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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
 
FORM 10-Q
(Mark One)
[X]QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 For the quarterly period endedMarch 31, 20162017
  
 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 NumberStates of Incorporation
I.R.S. Employer
Identification Nos.
Former name, former address and former fiscal year, if changed since last report
1-14201SEMPRA ENERGYCalifornia33-0732627No change
 
488 8th Avenue
   
 San Diego, California 92101   
 (619)696-2000   
     
1-03779SAN DIEGO GAS & ELECTRIC COMPANYCalifornia95-1184800No change
 8326 Century Park Court   
 San Diego, California 92123   
 (619)696-2000   
     
1-01402SOUTHERN CALIFORNIA GAS COMPANYCalifornia95-1240705No change
 555 West Fifth Street   
 Los Angeles, California 90013   
 (213)244-1200   
 
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 registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
 
 YesXNo 


Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, 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 registrant was required to submit and post such files).
 
Sempra EnergyYesXNo 
San Diego Gas & Electric CompanyYesXNo 
Southern California Gas CompanyYesXNo 
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer”filer,” “smaller reporting company,” and “smaller reporting“emerging growth company” in Rule 12b-2 of the Exchange Act.
 
Large
accelerated filer
Accelerated filerNon-accelerated filerSmaller reporting companyEmerging 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 EnergyYesNo
San Diego Gas & Electric CompanyYesNo
Southern California Gas CompanyYesNo
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
 
Sempra EnergyYesYes NoX
San Diego Gas & Electric CompanyYesYes NoX
Southern California Gas CompanyYesYes NoX
 
Indicate the number of shares outstanding of each of the issuers’ classes of common stock, as of the latest practicable date.
 
Common stock outstanding on April 28, 2016:May 3, 2017:
Sempra Energy249,496,738250,831,410 shares
San Diego Gas & Electric CompanyWholly owned by Enova Corporation, which is wholly owned by Sempra Energy
Southern California Gas CompanyWholly owned by Pacific Enterprises, which is wholly owned by Sempra Energy








SEMPRA ENERGY FORM 10-Q
SAN DIEGO GAS & ELECTRIC COMPANY FORM 10-Q
SOUTHERN CALIFORNIA GAS COMPANY FORM 10-Q
TABLE OF CONTENTS
 
Page
Information Regarding Forward-Looking Statements4 
 Page
Information Regarding Forward-Looking Statements
4
  
PART I – FINANCIAL INFORMATION 
Item 1.
Financial Statements
6
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
7471
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
109102
Item 4.
Controls and Procedures
110103
   
PART II – OTHER INFORMATION 
Item 1.
Legal Proceedings
111
104
Item 1A.
Risk Factors
111
104
Item 6.
Exhibits
111
104
   
Signatures
113
107


This combined Form 10-Q 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 Part I – Item 1 sections are provided for each reporting company, except for the Notes to Condensed Consolidated Financial Statements. The Notes to Condensed Consolidated Financial Statements for all of the reporting companies are combined. All Items other than Part I – Item 1 are combined for the reporting companies.

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 necessarily based upon assumptions with respect to the future, involve risks and uncertainties, and are not guarantees of performance. 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.factors.
In this report, when we use words such as “believes,” “expects,” “anticipates,” “plans,” “estimates,” “projects,” “forecasts,” “contemplates,” “intends,” “assumes,” “depends,” “should,” “could,” “would,” “will,” “confident,” “may,” “can,” “potential,” “possible,” “proposed,” “target,” “pursue,” “goals,” “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 forward-looking statements include
§  local, regional, national and international economic, competitive, political, legislative, legal and regulatory conditions, decisions and developments;
§  ▪
actions and the timing of actions, including general rate case decisions, new regulations, and issuances of permits to construct, operate, and maintain facilities and equipment and to use land, franchise agreements and licenses for operation,other authorizations by the California Public Utilities Commission, California State Legislature, U.S. Department of Energy, California Division of Oil, Gas, and Geothermal Resources, Federal Energy Regulatory Commission, Nuclear Regulatory Commission, California Energy Commission, U.S. Environmental Protection Agency, Pipeline and Hazardous Materials Safety Administration, California Air Resources Board, South Coast Air Quality Management District, Mexican Competition Commission,Los Angeles County Department of Public Health, states, cities and counties, and other regulatory governmental and environmentalgovernmental bodies in the United States and other countries in which we operate;operate;
§  
▪
the timing and success of business development efforts and construction maintenance and capital projects, including risks in obtaining or maintaining or extending permits licenses, certificates and other authorizations on a timely basis, risks in completing construction projects on schedule and on budget, and risks in obtaining adequatethe consent and competitive financing for such projects;participation of partners;
§  
▪
the resolution of civil and criminal litigation and regulatory investigations;investigations;
§  
▪
deviations from regulatory precedent or practice that result in a reallocation of benefits or burdens among shareholders and ratepayers,ratepayers; modifications of settlements; and delays in, or disallowance or denial of, regulatory agency authorizationauthorizations to recover costs in rates from customers;customers (including with respect to regulatory assets associated with the San Onofre Nuclear Generating Station facility and 2007 wildfires) or regulatory agency approval for projects required to enhance safety and reliability;
§  
▪
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 North American transmission grid, moratoriums on the ability to withdrawwithdrawal or injection of natural gas from or inject natural gas into storage facilities, pipeline explosions and equipment failures;failures;
§  
▪
changes in energy markets; the timing and extent of changes and volatility in commodity prices; moves to reduce or eliminate reliance on natural gas; and the impact on the value of our investment in natural gas storage and related assets and our investments from low natural gas prices, low volatility of natural gas prices and the inability to procure favorable long-term contracts for natural gas storage services;services;
§  
▪
risks posed by decisions and actions of third parties who control the operations of our investments, in which we do not have a controlling interest, and risks that our partners or counterparties will be unable (due to liquidity issues, bankruptcy or otherwise) or unwilling to fulfill their contractual commitments;commitments;
§  capital markets
▪
weather conditions, includingnatural disasters, accidents, equipment failures, computer system outages, explosions, terrorist attacks and other events that disrupt our operations, damage our facilities and systems, cause the availabilityrelease of creditgreenhouse gases, radioactive materials and the liquidityharmful emissions, cause wildfires and subject us to third-party liability for property damage or personal injuries, fines and penalties, some of our investments, and inflation, interest and currency exchange rates;which may not be covered by insurance (including costs in excess of applicable policy limits) or may be disputed by insurers;
§  
▪
cybersecurity threats to the energy grid, natural gas 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; terrorist attacksemployees;
▪
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;
▪changes in the tax code as a result of potential federal tax reform, such as the elimination of the deduction for interest and non-deductibility of all, or a portion of, the cost of imported materials, equipment and commodities;
▪changes in foreign and domestic trade policies and laws, including border tariffs, revisions to favorable international trade agreements, and changes that threaten system operations and critical infrastructure; and wars;make our exports less competitive or otherwise restrict our ability to export;
§  
▪
the ability to win competitively bid infrastructure projects against a number of strong and aggressive competitors willing to aggressively bid for these projects;;
§  weather conditions, natural disasters, catastrophic accidents, equipment failures and other events that may disrupt our operations, damage our facilities and systems, cause the release of greenhouse gasses, radioactive materials and harmful emissions, 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 or may be disputed by insurers;
§  ▪disallowance of regulatory assets associated with, or decommissioning costs of, the San Onofre Nuclear Generating Station facility due to increased regulatory oversight, including motions to modify settlements;
§  expropriation of assets by foreign governments and title and other property disputes;disputes;
§  
▪
the impact on reliability of San Diego Gas & Electric Company’s (SDG&E) electric transmission and distribution system due to increased amount and variability of power supply from renewable energy sources and increased reliance on natural gas and natural gas transmission systems;;
§  
▪
the impact on competitive customer rates ofdue 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;system and from possible departing retail load resulting from customers transferring to Direct Access and Community Choice Aggregation; and

§  the inability or determination not to enter into long-term supply and sales agreements or long-term firm capacity agreements due to insufficient market interest, unattractive pricing or other factors; and
§  ▪
other uncertainties, allsome of which aremay be difficult to predict and many of which are beyond our control.
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 in our most recent Annual Report on Form 10-K and other reports that we file with the Securities and Exchange Commission.

PART I – FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS



SEMPRA ENERGY    
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS    
(Dollars in millions, except per share amounts)    
  Three months ended March 31,
  20162015
  (unaudited)
REVENUES    
Utilities$2,442$2,422
Energy-related businesses 180 260
    Total revenues 2,622 2,682
EXPENSES AND OTHER INCOME    
Utilities:    
    Cost of natural gas (311) (346)
    Cost of electric fuel and purchased power (515) (481)
Energy-related businesses:    
    Cost of natural gas, electric fuel and purchased power (56) (98)
    Other cost of sales (35) (35)
Operation and maintenance (701) (658)
Depreciation and amortization (328) (303)
Franchise fees and other taxes (111) (107)
Plant closure adjustment ― 21
Equity (losses) earnings, before income tax (22) 19
Other income, net 49 39
Interest income 6 7
Interest expense (143) (134)
Income before income taxes and equity earnings    
    of certain unconsolidated subsidiaries 455 606
Income tax expense (142) (163)
Equity earnings, net of income tax 17 15
Net income 330 458
Earnings attributable to noncontrolling interests (11) (21)
Earnings$319$437
      
Basic earnings per common share$1.28$1.76
      
Weighted-average number of shares outstanding, basic (thousands) 249,734 247,722
      
Diluted earnings per common share$1.27$1.74
      
Weighted-average number of shares outstanding, diluted (thousands) 251,412 251,206
      
Dividends declared per share of common stock$0.76$0.70
See Notes to Condensed Consolidated Financial Statements.


SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
  Three months ended March 31, 2016 and 2015
  (unaudited)
  Sempra Energy shareholders' equity    
  PretaxIncome taxNet-of-taxNoncontrolling 
  amount(expense) benefitamountinterests (after-tax)Total
2016:          
Net income$461$(142)$319$11$330
Other comprehensive income (loss):          
    Foreign currency translation adjustments 68 ― 68 5 73
    Financial instruments (159) 75 (84) (5) (89)
    Pension and other postretirement benefits 2 (1) 1 ― 1
    Total other comprehensive loss (89) 74 (15) ― (15)
Comprehensive income$372$(68)$304$11$315
2015:          
Net income$600$(163)$437$21$458
Other comprehensive income (loss):          
    Foreign currency translation adjustments (62) ― (62) (8) (70)
    Financial instruments (89) 34 (55) (5) (60)
    Pension and other postretirement benefits 2 (1) 1 ― 1
    Total other comprehensive loss (149) 33 (116) (13) (129)
Comprehensive income$451$(130)$321$8$329
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
  March 31,December 31,
 20162015(1)
  (unaudited)  
ASSETS    
Current assets:    
    Cash and cash equivalents$376$403
    Restricted cash 23 27
    Accounts receivable – trade, net 1,100 1,283
    Accounts receivable – other 177 190
    Due from unconsolidated affiliates 7 6
    Income taxes receivable 49 30
    Inventories 231 298
    Regulatory balancing accounts – undercollected 256 307
    Fixed-price contracts and other derivatives 88 80
    Assets held for sale, power plant 303 ―
    Other 273 267
        Total current assets 2,883 2,891
      
Other assets:    
    Restricted cash 20 20
    Due from unconsolidated affiliates 186 186
    Regulatory assets 3,336 3,273
    Nuclear decommissioning trusts 1,082 1,063
    Investments 2,727 2,905
    Goodwill 849 819
    Other intangible assets 402 404
    Dedicated assets in support of certain benefit plans 432 464
    Insurance receivable for Aliso Canyon costs 660 325
    Sundry 825 761
        Total other assets 10,519 10,220
      
Property, plant and equipment:    
    Property, plant and equipment 38,541 38,200
    Less accumulated depreciation and amortization (10,108) (10,161)
        Property, plant and equipment, net ($376 and $383 at March 31, 2016 and
            December 31, 2015, respectively, related to VIE)
 28,433 28,039
Total assets$41,835$41,150
(1)Derived from audited financial statements.    
See Notes to Condensed Consolidated Financial Statements.    
SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
  March 31,December 31,
 20162015(1)
  (unaudited)  
LIABILITIES AND EQUITY    
Current liabilities:    
    Short-term debt$1,177$622
    Accounts payable – trade 1,028 1,133
    Accounts payable – other 129 142
    Due to unconsolidated affiliates 13 14
    Dividends and interest payable 360 303
    Accrued compensation and benefits 259 423
    Regulatory balancing accounts – overcollected 45 34
    Current portion of long-term debt 1,066 907
    Fixed-price contracts and other derivatives 57 56
    Customer deposits 147 153
    Reserve for Aliso Canyon costs 302 274
    Other 549 551
        Total current liabilities 5,132 4,612
Long-term debt ($300 and $303 at March 31, 2016 and December 31, 2015, respectively,
     related to VIE)
 12,975 13,134
      
Deferred credits and other liabilities:    
    Customer advances for construction 148 149
    Pension and other postretirement benefit plan obligations, net of plan assets 1,165 1,152
    Deferred income taxes 3,222 3,157
    Deferred investment tax credits 32 32
    Regulatory liabilities arising from removal obligations 2,850 2,793
    Asset retirement obligations 2,151 2,126
    Fixed-price contracts and other derivatives 248 240
    Deferred credits and other 1,188 1,176
        Total deferred credits and other liabilities 11,004 10,825
      
Commitments and contingencies (Note 11)    
      
Equity:    
    Preferred stock (50 million shares authorized; none issued) ― ―
    Common stock (750 million shares authorized; 249 million and 248 million shares    
        outstanding at March 31, 2016 and December 31, 2015, respectively; no par value) 2,642 2,621
    Retained earnings 10,125 9,994
    Accumulated other comprehensive income (loss) (821) (806)
        Total Sempra Energy shareholders’ equity 11,946 11,809
    Preferred stock of subsidiary 20 20
    Other noncontrolling interests 758 750
        Total equity 12,724 12,579
Total liabilities and equity$41,835$41,150
(1)Derived from audited financial statements.    
See Notes to Condensed Consolidated Financial Statements.    
SEMPRA ENERGY   
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions, except per share amounts)   
 Three months ended March 31,
 2017 2016(1)
 (unaudited)
REVENUES   
Utilities$2,698
 $2,442
Energy-related businesses333
 180
Total revenues3,031
 2,622
    
EXPENSES AND OTHER INCOME   
Utilities:   
Cost of electric fuel and purchased power(527) (515)
Cost of natural gas(485) (311)
Energy-related businesses:   
Cost of natural gas, electric fuel and purchased power(67) (56)
Other cost of sales(22) (35)
Operation and maintenance(714) (701)
Depreciation and amortization(360) (328)
Franchise fees and other taxes(110) (111)
Equity earnings (losses), before income tax3
 (22)
Other income, net169
 49
Interest income6
 6
Interest expense(169) (143)
Income before income taxes and equity (losses) earnings
of certain unconsolidated subsidiaries
755
 455
Income tax expense(295) (108)
Equity (losses) earnings, net of income tax(8) 17
Net income452
 364
Earnings attributable to noncontrolling interests(11) (11)
Earnings$441
 $353
    
    
Basic earnings per common share$1.76
 $1.41
Weighted-average number of shares outstanding, basic (thousands)251,131
 249,734
    
Diluted earnings per common share$1.75
 $1.40
Weighted-average number of shares outstanding, diluted (thousands)252,246
 251,487
    
Dividends declared per share of common stock$0.82
 $0.76
(1)As adjusted for the adoption of ASU 2016-09 as of January 1, 2016.
See Notes to Condensed Consolidated Financial Statements.


SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
  Three months ended March 31,
  20162015
  (unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES    
    Net income$330$458
    Adjustments to reconcile net income to net cash provided by operating activities:    
        Depreciation and amortization 328 303
        Deferred income taxes and investment tax credits 112 131
        Plant closure adjustment ― (21)
        Equity losses (earnings) 5 (34)
        Fixed-price contracts and other derivatives 4 11
        Other 2 (27)
    Net change in other working capital components 165 19
    Insurance receivable for Aliso Canyon costs (335) ―
    Changes in other assets (29) (42)
    Changes in other liabilities 10 13
        Net cash provided by operating activities 592 811
      
CASH FLOWS FROM INVESTING ACTIVITIES    
    Expenditures for property, plant and equipment (971) (780)
    Expenditures for investments and acquisition of business (30) (34)
    Distributions from investments 9 1
    Purchases of nuclear decommissioning and other trust assets (94) (95)
    Proceeds from sales by nuclear decommissioning and other trusts 93 94
    Increases in restricted cash (16) (18)
    Decreases in restricted cash 20 25
    Advances to unconsolidated affiliates (6) (5)
    Repayments of advances to unconsolidated affiliates 9 33
    Other (3) 9
        Net cash used in investing activities (989) (770)
      
CASH FLOWS FROM FINANCING ACTIVITIES    
    Common dividends paid (161) (149)
    Issuances of common stock 15 17
    Repurchases of common stock (54) (65)
    Issuances of debt (maturities greater than 90 days) 55 938
    Payments on debt (maturities greater than 90 days) (54) (654)
    Increase (decrease) in short-term debt, net 531 (363)
    Tax benefit related to share-based compensation 34 52
    Other (2) (7)
        Net cash provided by (used in) financing activities 364 (231)
     
Effect of exchange rate changes on cash and cash equivalents 6 (3)
      
Decrease in cash and cash equivalents (27) (193)
Cash and cash equivalents, January 1 403 570
Cash and cash equivalents, March 31$376$377
See Notes to Condensed Consolidated Financial Statements.    

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
(Dollars in millions)
  Three months ended March 31,
 20162015
 (unaudited)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION    
    Interest payments, net of amounts capitalized$97$83
    Income tax payments, net of refunds 41 42
      
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES    
    Acquisition of business:    
          Assets acquired$―$10
          Liabilities assumed ― (2)
          Accrued purchase price ― (6)
          Cash paid$―$2
      
    Accrued capital expenditures$423   $272
    Financing of build-to-suit property ― 27
    Common dividends issued in stock 13 13
    Dividends declared but not paid 197 181
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
 Three months ended March 31,
 20162015
 (unaudited)
Operating revenues    
    Electric$843$805
    Natural gas 148 161
        Total operating revenues 991 966
Operating expenses    
    Cost of electric fuel and purchased power 248 228
    Cost of natural gas 39 54
    Operation and maintenance 246 217
    Depreciation and amortization 159 145
    Franchise fees and other taxes 63 61
    Plant closure adjustment ― (21)
        Total operating expenses 755 684
Operating income 236 282
Other income, net 14 9
Interest expense (48) (52)
Income before income taxes 202 239
Income tax expense (72) (88)
Net income 130 151
Earnings attributable to noncontrolling interest (1) (4)
Earnings attributable to common shares$129$147
See Notes to Condensed Consolidated Financial Statements.
SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
 Sempra Energy shareholders’ equity    
 Pretax
amount		 Income tax
(expense) benefit		 Net-of-tax
amount		 
Noncontrolling
interests
(after-tax)
 Total
 Three months ended March 31, 2017 and 2016
 (unaudited)
2017:         
Net income$736
 $(295) $441
 $11
 $452
Other comprehensive income (loss):         
Foreign currency translation adjustments46
 —
 46
 9
 55
Financial instruments7
 (3) 4
 2
 6
Pension and other postretirement benefits3
 (1) 2
 —
 2
Total other comprehensive income56
 (4) 52
 11
 63
Comprehensive income$792
 $(299) $493
 $22
 $515
2016(1):         
Net income$461
 $(108) $353
 $11
 $364
Other comprehensive income (loss):         
Foreign currency translation adjustments68
 —
 68
 5
 73
Financial instruments(159) 75
 (84) (5) (89)
Pension and other postretirement benefits2
 (1) 1
 —
 1
Total other comprehensive loss(89) 74
 (15) —
 (15)
Comprehensive income$372
 $(34) $338
 $11
 $349
(1)As adjusted for the adoption of ASU 2016-09 as of January 1, 2016.
See Notes to Condensed Consolidated Financial Statements.


SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
 Three months ended March 31, 2016 and 2015
 (unaudited)
 SDG&E shareholder's equity  
 PretaxIncome taxNet-of-taxNoncontrolling 
 amountexpenseamountinterest (after-tax)Total
2016:          
Net income$201$(72)$129$1$130
Other comprehensive income (loss):          
    Financial instruments ― ― ― (2) (2)
    Total other comprehensive loss ― ― ― (2) (2)
Comprehensive income (loss)$201$(72)$129$(1)$128
2015:          
Net income$235$(88)$147$4$151
Other comprehensive income (loss):          
    Financial instruments ― ― ― (2) (2)
    Total other comprehensive loss ― ― ― (2) (2)
Comprehensive income$235$(88)$147$2$149
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
  March 31,December 31,
  20162015(1)
  (unaudited)  
ASSETS    
Current assets:    
    Cash and cash equivalents$36$20
    Restricted cash 21 23
    Accounts receivable – trade, net 300 331
    Accounts receivable – other 18 17
    Due from unconsolidated affiliates 1 1
    Inventories 72 75
    Regulatory balancing accounts – net undercollected 256 307
    Regulatory assets 119 107
    Fixed-price contracts and other derivatives 50 53
    Other 64 70
        Total current assets 937 1,004
      
Other assets:    
    Restricted cash 2 ―
    Deferred taxes recoverable in rates 921 914
    Other regulatory assets 968 977
    Nuclear decommissioning trusts 1,082 1,063
    Sundry 331 301
        Total other assets 3,304 3,255
      
Property, plant and equipment:    
    Property, plant and equipment 16,668 16,458
    Less accumulated depreciation and amortization (4,284) (4,202)
        Property, plant and equipment, net ($376 and $383 at March 31, 2016 and
            December 31, 2015, respectively, related to VIE)
 12,384 12,256
Total assets$16,625$16,515
(1)Derived from audited financial statements.    
See Notes to Condensed Consolidated Financial Statements.    

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
  March 31,December 31,
  20162015(1)
  (unaudited)  
LIABILITIES AND EQUITY    
Current liabilities:    
    Short-term debt$166$168
    Accounts payable 295 377
    Due to unconsolidated affiliates 49 55
    Income taxes payable 59 ―
    Interest payable 39 39
    Accrued compensation and benefits 67 129
    Accrued franchise fees 46 66
    Current portion of long-term debt 191 50
    Asset retirement obligations 63 99
    Fixed-price contracts and other derivatives 53 51
    Customer deposits 71 72
    Other 130 101
        Total current liabilities 1,229 1,207
Long-term debt ($300 and $303 at March 31, 2016 and December 31, 2015,
    respectively, related to VIE)
 4,294 4,455
      
Deferred credits and other liabilities:    
    Customer advances for construction 44 46
    Pension and other postretirement benefit plan obligations, net of plan assets 216 212
    Deferred income taxes 2,497 2,472
    Deferred investment tax credits 20 19
    Regulatory liabilities arising from removal obligations 1,692 1,629
    Asset retirement obligations 745 729
    Fixed-price contracts and other derivatives 107 106
    Deferred credits and other 378 364
        Total deferred credits and other liabilities 5,699 5,577
      
Commitments and contingencies (Note 11)    
      
Equity:    
    Common stock (255 million shares authorized; 117 million shares outstanding;    
        no par value) 1,338 1,338
    Retained earnings 4,022 3,893
    Accumulated other comprehensive income (loss) (8) (8)
        Total SDG&E shareholder's equity5,352 5,223
    Noncontrolling interest 51 53
        Total equity 5,403 5,276
Total liabilities and equity$16,625$16,515
(1)Derived from audited financial statements.    
See Notes to Condensed Consolidated Financial Statements.    
SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
 March 31,
2017		 December 31,
2016(1)
 (unaudited)  
ASSETS   
Current assets:   
Cash and cash equivalents$290
 $349
Restricted cash72
 66
Accounts receivable – trade, net1,267
 1,390
Accounts receivable – other, net201
 164
Due from unconsolidated affiliates24
 26
Income taxes receivable65
 43
Inventories210
 258
Regulatory balancing accounts – undercollected202
 259
Fixed-price contracts and other derivatives161
 83
Assets held for sale196
 201
Other265
 271
Total current assets2,953
 3,110
    
Other assets:   
Restricted cash5
 10
Due from unconsolidated affiliates187
 201
Regulatory assets3,503
 3,414
Nuclear decommissioning trusts1,062
 1,026
Investments2,120
 2,097
Goodwill2,380
 2,364
Other intangible assets544
 548
Dedicated assets in support of certain benefit plans412
 430
Insurance receivable for Aliso Canyon costs621
 606
Deferred income taxes188
 234
Sundry817
 815
Total other assets11,839
 11,745
    
Property, plant and equipment:   
Property, plant and equipment44,404
 43,624
Less accumulated depreciation and amortization(10,912) (10,693)
Property, plant and equipment, net ($342 and $354 at March 31, 2017 and
December 31, 2016, respectively, related to VIE)
33,492
 32,931
Total assets$48,284
 $47,786
(1)Derived from audited financial statements.


SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
 Three months ended March 31,
 20162015
 (unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES    
    Net income$130$151
    Adjustments to reconcile net income to net cash provided by operating activities:    
        Depreciation and amortization 159 145
        Deferred income taxes and investment tax credits 20 56
        Plant closure adjustment ― (21)
        Fixed-price contracts and other derivatives (1) (1)
        Other (9) (1)
    Net change in other working capital components 103 7
    Changes in other assets (34) (48)
    Changes in other liabilities 1 11
        Net cash provided by operating activities 369 299
     
CASH FLOWS FROM INVESTING ACTIVITIES    
    Expenditures for property, plant and equipment (329) (355)
    Purchases of nuclear decommissioning trust assets (93) (94)
    Proceeds from sales by nuclear decommissioning trusts 93 94
    Increases in restricted cash (10) (10)
    Decreases in restricted cash 10 10
    Increase in loans to affiliates, net ― (66)
    Other (1) ―
        Net cash used in investing activities (330) (421)
     
CASH FLOWS FROM FINANCING ACTIVITIES    
    Issuances of debt (maturities greater than 90 days) ― 388
    Payments on debt (maturities greater than 90 days) (20) (3)
    Decrease in short-term debt, net (2) (246)
    Capital distributions made by Otay Mesa VIE (1) (2)
        Net cash (used in) provided by financing activities (23) 137
     
Increase in cash and cash equivalents 16 15
Cash and cash equivalents, January 1 20 8
Cash and cash equivalents, March 31$36$23
     
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION    
    Interest payments, net of amounts capitalized$46$39
    Income tax (refunds) payments, net (8) 31
     
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITY    
    Accrued capital expenditures$104$103
See Notes to Condensed Consolidated Financial Statements.
SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
 Three months ended March 31,
 20162015
 (unaudited)
     
Operating revenues$1,033$1,048
Operating expenses    
    Cost of natural gas 253 267
    Operation and maintenance 327 314
    Depreciation and amortization 122 113
    Franchise fees and other taxes 37 34
        Total operating expenses 739 728
Operating income 294 320
Other income, net 10 8
Interest expense (22) (19)
Income before income taxes 282 309
Income tax expense (87) (95)
Net income/Earnings attributable to common shares$195$214
See Notes to Condensed Consolidated Financial Statements.


SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
 Three months ended March 31, 2016 and 2015
 (unaudited)
 PretaxIncome taxNet-of-tax
 amountexpenseamount
2016:      
Net income/Comprehensive income$282$(87)$195
2015:      
Net income/Comprehensive income$309$(95)$214
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
  March 31,December 31,
  20162015(1)
  (unaudited)  
ASSETS    
Current assets:    
    Cash and cash equivalents$14$58
    Accounts receivable – trade, net 445 635
    Accounts receivable – other 99 99
    Due from unconsolidated affiliates 8 48
    Inventories 33 79
    Regulatory assets 8 7
    Other 44 40
        Total current assets 651 966
     
Other assets:    
    Regulatory assets arising from pension obligations 715 699
    Other regulatory assets 686 636
    Insurance receivable for Aliso Canyon costs 660 325
    Sundry 252 207
        Total other assets 2,313 1,867
     
Property, plant and equipment:    
    Property, plant and equipment 14,359 14,171
    Less accumulated depreciation and amortization (4,896) (4,900)
        Property, plant and equipment, net 9,463 9,271
Total assets$12,427$12,104
(1)Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
  March 31,December 31,
  20162015(1)
  (unaudited)  
LIABILITIES AND SHAREHOLDERS’ EQUITY    
Current liabilities:    
    Short-term debt$5$―
    Accounts payable – trade 351 422
    Accounts payable – other 77 76
    Due to unconsolidated affiliate 34 ―
    Income taxes payable 27 3
    Accrued compensation and benefits 110 160
    Regulatory balancing accounts – net overcollected 45 34
    Current portion of long-term debt 9 9
    Customer deposits 70 76
    Reserve for Aliso Canyon costs 302 274
    Other 193 184
        Total current liabilities 1,223 1,238
Long-term debt 2,481 2,481
Deferred credits and other liabilities:    
    Customer advances for construction 104 103
    Pension obligation, net of plan assets 733 716
    Deferred income taxes 1,643 1,532
    Deferred investment tax credits 13 14
    Regulatory liabilities arising from removal obligations 1,139 1,145
    Asset retirement obligations 1,367 1,354
    Deferred credits and other 380 372
        Total deferred credits and other liabilities 5,379 5,236
     
Commitments and contingencies (Note 11)    
     
Shareholders' equity:    
    Preferred stock 22 22
    Common stock (100 million shares authorized; 91 million shares outstanding;    
        no par value) 866 866
    Retained earnings 2,475 2,280
    Accumulated other comprehensive income (loss) (19) (19)
        Total shareholders’ equity 3,344 3,149
Total liabilities and shareholders’ equity$12,427$12,104
(1)Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
 Three months ended March 31,
 20162015
 (unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES    
    Net income$195$214
    Adjustments to reconcile net income to net cash provided by operating activities:    
        Depreciation and amortization 122 113
        Deferred income taxes and investment tax credits 59 (9)
        Other (7) (6)
    Net change in other working capital components 243 85
    Insurance receivable for Aliso Canyon costs (335) ―
    Changes in other assets (37) (19)
    Changes in other liabilities 1 (3)
        Net cash provided by operating activities 241 375
     
CASH FLOWS FROM INVESTING ACTIVITIES    
    Expenditures for property, plant and equipment (340) (315)
    Decrease (increase) in loans to affiliate, net 50 (74)
        Net cash used in investing activities (290) (389)
     
CASH FLOWS FROM FINANCING ACTIVITY    
    Increase (decrease) in short-term debt, net 5 (50)
        Net cash provided by (used in) financing activity 5 (50)
     
Decrease in cash and cash equivalents (44) (64)
Cash and cash equivalents, January 1 58 85
Cash and cash equivalents, March 31$14$21
     
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION    
    Interest payments, net of amounts capitalized$17$17
    Income tax payments (refunds), net 3 (3)
     
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITY    
    Accrued capital expenditures$148$129
See Notes to Condensed Consolidated Financial Statements.
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)
(Dollars in millions)   
 March 31,
2017		 December 31,
2016(1)
 (unaudited)  
LIABILITIES AND EQUITY   
Current liabilities:   
Short-term debt$2,054
 $1,779
Accounts payable – trade969
 1,346
Accounts payable – other123
 130
Due to unconsolidated affiliates13
 11
Dividends and interest payable382
 319
Accrued compensation and benefits239
 409
Regulatory balancing accounts – overcollected189
 122
Current portion of long-term debt839
 913
Fixed-price contracts and other derivatives115
 83
Customer deposits160
 158
Reserve for Aliso Canyon costs49
 53
Liabilities held for sale40
 47
Other640
 557
Total current liabilities5,812
 5,927
    
Long-term debt ($291 and $293 at March 31, 2017 and December 31, 2016, respectively,
related to VIE)
14,409
 14,429
    
Deferred credits and other liabilities:   
Customer advances for construction145
 152
Pension and other postretirement benefit plan obligations, net of plan assets1,212
 1,208
Deferred income taxes4,025
 3,745
Deferred investment tax credits26
 28
Regulatory liabilities arising from removal obligations2,761
 2,697
Asset retirement obligations2,455
 2,431
Fixed-price contracts and other derivatives343
 405
Deferred credits and other1,527
 1,523
Total deferred credits and other liabilities12,494
 12,189
    
Commitments and contingencies (Note 11)


 


    
Equity:   
Preferred stock (50 million shares authorized; none issued)—
 —
Common stock (750 million shares authorized; 251 million and 250 million shares
outstanding at March 31, 2017 and December 31, 2016, respectively; no par value)
3,008
 2,982
Retained earnings10,952
 10,717
Accumulated other comprehensive income (loss)(696) (748)
Total Sempra Energy shareholders’ equity13,264
 12,951
Preferred stock of subsidiary20
 20
Other noncontrolling interests2,285
 2,270
Total equity15,569
 15,241
Total liabilities and equity$48,284
 $47,786
(1)Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
 Three months ended March 31,
 2017 2016(1)
 (unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES   
Net income$452
 $364
Adjustments to reconcile net income to net cash provided by operating activities:   
Depreciation and amortization360
 328
Deferred income taxes and investment tax credits268
 78
Equity losses5
 5
Fixed-price contracts and other derivatives(106) 4
Other(22) 36
Net change in other working capital components84
 165
Insurance receivable for Aliso Canyon costs(15) (335)
Changes in other assets(41) (29)
Changes in other liabilities19
 10
Net cash provided by operating activities1,004
 626
    
CASH FLOWS FROM INVESTING ACTIVITIES   
Expenditures for property, plant and equipment(992) (971)
Expenditures for investments(59) (30)
Distributions from investments17
 9
Purchases of nuclear decommissioning and other trust assets(350) (94)
Proceeds from sales by nuclear decommissioning and other trusts357
 93
Increases in restricted cash(93) (16)
Decreases in restricted cash93
 20
Advances to unconsolidated affiliates(5) (6)
Repayments of advances to unconsolidated affiliates2
 9
Other4
 (3)
Net cash used in investing activities(1,026) (989)
    
CASH FLOWS FROM FINANCING ACTIVITIES   
Common dividends paid(176) (161)
Issuances of common stock17
 15
Repurchases of common stock(14) (54)
Issuances of debt (maturities greater than 90 days)542
 55
Payments on debt (maturities greater than 90 days)(313) (54)
(Decrease) increase in short-term debt, net(97) 531
Other(5) (2)
Net cash (used in) provided by financing activities(46) 330
    
Effect of exchange rate changes on cash and cash equivalents9
 6
    
Decrease in cash and cash equivalents(59) (27)
Cash and cash equivalents, January 1349
 403
Cash and cash equivalents, March 31$290
 $376
(1)As adjusted for the adoption of ASU 2016-09 as of January 1, 2016.
See Notes to Condensed Consolidated Financial Statements.

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (CONTINUED)
(Dollars in millions)
 Three months ended March 31,
 2017 2016(1)
 (unaudited)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION   
Interest payments, net of amounts capitalized$106
 $97
Income tax payments, net of refunds47
 41
    
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING AND FINANCING ACTIVITIES   
Accrued capital expenditures$378
 $423
Equitization of note receivable due from unconsolidated affiliate19
 —
Common dividends issued in stock13
 13
Dividends declared but not paid216
 197
(1)As adjusted for the adoption of ASU 2016-09 as of January 1, 2016.
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
 Three months ended March 31,
 2017 2016(1)
 (unaudited)
Operating revenues   
Electric$875
 $843
Natural gas182
 148
Total operating revenues1,057
 991
Operating expenses   
Cost of electric fuel and purchased power261
 248
Cost of natural gas65
 39
Operation and maintenance227
 246
Depreciation and amortization163
 159
Franchise fees and other taxes63
 63
Total operating expenses779
 755
Operating income278
 236
Other income, net18
 14
Interest expense(49) (48)
Income before income taxes247
 202
Income tax expense(90) (65)
Net income157
 137
Earnings attributable to noncontrolling interest(2) (1)
Earnings attributable to common shares$155
 $136
(1)As adjusted for the adoption of ASU 2016-09 as of January 1, 2016.
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
 SDG&E shareholder’s equity    
 
Pretax
amount
 
Income tax
expense
 
Net-of-tax
amount
 
Noncontrolling
interest
(after-tax)
 Total
 Three months ended March 31, 2017 and 2016
 (unaudited)
2017:         
Net income$245
 $(90) $155
 $2
 $157
Other comprehensive income (loss):         
Financial instruments—
 —
 —
 3
 3
Total other comprehensive income—
 —
 —
 3
 3
Comprehensive income$245
 $(90) $155
 $5
 $160
2016(1):         
Net income$201
 $(65) $136
 $1
 $137
Other comprehensive income (loss):         
Financial instruments—
 —
 —
 (2) (2)
Total other comprehensive loss—
 —
 —
 (2) (2)
Comprehensive income (loss)$201
 $(65) $136
 $(1) $135
(1)As adjusted for the adoption of ASU 2016-09 as of January 1, 2016.
See Notes to Condensed Consolidated Financial Statements.



SAN DIEGO GAS & ELECTRIC COMPANY   
CONDENSED CONSOLIDATED BALANCE SHEETS   
(Dollars in millions)   
 March 31,
2017		 December 31,
2016(1)
 (unaudited)  
ASSETS   
Current assets:   
Cash and cash equivalents$18
 $8
Restricted cash13
 11
Accounts receivable – trade, net359
 354
Accounts receivable – other, net23
 17
Due from unconsolidated affiliates—
 4
Income taxes receivable85
 122
Inventories82
 80
Prepaid expenses46
 59
Regulatory balancing accounts – net undercollected202
 259
Regulatory assets99
 81
Fixed-price contracts and other derivatives39
 58
Other19
 19
Total current assets985
 1,072
    
Other assets:   
Restricted cash—
 1
Deferred income taxes recoverable in rates1,013
 1,014
Other regulatory assets1,018
 998
Nuclear decommissioning trusts1,062
 1,026
Sundry355
 358
Total other assets3,448
 3,397
    
Property, plant and equipment:   
Property, plant and equipment18,144
 17,844
Less accumulated depreciation and amortization(4,677) (4,594)
Property, plant and equipment, net ($342 and $354 at March 31, 2017 and
December 31, 2016, respectively, related to VIE)		13,467
 13,250
Total assets$17,900
 $17,719
(1)Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.

SAN DIEGO GAS & ELECTRIC COMPANY   
CONDENSED CONSOLIDATED BALANCE SHEETS (CONTINUED)   
(Dollars in millions)   
 March 31,
2017		 December 31,
2016(1)
 (unaudited)  
LIABILITIES AND EQUITY   
Current liabilities:   
Short-term debt$343
 $—
Accounts payable350
 460
Due to unconsolidated affiliates45
 15
Interest payable47
 40
Accrued compensation and benefits57
 121
Accrued franchise fees54
 43
Current portion of long-term debt51
 191
Asset retirement obligations79
 79
Fixed-price contracts and other derivatives65
 61
Customer deposits76
 76
Other93
 82
Total current liabilities1,260
 1,168
    
Long-term debt ($291 and $293 at March 31, 2017 and December 31, 2016,
respectively, related to VIE)		4,638
 4,658
    
Deferred credits and other liabilities:   
Customer advances for construction50
 52
Pension and other postretirement benefit plan obligations, net of plan assets238
 232
Deferred income taxes2,871
 2,829
Deferred investment tax credits15
 16
Regulatory liabilities arising from removal obligations1,790
 1,725
Asset retirement obligations762
 751
Fixed-price contracts and other derivatives197
 189
Deferred credits and other419
 421
Total deferred credits and other liabilities6,342
 6,215
    
Commitments and contingencies (Note 11)

 

    
Equity:   
Preferred stock (45 million shares authorized; none issued)—
 —
Common stock (255 million shares authorized; 117 million shares outstanding;
no par value)		1,338
 1,338
Retained earnings4,291
 4,311
Accumulated other comprehensive income (loss)(8) (8)
Total SDG&E shareholder’s equity5,621
 5,641
Noncontrolling interest39
 37
Total equity5,660
 5,678
Total liabilities and equity$17,900
 $17,719
(1)Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.


SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
 Three months ended March 31,
 2017 2016(1)
 (unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES   
Net income$157
 $137
Adjustments to reconcile net income to net cash provided by operating activities:   
Depreciation and amortization163
 159
Deferred income taxes and investment tax credits34
 13
Fixed-price contracts and other derivatives—
 (1)
Other(12) (9)
Net change in other working capital components84
 103
Changes in other assets(34) (34)
Changes in other liabilities(6) 1
Net cash provided by operating activities386
 369
    
CASH FLOWS FROM INVESTING ACTIVITIES   
Expenditures for property, plant and equipment(418) (329)
Purchases of nuclear decommissioning trust assets(350) (93)
Proceeds from sales by nuclear decommissioning trusts357
 93
Increases in restricted cash(10) (10)
Decreases in restricted cash9
 10
Decrease in loans to affiliate, net31
 —
Other—
 (1)
Net cash used in investing activities(381) (330)
    
CASH FLOWS FROM FINANCING ACTIVITIES   
Common dividends paid(175) —
Payments on debt (maturities greater than 90 days)(160) (20)
Increase (decrease) in short-term debt, net343
 (2)
Capital distributions made by VIE(3) (1)
Net cash provided by (used in) financing activities5
 (23)
    
Increase in cash and cash equivalents10
 16
Cash and cash equivalents, January 18
 20
Cash and cash equivalents, March 31$18
 $36
    
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION   
Interest payments, net of amounts capitalized$40
 $46
Income tax refunds, net—
 (8)
    
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITY   
Accrued capital expenditures$126
 $104
(1)As adjusted for the adoption of ASU 2016-09 as of January 1, 2016.
See Notes to Condensed Consolidated Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED STATEMENTS OF OPERATIONS
(Dollars in millions)
 Three months ended March 31,
 2017 2016(1)
 (unaudited)
    
Operating revenues$1,241
 $1,033
Operating expenses   
Cost of natural gas408
 253
Operation and maintenance353
 327
Depreciation and amortization126
 122
Franchise fees and other taxes39
 37
Total operating expenses926
 739
Operating income315
 294
Other income, net11
 10
Interest expense(25) (22)
Income before income taxes301
 282
Income tax expense(98) (83)
Net income/Earnings attributable to common shares$203
 $199
(1)As adjusted for the adoption of ASU 2016-09 as of January 1, 2016.
See Notes to Condensed Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
 Pretax
amount		 Income tax expense Net-of-tax
amount
 Three months ended March 31, 2017 and 2016
 (unaudited)
2017:     
Net income/Comprehensive income$301
 $(98) $203
2016(1):     
Net income/Comprehensive income$282
 $(83) $199
(1)As adjusted for the adoption of ASU 2016-09 as of January 1, 2016.
See Notes to Condensed Financial Statements.


SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED BALANCE SHEETS
(Dollars in millions)
 March 31,
2017		 December 31,
2016(1)
 (unaudited)  
ASSETS   
Current assets:   
Cash and cash equivalents$21
 $12
Accounts receivable – trade, net503
 608
Accounts receivable – other, net95
 77
Due from unconsolidated affiliates16
 8
Income taxes receivable—
 2
Inventories43
 58
Regulatory assets6
 8
Other52
 63
Total current assets736
 836
    
Other assets:   
Regulatory assets arising from pension obligations741
 742
Other regulatory assets661
 589
Insurance receivable for Aliso Canyon costs621
 606
Sundry400
 399
Total other assets2,423
 2,336
    
Property, plant and equipment:   
Property, plant and equipment15,599
 15,344
Less accumulated depreciation and amortization(5,156) (5,092)
Property, plant and equipment, net10,443
 10,252
Total assets$13,602
 $13,424
(1)Derived from audited financial statements.
See Notes to Condensed Financial Statements.

SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED BALANCE SHEETS (CONTINUED)
(Dollars in millions)
 March 31,
2017		 December 31,
2016(1)
 (unaudited)  
LIABILITIES AND SHAREHOLDERS’ EQUITY   
Current liabilities:   
Short-term debt$—
 $62
Accounts payable – trade330
 481
Accounts payable – other73
 74
Due to unconsolidated affiliates—
 28
Income taxes payable16
 —
Accrued compensation and benefits95
 150
Regulatory balancing accounts – net overcollected189
 122
Customer deposits77
 76
Reserve for Aliso Canyon costs49
 53
Other247
 195
Total current liabilities1,076
 1,241
    
Long-term debt2,983
 2,982
    
Deferred credits and other liabilities:   
Customer advances for construction96
 99
Pension obligation, net of plan assets761
 762
Deferred income taxes1,836
 1,709
Deferred investment tax credits11
 12
Regulatory liabilities arising from removal obligations971
 972
Asset retirement obligations1,628
 1,616
Deferred credits and other527
 521
Total deferred credits and other liabilities5,830
 5,691
    
Commitments and contingencies (Note 11)

 

    
Shareholders’ equity:   
Preferred stock (11 million shares authorized; 1 million shares outstanding)22
 22
Common stock (100 million shares authorized; 91 million shares outstanding;   
no par value)866
 866
Retained earnings2,847
 2,644
Accumulated other comprehensive income (loss)(22) (22)
Total shareholders’ equity3,713
 3,510
Total liabilities and shareholders’ equity$13,602
 $13,424
(1)Derived from audited financial statements.
See Notes to Condensed Financial Statements.



SOUTHERN CALIFORNIA GAS COMPANY
CONDENSED STATEMENTS OF CASH FLOWS
(Dollars in millions)
 Three months ended March 31,
 2017 2016(1)
 (unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES   
Net income$203
 $199
Adjustments to reconcile net income to net cash provided by operating activities:   
Depreciation and amortization126
 122
Deferred income taxes and investment tax credits80
 55
Other(5) (7)
Net change in other working capital components96
 243
Insurance receivable for Aliso Canyon costs(15) (335)
Changes in other assets(21) (37)
Changes in other liabilities(1) 1
Net cash provided by operating activities463
 241
    
CASH FLOWS FROM INVESTING ACTIVITIES   
Expenditures for property, plant and equipment(357) (340)
(Increase) decrease in loans to affiliate, net(35) 50
Net cash used in investing activities(392) (290)
    
CASH FLOWS FROM FINANCING ACTIVITY   
(Decrease) increase in short-term debt, net(62) 5
Net cash (used in) provided by financing activity(62) 5
    
Increase (decrease) in cash and cash equivalents9
 (44)
Cash and cash equivalents, January 112
 58
Cash and cash equivalents, March 31$21
 $14
    
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION   
Interest payments, net of amounts capitalized$16
 $17
Income tax payments, net—
 3
    
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITY   
Accrued capital expenditures$147
 $148
(1)As adjusted for the adoption of ASU 2016-09 as of January 1, 2016.
See Notes to Condensed Financial Statements.



SEMPRA ENERGY AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. GENERAL

PRINCIPLES OF CONSOLIDATION
Sempra Energy
Sempra Energy’s Condensed Consolidated Financial Statements include the accounts of Sempra Energy, a California-based Fortune 500 energy-services holding company, and its consolidated subsidiaries and variable interest entities (VIEs). Sempra Energy’s principal operating units are
§  
▪Sempra Utilities, which includes our San Diego Gas & Electric Company (SDG&E) and, Southern California Gas Company (SoCalGas), which are separate, and Sempra South American Utilities reportable segments; and
§  
▪Sempra International,Infrastructure, which includes our Sempra South American Utilities and Sempra Mexico, reportable segments; and
§  Sempra U.S. Gas & Power, which includes our Sempra Renewables and Sempra Natural GasLNG & Midstream reportable segments.
We provide descriptions of each of our segments in Note 12.
We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include our South American utilities or the utilities in our Sempra International and Sempra U.S. Gas & PowerInfrastructure operating units.unit. Sempra Global is the holding company for most of our subsidiaries that are not subject to California utility regulation. All references in these Notes to “Sempra International,Utilities,” “Sempra U.S. Gas & Power”Infrastructure” and their respective reportable segments are not intended to refer to any legal entity with the same or similar name.
Our Sempra Mexico segment includes the operating companies of our subsidiary, Infraestructura Energética Nova, S.A.B. de C.V. (IEnova), as well as certain holding companies and risk management activity. We discuss IEnova further in Note 1 of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2015 (the Annual Report), which includes the combined reports for Sempra Energy, SDG&E and SoCalGas.
Sempra Energy uses the equity method to account for investments in affiliated companies over which we have the ability to exercise significant influence, but not control. We discuss our investments in unconsolidated entities in Notes 3 and 4 herein and in Notes 3, 4 and 10 of the Notes to Consolidated Financial Statements in the Annual Report.
SDG&E
SDG&E’s Condensed Consolidated Financial Statements include its accounts and the accounts of a VIE of which SDG&E is the primary beneficiary, as we discuss in Note 5 under “Variable Interest Entities.” SDG&E’s common stock is wholly owned by Enova Corporation, which is a wholly owned subsidiary of Sempra Energy.
SoCalGas
SoCalGas’ Condensed Consolidated Financial Statements include its accounts and the de minimis accounts of inactive subsidiaries. SoCalGas’ common stock is wholly owned by Pacific Enterprises, which is a wholly owned subsidiary of Sempra Energy.

BASIS OF PRESENTATION

This is a combined report of Sempra Energy, SDG&E and SoCalGas. We provide separate information for SDG&E and SoCalGas as required. References in this report to “we,” “our” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, unless otherwise indicated by the context. We have eliminated intercompany accounts and transactions within the consolidated financial statements of each reporting entity.
Throughout this report, we refer to the following as Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements when discussed together or collectively:
▪the Condensed Consolidated Financial Statements and related Notes of Sempra Energy and its subsidiaries and VIEs;
▪the Condensed Consolidated Financial Statements and related Notes of SDG&E and its VIE; and
▪the Condensed Financial Statements and related Notes of SoCalGas.
We have prepared the Condensed Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP) and in accordance with the interim-period-reporting requirements of Form 10-Q. Results of operations for interim periods are not necessarily indicative of results for the entire year. We evaluated events and transactions that occurred after March 31, 20162017 through the date the financial statements were issued and, in the opinion of management, the accompanying statements reflect all adjustments necessary for a fair presentation. These adjustments are only of a normal, recurring nature.
All December 31, 20152016 balance sheet information in the Condensed Consolidated Financial Statements has been derived from our audited 20152016 Consolidated Financial Statements in the Annual Report.Report on Form 10-K for the year ended December 31, 2016 (Annual Report). Certain information and note disclosures normally included in annual financial statements prepared in accordance with U.S. GAAP have been condensed or omitted pursuant to the interim-period-reporting provisions of U.S. GAAP and the Securities and Exchange Commission.


We describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. We follow the same accounting policies for interim reporting purposes.
You should read the information in this Quarterly Report in conjunction with the Annual Report.


Regulated Operations
The California Utilities and Sempra Mexico’s natural gas distribution utility, Ecogas México, S. de R.L. de C.V. (Ecogas), prepare their financial statements in accordance with the provisions of U.S. GAAP governing rate-regulated operations. We discuss these provisions and revenue recognition at our utilities in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

Sempra South American Utilities has controlling interests in two electric distribution utilities in South America, Chilquinta Energía S.A. (Chilquinta Energía) in Chile and Luz del Sur S.A.A. (Luz del Sur) in Peru, and their subsidiaries. Sempra Natural Gas owns Mobile Gas Service Corporation (Mobile Gas)Revenues are based on tariffs that are set by government agencies in southwest Alabamatheir respective countries based on an efficient model distribution company defined by those agencies. Because the tariffs are based on a model and Willmut Gas Company (Willmut Gas)are intended to cover the costs of the model company, but are not based on the costs of the specific utility and may not result in Mississippi,full cost recovery, these utilities do not meet the requirements necessary for, and therefore do not apply, regulatory accounting treatment under U.S. GAAP.
Our Sempra Mexico owns Ecogas México, S. de R.L.segment includes the operating companies of our subsidiary, Infraestructura Energética Nova, S.A.B. de C.V. (Ecogas) in northern Mexico, all natural gas distribution utilities. The California Utilities, Mobile Gas, Willmut Gas, and Ecogas prepare their financial statements in accordance with U.S. GAAP provisions governing rate-regulated operations, as we discuss in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
Pipeline projects currently under construction by(IEnova). Certain business activities at IEnova that are both regulated by the Comisión Reguladora de Energía (or CRE, the Energy Regulatory Commission) and meet the regulatory accounting requirements of U.S. GAAP. Pipeline projects currently under construction by IEnova that meet the regulatory accounting requirements of U.S. GAAP record the impact of allowance for funds used during construction (AFUDC) related to equity. We discuss AFUDC in Note 5 below and in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
Sempra LNG & Midstream owned Mobile Gas Service Corporation (Mobile Gas) in southwest Alabama and Willmut Gas Company (Willmut Gas) in Mississippi until they were sold in September 2016, as we discuss in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report. Mobile Gas and Willmut Gas also prepared their financial statements in accordance with U.S. GAAP provisions governing rate-regulated operations.



NOTE 2. NEW ACCOUNTING STANDARDS

We describe below recent pronouncements that have had or may have a significant effect on our financial statements. We do not discuss recent pronouncements that are not anticipated to have an impact on or are unrelated to our financial condition, results of operations, cash flows or disclosures.


SEMPRA ENERGY, SDG&E AND SOCALGAS

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

ASU 2015-14 defers the effective date of ASU 2014-09 by one year for all entities and permits early adoption on a limited basis. For public entities, ASU 2014-09 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted for fiscal years beginning after December 15, 2016, and is effective for interim periods in the year of adoption. We will adopt ASU 2014-09 on January 1, 2018 using the modified retrospective transition method and are currently evaluating the effect of the standards on our ongoing financial reportingreporting. As part of our evaluation, we formed multiple working groups with oversight from a steering committee comprised of members from relevant Sempra Energy business units. We separated our various revenue streams into high-level categories, which served as the basis for accounting analysis and havedocumentation of the impact of ASU 2014-09 on our revenue recognition. The majority of Sempra Energy’s revenues result from electric and natural gas service to Sempra Utilities’ customers. For such tariff-based revenues, Sempra Energy does not yet selectedanticipate that the year in whichnew standard will materially impact the amount and timing of such revenues. However, we will adoptcontinue to actively monitor outstanding issues currently being addressed by the standards or our transition method.
American Institute of Certified Public


Accountants’ Revenue Recognition Working Group and the Financial Accounting Standards Board’s Transition Resource Group, since conclusions reached by these groups may impact our application of these ASUs.
ASU 2016-01, “Recognition and Measurement of Financial Assets and Financial Liabilities”: In addition to the presentation and disclosure requirements for financial instruments, ASU 2016-01 requires entities to measure equity investments, notother than those accounted for under the equity method, at fair value and recognize changes in fair value in net income. Entities will no longer be able to use the cost method of accounting for equity securities. However, for equity investments without readily determinable fair values, entities may elect a measurement alternative that will allow those investments to be recorded at cost, less impairment, and adjusted for subsequent observable price changes. Upon adoption, entities must record a cumulative-effect adjustment to the balance sheet as of the beginning of the first reporting period in which the standard is adopted. The guidance on equity securities without readily determinable fair valuevalues will be applied prospectively to all equity investments that exist as of the date of adoption of the standard.
For public entities, ASU 2016-01 is effective for fiscal years beginning after December 15, 2017. We will adopt ASU 2016-01 on January 1, 2018 as required and do not expect it to materially affect our financial condition, results of operations or cash flows. We will make the required changes to our disclosures upon adoption.
ASU 2016-02, “Leases”: ASU 2016-02 requires entities to include substantially all leases on the balance sheet by requiring the recognition of right-of-use assets and lease liabilities for all leases. Entities may elect to exclude from the balance sheet those leases with a maximum possible term of less than 12 months. For lessees, a lease is classified as finance or operating, and the asset and liability are initially measured at the present value of the lease payments. For lessors, accounting for leases is largely unchanged from previous provisions of U.S. GAAP, other than certain changes to align lessor accounting to specific changes made to lessee accounting and ASU 2014-09. ASU 2016-02 also requires new qualitative disclosures along with specificand quantitative disclosures for both lessees and lessors.

For public entities, ASU 2016-02 is effective for fiscal years beginning after December 15, 2018, with early adoption permitted, and is effective for interim periods in the year of adoption. The standard requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The modified retrospective approach includes optional practical expedients that may be elected, which would allow entities to continue to account for leases that commence before the effective date of the standard in accordance with previous U.S. GAAP unless the lease is modified, except for the lessee requirement to recognizebegin recognizing right-of-use assets and lease liabilities for all operating leases on the balance sheet at the reporting date. We are currently evaluating the effect of the standard on our ongoing financial reporting and have not yet selected the year in which we will adopt the standard. As part of our evaluation, we formed a steering committee comprised of members from relevant Sempra Energy business units and are compiling our population of contracts. Based on our assessment to date, we have determined that we will elect the practical expedients available under the transition guidance.
ASU 2016-05, “Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships”: ASU 2016-05 provides clarification that a change in the counterparty to a derivative instrument that has been designated as a hedging instrument does not, in and of itself, require dedesignation of that hedging relationship provided that all other hedge accounting criteria continue to be met. ASU 2016-05 may be adopted prospectively or using a modified retrospective approach. We prospectively adopted ASU 2016-05 on January 1, 2016 and it did not affect our financial condition, results of operations or cash flows.
ASU 2016-09, “Improvements to Employee Share-Based Payment Accounting”:ASU 2016-09 is intended to simplify several aspects of the accounting for employee share-based payment transactions. Under ASU 2016-09, excess tax benefits and tax deficiencies are required to be recorded in earnings, and the requirement to reclassify excess tax benefits and deficiencies from operating to financing activities on the statement of cash flows has been eliminated. ASU 2016-09 also allows entities to withhold taxes up to the maximum individual statutory tax rate without resulting in liability classification of the award and clarifies that cash payments made to taxing authorities in connection with withheld shares should be classified as financing activities in the statement of cash flows. Additionally,
We early adopted the provisions of ASU 2016-09 during the three months ended September 30, 2016, with an effective date of January 1, 2016. The following financial statement line items for the three months ended March 31, 2016 were affected by the change in accounting principle:


IMPACT FROM ADOPTION OF ASU 2016-09
(Dollars in millions, except per share amounts)
 Three months ended March 31, 2016
 As previously reported Effect of adoption As adjusted
Sempra Energy Consolidated:     
Condensed Consolidated Statement of Operations:     
Income tax expense$(142) $34
 $(108)
Net income330
 34
 364
Earnings319
 34
 353
      
Basic earnings per common share$1.28
 $0.13
 $1.41
Diluted earnings per common share$1.27
 $0.13
 $1.40
Weighted-average number of shares outstanding, diluted (thousands)251,412
 75
 251,487
      
Condensed Consolidated Statement of Comprehensive Income (Loss):     
Net income$330
 $34
 $364
Comprehensive income315
 34
 349
      
Condensed Consolidated Statement of Cash Flows:     
Cash flows from operating activities:     
Net income$330
 $34
 $364
Adjustments to reconcile net income to net cash provided by operating activities:     
Deferred income taxes and investment tax credits112
 (34) 78
Other2
 34
 36
Net cash provided by operating activities592
 34
 626
Cash flows from financing activities:     
Tax benefit related to share-based compensation34
 (34) —
Net cash provided by financing activities364
 (34) 330
SDG&E:     
Condensed Consolidated Statement of Operations:     
Income tax expense$(72) $7
 $(65)
Net income130
 7
 137
Earnings attributable to common shares129
 7
 136
      
Condensed Consolidated Statement of Comprehensive Income (Loss):     
Net income$130
 $7
 $137
Comprehensive income128
 7
 135
      
Condensed Consolidated Statement of Cash Flows:     
Cash flows from operating activities:     
Net income$130
 $7
 $137
Adjustments to reconcile net income to net cash provided by operating activities:     
Deferred income taxes and investment tax credits20
 (7) 13
SoCalGas:     
Condensed Statement of Operations:     
Income tax expense$(87) $4
 $(83)
Net income195
 4
 199
      
Condensed Statement of Comprehensive Income (Loss):     
Net income/Comprehensive income$195
 $4
 $199
      
Condensed Statement of Cash Flows:     
Cash flows from operating activities:     
Net income$195
 $4
 $199
Adjustments to reconcile net income to net cash provided by operating activities:     
Deferred income taxes and investment tax credits59
 (4) 55




ASU 2016-13, “Measurement of Credit Losses on Financial Instruments”: ASU 2016-13 changes how entities will measure credit losses for most financial assets and certain other instruments. The standard providesintroduces an “expected credit loss” impairment model that requires immediate recognition of estimated credit losses expected to occur over the remaining life of most financial assets measured at amortized cost, including trade and other receivables, loan commitments and financial guarantees. ASU 2016-13 also requires use of an allowance to record estimated credit losses on available-for-sale debt securities and expands disclosure requirements regarding an entity’s assumptions, models and methods for an accounting policy election to either continue to estimate forfeitures or account for them as they occur. estimating the credit losses.
For public entities, ASU 2016-092016-13 is effective for fiscal years beginning after December 15, 2016,2019, with early adoption permitted for fiscal years beginning after December 15, 2018. We are currently evaluating the effect of the standard on our ongoing financial reporting and have not yet selected the year in which we will adopt the standard.
ASU 2016-15, “Classification of Certain Cash Receipts and Cash Payments”: ASU 2016-15 provides guidance on how certain cash receipts and cash payments are to be presented and classified in the statement of cash flows in order to reduce diversity in practice.
For public entities, ASU 2016-15 is effective for fiscal years beginning after December 15, 2017, with early adoption permitted, and is effective for interim periods in the year of adoption. An entity that elects early adoption must adopt all of the amendments in the same period. Entities must apply the guidance retrospectively to all periods presented, but may apply it prospectively if retrospective application would be impracticable. We are currently evaluating the fulleffect of the standard on our statements of cash flows and plan to adopt the standard in the fourth quarter of 2017.
ASU 2016-18, “Restricted Cash”: ASU 2016-18 requires amounts described as restricted cash and restricted cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. A reconciliation between the balance sheet and the statement of cash flows must be disclosed when the balance sheet includes more than one line item for cash, cash equivalents, restricted cash and restricted cash equivalents.
For public entities, ASU 2016-18 is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. We plan to adopt the standard in the fourth quarter of 2017. If we had adopted ASU 2016-18 in the first quarter of 2017, cash and cash equivalents at the beginning of the period would have included restricted cash of $76 million and $12 million, and cash and cash equivalents at the end of the period would have included restricted cash of $77 million and $13 million, in Sempra Energy’s and SDG&E’s statements of cash flows in the three months ended March 31, 2017, respectively.
ASU 2017-04, “Simplifying the Test for Goodwill Impairment”: ASU 2017-04 removes the second step of the goodwill impairment test, which requires a hypothetical purchase price allocation. An entity will be required to apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the carrying amount of goodwill. For public entities, ASU 2017-04 is effective for annual or interim goodwill impairment tests in fiscal years beginning after December 15, 2019, with early adoption permitted. The amendments should be applied on a prospective basis. We are currently evaluating the effect of the standard on our ongoing financial reporting and have not yet concluded as to whetherselected the year in which we will adopt the standard.
ASU 2017-05, “Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets”: ASU 2017-05 clarifies the scope of accounting for the derecognition or partial sale of nonfinancial assets to exclude all businesses and nonprofit activities. ASU 2017-05 also provides a definition for in-substance nonfinancial assets and additional guidance on partial sales of nonfinancial assets. For public entities, ASU 2017-05 is effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, with early adoption permitted. An entity may elect to apply the amendments under a retrospective or modified retrospective approach. We are currently evaluating the effect of the standard on our ongoing financial reporting and will adopt it in conjunction with ASU 2014-09 on January 1, 2018, but have not yet selected the method of adoption.
ASU 2017-07, “Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost”: ASU 2017-07 requires the service cost component of net periodic benefit costs to be presented in the same income statement line item as other employee compensation costs arising from services rendered during the period and the other components of net periodic benefit costs to be presented separately outside of operating income. The guidance also allows only the service cost component to be eligible for capitalization. For public entities, ASU 2017-07 is effective for annual reporting periods beginning after December 15, 2017, with early adoption permitted as of the beginning of an early adoption. If we early adoptannual period for which financial statements have not been issued or made available for issuance. Amendments are to be applied retrospectively for presentation of costs and prospectively for capitalization of service costs. We are currently evaluating the effect of the standard on our ongoing financial reporting and have not yet selected the year in 2016,which we will recognize a $34 million tax benefit in earnings, which is currently recorded in Shareholders’ Equity, related toadopt the three months ended March 31, 2016, and a benefit to retained earnings as of January 1, 2016 of approximately $107 million, both associated with the provision in ASU 2016-09 to recognize all excess tax benefits related to share-based compensation.standard.





NOTE 3. ACQUISITION AND DIVESTITURE ACTIVITY

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


ACQUISITION


Sempra Renewables

In We did not complete any acquisitions during the three months ended March 2015, Sempra Renewables invested $8 million to acquire a 100-percent interest31, 2017 or 2016. At March 31, 2017, the purchase price allocations for the acquisitions of Ventika, S.A.P.I. de C.V. and Ventika II, S.A.P.I. de C.V. in the Black Oak Getty Wind project, a 78-megawatt (MW) wind farm under development in Stearns County, Minnesota. The wind farm has a 20-year power purchase agreement with Minnesota Municipal Power Agency that will commence upon commercial operation in late 2016.


POTENTIAL ACQUISITION


Sempra Mexico

IEnovaDecember 2016 and Petróleos Mexicanos (or PEMEX, the Mexican state-owned oil company) are 50-50 partners in the joint venture Gasoductos de Chihuahua (GdC). GdC develops and operates energy infrastructure in Mexico. On July 31, 2015, IEnova entered into an agreement to purchase PEMEX’s 50-percent interest for $1.325 billion (excluding the assumption of approximately $170 million of net debt), which upon closing would increase its interest from 50 percent to 100 percent. The assets involved in the acquisition included three natural gas pipelines, an ethane pipeline, and a liquid petroleum gas pipeline and associated storage terminal. The transaction excluded the Los Ramones Norte pipeline that is owned under a separate joint venture with GdC, PEMEX, BlackRock and First Reserve, keeping IEnova’s interest in the pipeline at the current 25 percent.
In December 2015, Mexico’s Comisión Federal de Competencia Económica (COFECE or Mexican Competition Commission) objected to the transaction based upon previous antitrust rulings on PEMEX’s indirect ownership of two of the assets, the TDF S. de R.L. de C.V. liquid petroleum gas pipelinein September 2016 were preliminary and subject to completion. Adjustments to the San Fernando natural gas pipeline, included in the acquisitionfair value estimates may occur as proposed. COFECE specified that these assets must be offered by PEMEX in a competitive bidding process as a prerequisite for approval of any transaction involving these two assets. COFECE’s decision did not object to IEnova’s acquisition of the assets on a market concentration basis. The parties are in the process of restructuring the transaction so that PEMEX can proceed with a bidding process on these twoconducted for various valuations and assessments is finalized, primarily related to tax assets, in accordance with the COFECE ruling. IEnova will have the right to approve the winning bidder as a new partner. Any restructured transaction will require negotiation of satisfactory terms for the revised transaction,liabilities and will also be subject to IEnova and PEMEX board approvals and satisfactory completion of the Mexican antitrust review, and may require further approvals from Mexican authorities.


other attributes.
ASSETS HELD FOR SALE POWER PLANT


Sempra Mexico

We classify assets as held for sale when management approves and commits to a formal plan to actively market an asset for sale and we expect the sale to close within the next twelve months.12 months. Upon classifying an asset as held for sale, we record the asset at the lower of its carrying value or its estimated fair value reduced for selling costs, and we stop recording depreciation expense on the asset.costs.
Sempra Mexico
In February 2016, management approved a plan to market and sell Sempra Mexico’s Termoeléctrica de Mexicali (TdM), a 625-MW625-megawatt (MW) natural gas-fired power plant located in Mexicali, Baja California, Mexico. As a result, we stopped depreciating the plant and classified it as held for sale. We considered the estimated fair value of the plant, less costs to sell, and determined that no additional adjustments to carrying value are required at March 31, 2017. We are actively pursuing the sale of TdM, which we expect to be completed in the second half of 2017.
In connection with classifying Termoeléctrica de MexicaliTdM as held for sale, we recognized a $5 million income tax benefit and $29 million in Income Tax Expense on Sempra Energy’s Condensed Consolidated Statement of Operations inincome tax expense for the three months ended March 31, 2017 and 2016, respectively, for a deferred Mexican income tax liability related to the excess of carrying value over the tax basis (outside basis difference). This outside basis difference resulted from undistributed earnings and movements in foreign exchange rates and inflation. The deferred tax liability onbasis. As the outside basis difference was not previously recognized due to exceptions provided in U.S. GAAP, which no longer apply as a result of classifying the plant as held for sale. As this $29 million ($24 million after noncontrolling interest) of Mexican income tax expense on our outsidethis basis difference is based on current carrying value, foreign exchange rates and inflation, at March 31, 2016, thissuch amount could change in future periods until the date of sale.
At March 31, 2016,2017, the carrying amounts of the major classes of assets and related liabilities held for sale associated with the plantTdM are as follows:
ASSETS HELD FOR SALE AT MARCH 31, 2017
(Dollars in millions)
 Termoeléctrica de Mexicali
Cash$1
Inventories11
Other current assets31
Deferred income taxes9
Property, plant and equipment, net120
Other noncurrent assets24
Total assets held for sale$196
  
Accounts payable$6
Other current liabilities4
Asset retirement obligations4
Other noncurrent liabilities26
Total liabilities held for sale$40



ASSETS HELD FOR SALE, POWER PLANT
(Dollars in millions) 
  March 31, 2016
Cash and cash equivalents$1
Inventories 8
Other current assets 29
Other assets 15
Property, plant and equipment, net 250
    Total assets held for sale$303
    
Accounts payable$1
Other current liabilities 7
Deferred income taxes 16
Asset retirement obligations 4
Other liabilities 15
    Total liabilities held for sale(1)$43
(1)Included in Other Current Liabilities on the Sempra Energy Condensed Consolidated Balance Sheet.

We considered the estimated fair value of the plant, less costs to sell, and determined that no adjustment to carrying value was required. In estimating fair value, we used both a market approach and discounted cash flow valuation techniques. In the event that the estimated sales price, less transaction costs, is less than the carrying value, or updated market information indicates fair value may be less than carrying value, we would recognize a loss in our results of operations at that time. We expect to complete the sale in the second half of 2016.


PENDING DIVESTITURE


Sempra Natural GasLNG & Midstream
Investment in Rockies Express Pipeline LLC (Rockies Express)

OnIn March 29, 2016, Sempra Natural GasLNG & Midstream entered into an agreement to sell its 25-percent interest in Rockies Express Pipeline LLC (Rockies Express) to a subsidiary of Tallgrass Development, LP for cash consideration of approximately $440 million, subject to adjustment at closing. The transaction is subject to customary closing conditions. Sempra Natural Gas expects the transaction to closeclosed in the second quarterMay 2016 for total cash proceeds of 2016.$443 million.


At the date of the agreement, the carrying value of Sempra Natural Gas’LNG & Midstream’s investment in Rockies Express was $484 million. Following the execution of the agreement, Sempra Natural GasLNG & Midstream measured the fair value of its equity method investment at $440 million, and recognized a $44 million ($27 million after-tax) impairment in Equity (Losses) Earnings, Before Income Tax, on the Sempra Energy Condensed Consolidated Statement of Operations for the three months ended March 31, 2016. We discuss non-recurring fair value measures and the associated accounting impact on our investment in Rockies Express in Note 8.10 of the Notes to Consolidated Financial Statements in the Annual Report.


NOTE 4. INVESTMENTS IN UNCONSOLIDATED ENTITIES

Sempra Energy uses the equity method to account for investments in affiliated companies over which we have the ability to exercise significant influence, but not control. We provide additional information concerning our equity method investments above in Note 3 above and in Notes 3 and 4 of the Notes to Consolidated Financial Statements in the Annual Report.
SEMPRA SOUTH AMERICAN UTILITIES

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

SEMPRA MEXICO
Sempra Mexico invested cash of $46 million in its unconsolidated joint venture, Infraestructura Marina del Golfo, in the three months ended March 31, 2017.
SEMPRA RENEWABLES

Sempra Renewables invested cash of $15 million and $17 million in its unconsolidated joint ventures duringin the three months ended March 31, 2016 and 2015, respectively.


2016.
SEMPRA NATURAL GASLNG & MIDSTREAM

Sempra Natural GasLNG & Midstream capitalized $11 million and $12 million of interest during bothin the three months ended March 31, 2017 and 2016, and 2015 and invested cash of $3 million duringrespectively, related to its investment in Cameron LNG Holdings, LLC (Cameron LNG JV), which has not commenced planned principal operations. During the three months ended March 31, 2015 at Cameron2017, Sempra LNG Holdings, LLC (Cameron LNG JV).
In March 2016, Sempra Natural Gas entered into an agreement to sell its 25-percent interest& Midstream invested cash of $1 million in Rockies Express, which we discuss in Note 3.this unconsolidated joint venture.


GUARANTEES

At March 31, 2017, we had outstanding guarantees aggregating a maximum of $4.4 billion with an aggregate carrying value of $48 million. We discuss these guarantees that we have provided, which have a maximum aggregate amount of $4.5 billion, in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report. These guarantees have an aggregate carrying value of $67 million at March 31, 2016.



NOTE 5. OTHER FINANCIAL DATA




INVENTORIES
INVENTORIES

The components of inventories by segment are as follows:


INVENTORY BALANCES
(Dollars in millions)
 Natural gas  Liquefied natural gas  Materials and supplies  Total
 March 31, 2017 December 31, 2016  March 31, 2017 December 31, 2016  March 31,
2017		 December 31, 2016  March 31,
2017		 December 31, 2016
SDG&E$—
 $2
  $—
 $—
  $82
 $78
  $82
 $80
SoCalGas(1)—
 11
  —
 —
  43
 47
  43
 58
Sempra South American Utilities—
 —
  —
 —
  28
 27
  28
 27
Sempra Mexico—
 —
  9
 6
  2
 1
  11
 7
Sempra Renewables—
 —
  —
 —
  4
 4
  4
 4
Sempra LNG & Midstream39
 79
  3
 3
  —
 —
  42
 82
Sempra Energy Consolidated$39
 $92
  $12
 $9
  $159
 $157
  $210
 $258
(1)At March 31, 2017 and December 31, 2016, SoCalGas’ natural gas inventory for core customers is net of an inventory loss related to the Aliso Canyon natural gas leak, which we discuss in Note 11.
INVENTORY BALANCES
(Dollars in millions)
  Natural gasLiquefied natural gasMaterials and suppliesTotal
  
March 31,
2016
 
December 31,
2015
March 31,
2016
December 31,
2015
March 31,
2016
December 31,
2015
March 31,
2016
December 31,
2015
SDG&E$3 $6$―$―$69$69$72$75
SoCalGas(1) ―  49 ― ― 33 30 33 79
Sempra South American Utilities ―  ― ― ― 37 30 37 30
Sempra Mexico ―  ― 6 3 2 10 8 13
Sempra Renewables ―  ― ― ― 3 3 3 3
Sempra Natural Gas 74  94 3 3 1 1 78 98
                  
Sempra Energy Consolidated
$77 $149$9$6$145$143$231$298
(1)At both March 31, 2016 and December 31, 2015, SoCalGas' natural gas inventory for core customers is net of the estimated inventory loss related to the Aliso Canyon natural gas leak, which we discuss in Note 11.
GREENHOUSE GAS (GHG) ALLOWANCES
The Condensed Consolidated Balance Sheets include the following amounts associated with GHG allowances and obligations.
GHG ALLOWANCES AND OBLIGATIONS
(Dollars in millions)           
 Sempra Energy
Consolidated		 SDG&E SoCalGas
 
March 31,
2017
 
December 31,
2016
 March 31,
2017		 December 31,
2016		 March 31,
2017		 December 31,
2016
Assets:           
Other current assets$40
 $40
 $16
 $16
 $24
 $24
Sundry307
 295
 184
 182
 119
 109
Total assets$347
 $335
 $200
 $198
 $143
 $133
            
Liabilities:           
Other current liabilities$40
 $40
 $16
 $16
 $24
 $24
Deferred credits and other183
 171
 80
 72
 99
 96
Total liabilities$223
 $211
 $96
 $88
 $123
 $120


GOODWILL

We discuss goodwill in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. The increase in goodwill from $819$2,364 million at December 31, 20152016 to $849$2,380 million at March 31, 20162017 is due to foreign currency translation at Sempra South American Utilities. We record the offset of this fluctuation in Other Comprehensive Income (Loss) (OCI).

VARIABLE INTEREST ENTITIES
We consolidate a VIE if we are the primary beneficiary of the VIE. Our determination of whether we are the primary beneficiary is based uponon qualitative and quantitative analyses, which assess
§  
▪the purpose and design of the VIE;
§  
▪the nature of the VIE’s risks and the risks we absorb;
§  
▪the power to direct activities that most significantly impact the economic performance of the VIE; and
§  
▪the obligation to absorb losses or right to receive benefits that could be significant to the VIE.


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

Tolling Agreements
SDG&E has agreements under which it purchases power generated by facilities for which it supplies all of the natural gas to fuel the power plant (i.e., tolling agreements). SDG&E’s obligation to absorb natural gas costs may be a significant variable interest. In addition, SDG&E has the power to direct the dispatch of electricity generated by these facilities. Based upon our analysis, the ability to direct the dispatch of electricity may have the most significant impact on the economic performance of the entity owning the generating facility because of the associated exposure to the cost of natural gas, which fuels the plants, and the value of electricity produced. To the extent that SDG&E (1) is obligated to purchase and provide fuel to operate the facility, (2) has the power to direct the dispatch, and (3) purchases all of the output from the facility for a substantial portion of the facility’s useful life, SDG&E may be the primary beneficiary of the entity owning the generating facility. SDG&E determines if it is the primary beneficiary in these cases based on a qualitative approach in which we consider the operational characteristics of the facility, including its expected power generation output relative to its capacity to generate and the financial structure of the entity, among other factors. If we determine that SDG&E is the primary beneficiary, SDG&E and Sempra Energy consolidate the entity that owns the facility as a VIE.
Otay Mesa VIE
SDG&E has an agreement to purchase power generated at the Otay Mesa Energy Center (OMEC), a 605-MW generating facility. In addition to tolling, the agreement provides SDG&E with the option to purchase OMEC at the end of the contract term in 2019, or upon earlier termination of the purchased-powerpower purchase agreement, at a predetermined price subject to adjustments based on performance of the facility. If SDG&E does not exercise its option, under certain circumstances, it may be required to purchase the power plant at a predetermined price,for $280 million, which we refer to as the put option.
The facility owner, Otay Mesa Energy Center LLC (OMEC LLC), is a VIE (Otay Mesa VIE), of which SDG&E is the primary beneficiary. SDG&E has no OMEC LLC voting rights, holds no equity in OMEC LLC and does not operate OMEC. In addition to the risks absorbed under the tolling agreement, SDG&E absorbs separately through the put option a significant portion of the risk that the value of Otay Mesa VIE could decline. Accordingly, SDG&E and Sempra Energy have consolidatedconsolidate Otay Mesa VIE. Otay Mesa VIE’s equity of $51$39 million at March 31, 20162017 and $53$37 million at December 31, 20152016 is included on the Condensed Consolidated Balance Sheets in Other Noncontrolling Interests for Sempra Energy and in Noncontrolling Interest for SDG&E.
OMEC LLC has a loan outstanding of $312$302 million at March 31, 2016,2017, the proceeds of which were used for the construction of OMEC. The loan is with third party lenders and is securedcollateralized by OMEC’s property, plant and equipment. SDG&E is not a party to the loan agreement and does not have any additional implicit or explicit financial responsibility to OMEC LLC. The loan fully matures in April 2019 and bears interest at rates varying with market rates. In addition, OMEC LLC has entered into interest rate swap agreements to moderate its exposure to interest rate changes. We provide additional information concerning the interest rate swaps in Note 7.
The Condensed Consolidated Statements of Operations of Sempra Energy and SDG&E include the following amounts associated with Otay Mesa VIE. The amounts are net of eliminations of transactions between SDG&E and Otay Mesa VIE. The captions in the table below generally correspond to SDG&E’s Condensed Consolidated Statements of Operations.
AMOUNTS ASSOCIATED WITH OTAY MESA VIE   
(Dollars in millions)   
 Three months ended March 31,
 2017 2016
Operating expenses   
Cost of electric fuel and purchased power$(18) $(17)
Operation and maintenance4
 4
Depreciation and amortization7
 7
Total operating expenses(7) (6)
Operating income7
 6
Interest expense(5) (5)
Income before income taxes/Net income2
 1
Earnings attributable to noncontrolling interest(2) (1)
Earnings attributable to common shares$—
 $—


AMOUNTS ASSOCIATED WITH OTAY MESA VIE
(Dollars in millions)
 Three months ended March 31,
 20162015
Operating expenses    
    Cost of electric fuel and purchased power$(17)$(18)
    Operation and maintenance 4 4
    Depreciation and amortization 7 6
        Total operating expenses (6) (8)
Operating income 6 8
Interest expense (5) (4)
Income before income taxes/Net income 1 4
Earnings attributable to noncontrolling interest (1) (4)
   Earnings attributable to common shares$―$―


SDG&E has determined that no contracts, other than the one relating to Otay Mesa VIE mentioned above, result in SDG&E being the primary beneficiary of a variable interest entity at March 31, 2016.2017. In addition to the tolling agreements described above, other variable interests involve various elements of fuel and power costs, including certain construction costs, tax credits, and other components of cash flow expected to be paid to or received by our counterparties. In most of these cases, the expectation of variability is not substantial, and SDG&E generally does not have the power to direct activities that most significantly impact the economic performance of the other VIEs. If our ongoing evaluation of these VIEs were to conclude that SDG&E becomes the primary beneficiary and consolidation by SDG&E becomes necessary, the effects are not expected to significantly affect the financial position, results of operations, or liquidity of SDG&E. In addition, SDG&E is not exposed to losses or gains as a result of these other VIEs, because all such variability would be recovered in rates. We provide additional information about power purchase agreements with peaker plant facilities that are VIEs of which SDG&E is not the primary beneficiary in Note 11 below and in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.
We provide additional information regarding Otay Mesa VIE in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.


Sempra Natural GasRenewables
Effective December 2016, certain of Sempra Renewables’ wind and solar power generation projects are held by limited liability companies whose members are Sempra Renewables and financial institutions. The financial institutions are noncontrolling tax equity investors to which earnings, tax attributes and cash flows are allocated in accordance with the respective limited liability company agreements. These entities are VIEs and Sempra Energy is the primary beneficiary, generally due to Sempra Energy’s power to direct activities that most significantly impact the economic performance of these VIEs as the operator of the renewable energy projects.

As the primary beneficiary of these tax equity limited liability companies, we consolidate them. Sempra Energy’s Condensed Consolidated Balance Sheets include $918 million and $926 million of property, plant and equipment, net, and equity of $464 million and $468 million included in Other Noncontrolling Interests at March 31, 2017 and December 31, 2016, respectively, associated with these entities. Sempra Energy’s Condensed Consolidated Statement of Operations for the three months ended March 31, 2017 includes the following amounts associated with the tax equity limited liability companies. The amounts are net of eliminations of transactions between Sempra Energy and these entities.
AMOUNTS ASSOCIATED WITH TAX EQUITY ARRANGEMENTS 
(Dollars in millions) 
  Three months ended March 31, 2017
REVENUES 
Energy-related businesses$13
EXPENSES 
Operation and maintenance(2)
Depreciation and amortization(8)
Income before income taxes3
Income tax expense(2)
Net income1
Losses attributable to noncontrolling interests(1)3
Earnings$4
   
(1)Net income or loss attributable to the noncontrolling interests is computed using the hypothetical liquidation at book value (HLBV) method and is not based on ownership percentages.


We provide additional information regarding the tax equity limited liability companies in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
Sempra LNG & Midstream
Sempra Energy’s equity method investment in Cameron LNG JV is considered to be a VIE generallyprincipally due to contractual provisions that transfer certain risks to customers. Sempra Energy is not the primary beneficiary because we do not have the power to direct the most significant activities of Cameron LNG JV. We will continue to evaluate Cameron LNG JV for any changes that may impact our determination of the primary beneficiary. The carrying value of our investment in Cameron LNG JV, including amounts recognized in Accumulated Other Comprehensive Income (Loss) (AOCI), related to interest-rate cash flow hedges at Cameron LNG JV, was $872$999 million at March 31, 20162017 and $983$997 million at December 31, 2015.2016. Our maximum exposure to loss includes the carrying value of our investment and the guarantees discussed above in Note 4 above and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.



Other Variable Interest Entities

Sempra Energy’s other operating units also enter into arrangements which could include variable interests. We evaluate these arrangements and applicable entities based uponon the qualitative and quantitative analyses described above. Certain of these entities are service companies that are VIEs. As the primary beneficiary of these service companies, we consolidate them; however, their financial statements are not material to the financial statements of Sempra Energy. In all other cases, we have determined that these contracts are not variable interests in a VIE and therefore are not subject to the U.S. GAAP requirements concerning the consolidation of VIEs.


PENSION AND OTHER POSTRETIREMENT BENEFITS


Net Periodic Benefit Cost

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

NET PERIODIC BENEFIT COST – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
 Pension benefits Other postretirement benefits
 Three months ended March 31,
 2017 2016 2017 2016
Service cost$28
 $28
 $6
 $5
Interest cost37
 40
 9
 11
Expected return on assets(40) (42) (16) (17)
Amortization of:       
Prior service cost3
 3
 —
 —
Actuarial loss (gain)8
 6
 (1) —
Regulatory adjustment(12) (28) 2
 2
Total net periodic benefit cost$24
 $7
 $—
 $1
NET PERIODIC BENEFIT COST – SDG&E
(Dollars in millions)
 Pension benefits Other postretirement benefits
 Three months ended March 31,
 2017 2016 2017 2016
Service cost$8
 $7
 $1
 $1
Interest cost9
 10
 2
 2
Expected return on assets(11) (12) (3) (3)
Amortization of:
      
Prior service cost—
 —
 1
 1
Actuarial loss2
 3
 —
 —
Regulatory adjustment(7) (7) (1) (1)
Total net periodic benefit cost$1
 $1
 $—
 $—
NET PERIODIC BENEFIT COST – SOCALGAS
(Dollars in millions)
 Pension benefits Other postretirement benefits
 Three months ended March 31,
 2017 2016 2017 2016
Service cost$18
 $17
 $4
 $4
Interest cost24
 25
 7
 8
Expected return on assets(26) (25) (13) (14)
Amortization of:       
Prior service cost (credit)2
 2
 (1) (1)
Actuarial loss4
 3
 —
 —
Regulatory adjustment(5) (21) 3
 3
Total net periodic benefit cost$17
 $1
 $—
 $—


NET PERIODIC BENEFIT COST – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
 Pension benefitsOther postretirement benefits
 Three months ended March 31,
 2016201520162015
Service cost$28$30$5$7
Interest cost 40 39 11 12
Expected return on assets (42) (44) (17) (17)
Amortization of:        
    Prior service cost (credit) 3 3 ― (1)
    Actuarial loss 6 8 ― ―
Regulatory adjustment (28) (29) 2 ―
Total net periodic benefit cost$7$7$1$1



NET PERIODIC BENEFIT COST – SDG&E
(Dollars in millions)
 Pension benefitsOther postretirement benefits
 Three months ended March 31,
 2016201520162015
Service cost$7$8$1$2
Interest cost 10 10 2 2
Expected return on assets (12) (14) (3) (3)
Amortization of:        
    Prior service cost ― ― 1 1
    Actuarial loss 3 2 ― ―
Regulatory adjustment (7) (5) (1) (2)
Total net periodic benefit cost$1$1$―$―



NET PERIODIC BENEFIT COST – SOCALGAS
(Dollars in millions)
 Pension benefitsOther postretirement benefits
 Three months ended March 31,
 2016201520162015
Service cost$17$19$4$5
Interest cost 25 25 8 9
Expected return on assets (25) (27) (14) (14)
Amortization of:        
    Prior service cost (credit) 2 2 (1) (2)
    Actuarial loss 3 5 ― ―
Regulatory adjustment (21) (24) 3 2
Total net periodic benefit cost$1$―$―$―


Benefit Plan Contributions

The following table shows our year-to-date contributions to pension and other postretirement benefit plans and the amounts we expect to contribute in 2016:

2017:
BENEFIT PLAN CONTRIBUTIONS
(Dollars in millions)
  
Sempra Energy
Consolidated
 SDG&E SoCalGas
Contributions through March 31, 2017:      
Pension plans $26
 $2
 $17
Other postretirement benefit plans 1
 —
 —
Total expected contributions in 2017:      
Pension plans $181
 $38
 $90
Other postretirement benefit plans 8
 4
 1

BENEFIT PLAN CONTRIBUTIONS
(Dollars in millions)
 Sempra Energy  
 ConsolidatedSDG&ESoCalGas
Contributions through March 31, 2016:      
    Pension plans$15$2$―
    Other postretirement benefit plans 1 ― ―
Total expected contributions in 2016:      
    Pension plans$123$4$77
    Other postretirement benefit plans 6 2 1

RABBI TRUST

In support of its Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans, Sempra Energy maintains dedicated assets, including a Rabbi Trust and investments in life insurance contracts, which totaled $432$412 million and $464$430 million at March 31, 20162017 and December 31, 2015,2016, respectively.


EARNINGS PER SHARE (EPS)

The following table provides earnings per share (EPS)EPS computations for the three months ended March 31, 20162017 and 2015.2016. Basic EPS is calculated by dividing earnings attributable to common stock by the weighted-average number of common shares outstanding for the period. Diluted EPS includes the potential dilution of common stock equivalent shares that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.

EARNINGS PER SHARE COMPUTATIONSEARNINGS PER SHARE COMPUTATIONS   
(Dollars in millions, except per share amounts; shares in thousands)(Dollars in millions, except per share amounts; shares in thousands)   
 Three months ended March 31,Three months ended March 31,
 201620152017 2016(1)
Numerator:Numerator:       
Earnings/Income attributable to common shares Earnings/Income attributable to common shares$319$437$441
 $353
        
Denominator:Denominator:       
Weighted-average common shares outstanding for basic EPS(1) 249,734 247,722
Dilutive effect of stock options, restricted stock awards and restricted stock units 1,678 3,484
Weighted-average common shares outstanding for basic EPS(2)251,131
 249,734
Dilutive effect of stock options, restricted stock awards and restricted stock units(3)1,115
 1,753
Weighted-average common shares outstanding for diluted EPS Weighted-average common shares outstanding for diluted EPS 251,412 251,206252,246
 251,487
        
Earnings per share:Earnings per share:       
Basic Basic$1.28$1.76$1.76
 $1.41
Diluted Diluted$1.27$1.741.75
 1.40
(1)Includes 555 and 452 average fully vested restricted stock units held in our Deferred Compensation Plan for the three months ended March 31, 2016 and 2015, respectively. These fully vested restricted stock units are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued.
(1)As adjusted for the adoption of ASU 2016-09 as of January 1, 2016, as we discuss in Note 2.
(2)Includes 600 and 555 average fully vested restricted stock units held in our Deferred Compensation Plan for the three months ended March 31, 2017 and 2016, respectively. These fully vested restricted stock units are included in weighted-average common shares outstanding for basic EPS because there are no conditions under which the corresponding shares will not be issued.
(3)Due to market fluctuations of both Sempra Energy stock and the comparative indices used to determine the vesting percentage of our total shareholder return performance-based restricted stock units, which we discuss in Note 8 of the Notes to Consolidated Financial Statements in the Annual Report, dilutive restricted stock units may vary widely from period-to-period.


The dilutionpotentially dilutive impact from common stock options, restricted stock awards (RSAs) and restricted stock units (RSUs) is based oncalculated under the treasury stock method. Under this method, proceeds based on the exercise price plusand unearned compensation and windfall tax benefits recognized, minus tax shortfalls recognized, are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits are tax deductions we would receive uponperiod, reducing the assumed exercisenumber of stock options in excess of the deferred income taxes we recorded related to the compensation expense on the stock options. Tax shortfalls occur when the assumed tax deductions are less than recorded deferred income taxes. The calculation of dilutive common stock equivalents excludes options for which the exercise price on common stock was greater than the average market price during the period (out-of-the-money options). For the three months ended March 31, 2016 and 2015, we had no such antidilutive stock options outstanding. For the three months ended March 31, 2016 and 2015, we had no stock options outstanding that were antidilutive because of the unearned compensation and windfall tax benefits included in the assumed proceeds under the treasury stock method.
The dilution from unvested restricted stock awards (RSAs) and restricted stock units (RSUs) is also based on the treasury stock method. Proceeds equal to the unearned compensation and windfall tax benefits recognized, minus tax shortfalls recognized, related to the awards and units are assumedpotential new shares to be used to repurchase shares on the open market at the average market price for the period.issued and sometimes causing an antidilutive effect. The windfall tax benefits or tax shortfalls recognized are the difference between tax deductions we would receive upon the assumed vestingcomputation of RSAs or RSUs and the deferred income taxes we recorded related to the compensation expense on such awards and units. There were no antidilutive RSAs or antidilutive RSUs from the application of unearned compensation in the treasury stock methoddiluted EPS for the three months ended March 31, 2016. There were no such2017 and 2016 excludes 6,801 and zero potentially dilutive shares, respectively, because to include them would be antidilutive RSAs and 614 antidilutive RSUs for the three months ended March 31, 2015.
Our performance-based RSUs include awards that vest atperiod. However, these shares could potentially dilute basic EPS in the end of three-year (for awards granted during or after 2015) or four-year performance periods based on Sempra Energy’s total return to shareholders relative to that of specified market indices (Total Shareholder Return or TSR RSUs) or based on the compound annual growth rate of Sempra Energy’s EPS (EPS RSUs). The comparative market indices for the TSR RSUs are the Standard & Poor’s (S&P) 500 Utilities Index and the S&P 500 Index. We primarily use long-term analyst consensus growth estimates for S&P 500 Utilities Index peer companies to develop our EPS RSU targets. TSR RSUs represent the right to receive from zero to 1.5 shares (2.0 shares for awards granted during or after 2014) of Sempra Energy common stock if performance targets are met. EPS RSUs represent the right to receive from zero to 2.0 shares of Sempra Energy common stock if performance targets are met. If performance falls between the targets specified for each performance metric, we calculate the payout using linear interpolation. Participants also receive additional shares for dividend equivalents on shares subject to RSUs, which are deemed reinvested to purchase additional units that become subject to the same vesting conditions as the RSUs to which the dividends relate. We discuss performance-based RSU awards further in Note 8 of the Notes to Consolidated Financial Statements in our Annual Report.
Our RSAs, which are solely service-based, and those RSUs that are service-based or issued in connection with certain other performance goals represent the right to receive up to 1.0 share if the service requirements or certain other vesting conditions are met. These RSAs and RSUs have the same dividend equivalent rights as the performance-based RSUs described above. We include RSAs and these RSUs in potential dilutive shares at 100 percent, subject to the application of the treasury stock method. We include our TSR RSUs and EPS RSUs in potential dilutive shares at zero to up to 200 percent to the extent that they currently meet the performance requirements for vesting, subject to the application of the treasury stock method. Due to market fluctuations of both Sempra Energy stock and the comparative indices, dilutive TSR RSU shares may vary widely from period-to-period. If it were assumed that performance goals for all performance-based RSUs were met at maximum levels and if the treasury stock method were not applied to any of our RSAs or RSUs, the incremental potential dilutive shares would be 2,616,084 and 1,285,193 for the three months ended March 31, 2016 and 2015, respectively.
future.



SHARE-BASED COMPENSATION

We discuss our share-based compensation plans in Note 8 of the Notes to Consolidated Financial Statements in the Annual Report. We recorded share-based compensation expense, net of income taxes, of $7 million and $8 million for the three months ended March 31, 2016 and 2015, respectively. Pursuant to our Sempra Energy share-based compensation plans, Sempra Energy’s compensation committeeBoard of Directors granted 372,270 TSR RSUs, 94,550 EPS424,360 performance-based RSUs and 93,25692,413 service-based RSUs during the three months ended March 31, 2016,2017, primarily in January.
During the three months ended March 31, 2016,2017, IEnova issued 183,970granted 1,034,086 RSUs from the IEnova 2013 Long-Term Incentive Plan, under which awards are cash settled at vesting based on the price of IEnova common stock.
We discuss share-based compensation plans and related awards further in Note 8 of the Notes to Consolidated Financial Statements in the Annual Report.


CAPITALIZED FINANCING COSTS

Capitalized financing costs include capitalized interest costs and AFUDC related to both debt and equity financing of construction projects. We capitalize interest costs incurred to finance capital projects and interest on equity method investments that have not commenced planned principal operations.
Interest capitalized and AFUDC are as follows:
CAPITALIZED FINANCING COSTS
(Dollars in millions)
 Three months ended March 31,
 2017 2016
Sempra Energy Consolidated$82
 $52
SDG&E20
 15
SoCalGas15
 13

The following table shows capitalized financing costs for the three months ended March 31, 2016 and 2015.


CAPITALIZED FINANCING COSTS
(Dollars in millions)
  Three months ended March 31,
  20162015
Sempra Energy Consolidated:    
    AFUDC related to debt$7$6
    AFUDC related to equity 27 27
    Other capitalized interest 18 17
        Total Sempra Energy Consolidated$52$50
SDG&E:    
    AFUDC related to debt$4$3
    AFUDC related to equity 11 8
        Total SDG&E$15$11
SoCalGas:    
    AFUDC related to debt$3$3
    AFUDC related to equity 10 9
        Total SoCalGas$13$12


COMPREHENSIVE INCOME

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

CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1) 
(Dollars in millions) 
 
Foreign
currency
translation
adjustments
 
Financial
instruments
 
Pension and other
postretirement
benefits
 
Total
accumulated other
comprehensive
income (loss)
 
 Three months ended March 31, 2017 and 2016 
Sempra Energy Consolidated:        
         
Balance as of December 31, 2016$(527) $(125) $(96) $(748) 
OCI before reclassifications46
 (2) —
 44
 
Amounts reclassified from AOCI—
 6
 2
 8
 
Net OCI46
 4
 2
 52
 
Balance as of March 31, 2017$(481) $(121) $(94) $(696) 
         
Balance as of December 31, 2015$(582) $(137) $(87) $(806) 
OCI before reclassifications68
 (82) —
 (14) 
Amounts reclassified from AOCI—
 (2) 1
 (1) 
Net OCI68
 (84) 1
 (15) 
Balance as of March 31, 2016$(514) $(221) $(86) $(821) 
SDG&E:        
         
Balance as of December 31, 2016 and March 31, 2017    $(8) $(8) 
         
Balance as of December 31, 2015 and March 31, 2016    $(8) $(8) 
SoCalGas:        
         
Balance as of December 31, 2016 and March 31, 2017  $(13) $(9) $(22) 
         
Balance as of December 31, 2015 and March 31, 2016  $(14) $(5) $(19) 
(1)All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests.



CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) BY COMPONENT(1)
SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
  Three months ended March 31, 2016 and 2015
  Foreign    Total
  currency Pension and otheraccumulated other
  translationFinancialpostretirementcomprehensive
  adjustmentsinstrumentsbenefitsincome (loss)
2016:        
Balance as of December 31, 2015$(582)$(137)$(87)$(806)
Other comprehensive income (loss) before        
   reclassifications 68 (82) ― (14)
Amounts reclassified from accumulated other        
   comprehensive income ― (2) 1 (1)
Net other comprehensive income (loss) 68 (84) 1 (15)
Balance as of March 31, 2016$(514)$(221)$(86)$(821)
2015:        
Balance as of December 31, 2014$(322)$(90)$(85)$(497)
Other comprehensive loss before        
   reclassifications (62) (54) ― (116)
Amounts reclassified from accumulated other        
   comprehensive income ― (1) 1 ―
Net other comprehensive (loss) income (62) (55) 1 (116)
Balance as of March 31, 2015$(384)$(145)$(84)$(613)
(1)All amounts are net of income tax, if subject to tax, and exclude noncontrolling interests.



RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
 Amounts reclassified  
Details about accumulatedfrom accumulated other Affected line item on Condensed
other comprehensive income (loss) componentscomprehensive income (loss) Consolidated Statements of Operations
   Three months ended March 31,     
   2016 2015     
Sempra Energy Consolidated:          
Financial instruments:          
    Interest rate and foreign exchange instruments$4 $6 Interest Expense
    Interest rate instruments 3  3 Equity (Losses) Earnings, Before Income Tax
    Interest rate and foreign exchange instruments
 1  ― Equity Earnings, Net of Income Tax
    Commodity contracts not subject to rate recovery (7)  (7) Revenues: Energy-Related Businesses
Total before income tax 1  2  
    ―  1 Income Tax Expense
Net of income tax 1  3  
    (3)  (4) Earnings Attributable to Noncontrolling Interests
   $(2) $(1)     
             
Pension and other postretirement benefits:          
    Amortization of actuarial loss$2 $2 See note (1) below
    (1)  (1) Income Tax Expense
Net of income tax$1 $1  
             
Total reclassifications for the period, net of tax$(1) $―     
SDG&E:          
Financial instruments:          
    Interest rate instruments$3 $3 Interest Expense
    (3)  (3) Earnings Attributable to Noncontrolling Interest
Total reclassifications for the period$― $―     
(1)Amounts are included in the computation of net periodic benefit cost (see "Pension and Other Postretirement Benefits" above).


RECLASSIFICATIONS OUT OF ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
(Dollars in millions)
Details about accumulated other
comprehensive income (loss) components		Amounts reclassified
from accumulated other
comprehensive income (loss)		 Affected line item on Condensed
Consolidated Statements of Operations
 Three months ended March 31,  
 2017 2016  
Sempra Energy Consolidated:     
Financial instruments:     
Interest rate and foreign exchange instruments$(3) $4
 Interest Expense
Interest rate instruments2
 3
 Equity Earnings (Losses), Before Income Tax
Interest rate and foreign exchange instruments2
 1
 Equity (Losses) Earnings, Net of Income Tax
Foreign exchange instruments2
 —
 Revenues: Energy-Related Businesses
Commodity contracts not subject to rate recovery9
 (7) Revenues: Energy-Related Businesses
Total before income tax12
 1
  
 (4) —
 Income Tax Expense
Net of income tax8
 1
  
 (2) (3) Earnings Attributable to Noncontrolling Interests
 $6
 $(2)  
Pension and other postretirement benefits:     
Amortization of actuarial loss$3
 $2
 See note (1) below
 (1) (1) Income Tax Expense
Net of income tax$2
 $1
  
      
Total reclassifications for the period, net of tax$8
 $(1)  
SDG&E:     
Financial instruments:     
Interest rate instruments$3
 $3
 Interest Expense
 (3) (3) Earnings Attributable to Noncontrolling Interest
Total reclassifications for the period$—
 $—
  
(1)Amounts are included in the computation of net periodic benefit cost (see “Pension and Other Postretirement Benefits” above).

For the three months ended March 31, 20162017 and 2015, Other Comprehensive Income (Loss) (OCI), excluding amounts attributable to noncontrolling interests, at SDG&E and SoCalGas was negligible, and2016, reclassifications out of AOCI to Net Incomenet income were also negligible for SoCalGas.




SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS

The following tables provide reconciliations of changes in Sempra Energy’s, SDG&E’s and SDG&E’sSoCalGas’ shareholders’ equity and noncontrolling interests for the three months ended March 31, 20162017 and 2015. The only change in SoCalGas’ equity for the three months ended March 31, 2016 and 2015 was comprehensive income and a negligible amount of preferred stock dividends declared.2016.

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
 
Sempra Energy
shareholders’
equity(1)
 Non-
controlling
interests(2)		 Total
equity(1)
Balance at December 31, 2016$12,951
 $2,290
 $15,241
Comprehensive income493
 22
 515
Share-based compensation expense10
 —
 10
Common stock dividends declared(206) —
 (206)
Issuances of common stock30
 —
 30
Repurchases of common stock(14) —
 (14)
Distributions to noncontrolling interests—
 (7) (7)
Balance at March 31, 2017$13,264
 $2,305
 $15,569
Balance at December 31, 2015$11,809
 $770
 $12,579
Cumulative-effect adjustment from change in accounting principle107
 —
 107
Comprehensive income338
 11
 349
Share-based compensation expense13
 —
 13
Common stock dividends declared(188) —
 (188)
Issuances of common stock28
 —
 28
Repurchases of common stock(54) —
 (54)
Distributions to noncontrolling interests—
 (3) (3)
Balance at March 31, 2016$12,053
 $778
 $12,831
(1)Amounts for the three months ended March 31, 2016 reflect the adoption of ASU 2016-09 as of January 1, 2016, as we discuss in Note 2.
(2)Noncontrolling interests include the preferred stock of SoCalGas and other noncontrolling interests as listed in the table below under “Other Noncontrolling Interests.”
SHAREHOLDER’S EQUITY AND NONCONTROLLING INTEREST – SDG&E
(Dollars in millions)
 
SDG&E
shareholder’s
equity(1)
 Non-
controlling
interest		 Total
equity(1)
Balance at December 31, 2016$5,641
 $37
 $5,678
Comprehensive income155
 5
 160
Common stock dividends declared(175) —
 (175)
Distributions to noncontrolling interest—
 (3) (3)
Balance at March 31, 2017$5,621
 $39
 $5,660
Balance at December 31, 2015$5,223
 $53
 $5,276
Cumulative-effect adjustment from change in accounting principle23
 —
 23
Comprehensive income (loss)136
 (1) 135
Distributions to noncontrolling interest—
 (1) (1)
Balance at March 31, 2016$5,382
 $51
 $5,433
(1)Amounts for the three months ended March 31, 2016 reflect the adoption of ASU 2016-09 as of January 1, 2016, as we discuss in Note 2.

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
   Sempra Energy Non-  
   shareholders’ controlling Total
   equity interests(1) equity
Balance at December 31, 2015$11,809$770$12,579
Comprehensive income 304 11 315
Share-based compensation expense 13 ― 13
Common stock dividends declared (188) ― (188)
Issuances of common stock 28 ― 28
Repurchases of common stock (54) ― (54)
Tax benefit related to share-based compensation 34 ― 34
Distributions to noncontrolling interests ― (3) (3)
Balance at March 31, 2016$11,946$778$12,724
Balance at December 31, 2014$11,326$774$12,100
Comprehensive income 321 8 329
Share-based compensation expense 13 ― 13
Common stock dividends declared (173) ― (173)
Issuances of common stock 30 ― 30
Repurchases of common stock (65) ― (65)
Tax benefit related to share-based compensation 52 ― 52
Distributions to noncontrolling interests ― (5) (5)
Balance at March 31, 2015$11,504$777$12,281
(1)Noncontrolling interests include the preferred stock of SoCalGas and other noncontrolling interests as listed in the table below under "Other Noncontrolling Interests."



SHAREHOLDER'S EQUITY AND NONCONTROLLING INTEREST – SDG&E
(Dollars in millions)
  SDG&E Non-  
  shareholder’s controlling Total
  equity interest equity
Balance at December 31, 2015$5,223$53$5,276
Comprehensive income (loss) 129 (1) 128
Distributions to noncontrolling interest ― (1) (1)
Balance at March 31, 2016$5,352$51$5,403
Balance at December 31, 2014$4,932$60$4,992
Comprehensive income 147 2 149
Distributions to noncontrolling interest ― (3) (3)
Balance at March 31, 2015$5,079$59$5,138


SHAREHOLDERS’ EQUITY – SOCALGAS
(Dollars in millions)
 Total
equity(1)
Balance at December 31, 2016$3,510
Comprehensive income203
Balance at March 31, 2017$3,713
Balance at December 31, 2015$3,149
Cumulative-effect adjustment from change in accounting principle15
Comprehensive income199
Balance at March 31, 2016$3,363

(1)Amounts for the three months ended March 31, 2016 reflect the adoption of ASU 2016-09 as of January 1, 2016, as we discuss in Note 2.

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


Preferred Stock

At Sempra Energy, theThe preferred stock ofat SoCalGas is presented at Sempra Energy as a noncontrolling interest and preferred stock dividends areinterest. Sempra Energy records charges against income related to noncontrolling interests.interests for preferred stock dividends declared by SoCalGas. We provide additional information concerningregarding preferred stock in Note 11 of the Notes to Consolidated Financial Statements in the Annual Report.



Other Noncontrolling Interests

At March 31, 20162017 and December 31, 2015,2016, we reported the following noncontrolling ownership interests held by others (not including preferred shareholders) recorded in Other Noncontrolling Interests in Total Equity on Sempra Energy’s Condensed Consolidated Balance Sheets:

OTHER NONCONTROLLING INTERESTS
(Dollars in millions)  
 Percent ownership held by noncontrolling interests 
 Equity held by
noncontrolling interests
 March 31,
2017		 December 31,
2016		 March 31,
2017		 December 31,
2016
SDG&E:       
Otay Mesa VIE100%100%$39
 $37
Sempra South American Utilities:       
Chilquinta Energía subsidiaries(1)22.9 – 43.4 23.1 – 43.4 23
 22
Luz del Sur16.4 16.4 182
 173
Tecsur9.8 9.8 4
 4
Sempra Mexico:       
IEnova33.6 33.6 1,531
 1,524
Sempra Renewables:       
Tax equity arrangement – wind(2)NA  NA 93
 92
Tax equity arrangement – solar(2)NA NA 371
 376
Sempra LNG & Midstream:       
Bay Gas Storage Company, Ltd.9.1 9.1 27
 27
Liberty Gas Storage, LLC23.3 23.3 14
 14
Southern Gas Transmission Company49.0 49.0 1
 1
Total Sempra Energy    $2,285
 $2,270
(1)Chilquinta Energía has four subsidiaries with noncontrolling interests held by others. Percentage range reflects the highest and lowest ownership percentages among these subsidiaries.
(2)Net income or loss attributable to the noncontrolling interests is computed using the HLBV method and is not based on ownership percentages, as we discuss in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
OTHER NONCONTROLLING INTERESTS
(Dollars in millions)  
  Percent ownership held by others    
  March 31,December 31, March 31, December 31,
  20162015 2016 2015
SDG&E:        
   Otay Mesa VIE100%100%$51$53
Sempra South American Utilities:        
   Chilquinta Energía subsidiaries(1)23.5 – 43.4 23.5 – 43.4  22 21
   Luz del Sur16.4 16.4  171 164
   Tecsur9.8 9.8  4 4
Sempra Mexico:        
   IEnova18.9 18.9  470 468
Sempra Natural Gas:        
   Bay Gas Storage Company, Ltd.9.1 9.1  25 25
   Liberty Gas Storage, LLC23.2 23.2  14 14
   Southern Gas Transmission Company49.0 49.0  1 1
      Total Sempra Energy    $758$750
(1)Chilquinta Energía has four subsidiaries with noncontrolling interests held by others. Percentage range reflects the highest and lowest ownership percentages among these subsidiaries.



TRANSACTIONS WITH AFFILIATES

Amounts due from and to unconsolidated affiliates at Sempra Energy Consolidated, SDG&E and SoCalGas are as follows:
AMOUNTS DUE FROM (TO) UNCONSOLIDATED AFFILIATES
(Dollars in millions)
 March 31, 2016December 31, 2015
Sempra Energy Consolidated:    
Total due from various unconsolidated affiliates - current$7$6
      
Sempra South American Utilities(1):    
    Eletrans S.A. and Eletrans II S.A.:    
        4% Note(2)$76$72
    Other related party receivables 1 ―
Sempra Mexico(1):    
    Affiliate of joint venture with PEMEX:    
        Note due November 13, 2017(3) 3 3
        Note due November 14, 2018(3) 42 42
        Note due November 14, 2018(3) 34 34
        Note due November 14, 2018(3) 8 8
    Energía Sierra Juárez:    
        Note due June 15, 2018(4) 17 24
Sempra Natural Gas:    
        Cameron LNG JV 5 3
    Total due from unconsolidated affiliates - noncurrent$186$186
      
Total due to various unconsolidated affiliates - current$(13)$(14)
SDG&E:    
Total due from various unconsolidated affiliates - current$1$1
     
Sempra Energy$(35)$(34)
SoCalGas (8) (13)
Affiliate (6) (8)
    Total due to unconsolidated affiliates - current$(49)$(55)
     
 Income taxes due (to) from Sempra Energy(5)$(32)$28
SoCalGas:    
Sempra Energy(6)$―$35
SDG&E 8 13
    Total due from unconsolidated affiliates - current$8$48
      
Sempra Energy$(34)$―
    Total due to unconsolidated affiliate - current$(34)$―
      
 Income taxes due (to) from Sempra Energy(5)$(23)$1
(1)Amounts include principal balances plus accumulated interest outstanding.
(2)
 
U.S. dollar-denominated loan, at a fixed interest rate with no stated maturity date, to provide project financing for the construction of transmission lines at Eletrans S.A. and Eletrans II S.A., both of which are joint ventures at Chilquinta Energía.
(3)
 
U.S. dollar-denominated loan, at a variable interest rate based on a 30-day LIBOR plus 450 basis points (4.94 percent at March 31, 2016), to finance the Los Ramones Norte pipeline project.
(4)
 
U.S. dollar-denominated loan, at a variable interest rate based on a 30-day LIBOR plus 637.5 basis points (6.81 percent at March 31, 2016), to finance the first phase of the Energía Sierra Juárez wind project.
(5)SDG&E and SoCalGas are included in the consolidated income tax return of Sempra Energy and are allocated income tax expense from Sempra Energy in an amount equal to that which would result from each company having always filed a separate return.
(6)At December 31, 2015, net receivable included outstanding advances to Sempra Energy of $50 million at an interest rate of 0.11 percent.
AMOUNTS DUE FROM (TO) UNCONSOLIDATED AFFILIATES
(Dollars in millions)
 March 31, 2017 December 31, 2016
Sempra Energy Consolidated:   
Total due from various unconsolidated affiliates – current$24
 $26
    
Sempra South American Utilities(1):   
Eletrans S.A. and Eletrans II S.A. – 4% Note(2)$82
 $96
Other related party receivables1
 1
Sempra Mexico(1):   
Affiliate of joint venture with Ductos y Energéticos del Norte:   
Note due November 14, 2018(3)2
 2
Note due November 14, 2018(3)44
 44
Note due November 14, 2018(3)36
 35
Note due November 14, 2018(3)9
 9
Energía Sierra Juárez – Note(4)13
 14
Total due from unconsolidated affiliates – noncurrent$187
 $201
    
Total due to various unconsolidated affiliates – current$(13) $(11)
SDG&E:   
Sempra Energy(5)$—
 $3
Various affiliates—
 1
Total due from various unconsolidated affiliates – current$—
 $4
    
Sempra Energy$(28) $—
SoCalGas(9) (8)
Various affiliates(8) (7)
Total due to various unconsolidated affiliates – current$(45) $(15)
    
Income taxes due from Sempra Energy(6)$109
 $159
SoCalGas:   
Sempra Energy(7)$7
 $—
SDG&E9
 8
Total due from unconsolidated affiliates – current$16
 $8
    
Sempra Energy$—
 $(28)
Total due to unconsolidated affiliates – current$—
 $(28)
    
Income taxes due (to) from Sempra Energy(6)$(13) $5
(1)Amounts include principal balances plus accumulated interest outstanding.
(2)U.S. dollar-denominated loan, at a fixed interest rate with no stated maturity date, to provide project financing for the construction of transmission lines at Eletrans S.A. and Eletrans II S.A. (collectively, Eletrans), which is a joint venture of Chilquinta Energía.
(3)U.S. dollar-denominated loan, at a variable interest rate based on the 30-day LIBOR plus 450 basis points (5.48 percent at March 31, 2017), to finance the Los Ramones Norte pipeline.
(4)
U.S. dollar-denominated loan, at a variable interest rate based on the 30-day LIBOR plus 637.5 basis points (7.36 percent at March 31, 2017) with no stated maturity date, to finance the first phase of the Energía Sierra Juárez wind project, which is a joint venture of IEnova.
(5)At December 31, 2016, net receivable included outstanding advances to Sempra Energy of $31 million at an interest rate of 0.68 percent.
(6)SDG&E and SoCalGas are included in the consolidated income tax return of Sempra Energy and are allocated income tax expense from Sempra Energy in an amount equal to that which would result from each company having always filed a separate return.
(7)At March 31, 2017, net receivable included outstanding advances to Sempra Energy of $35 million at an interest rate of 0.95 percent.



Revenues and cost of sales from unconsolidated affiliates are as follows:
REVENUES AND COST OF SALES FROM UNCONSOLIDATED AFFILIATES
(Dollars in millions)
 Three months ended March 31,
 2017 2016
Revenues:   
Sempra Energy Consolidated$7
 $5
SDG&E2
 3
SoCalGas18
 17
Cost of Sales:   
Sempra Energy Consolidated$14
 $30
SDG&E20
 14

REVENUES AND COST OF SALES FROM UNCONSOLIDATED AFFILIATES
(Dollars in millions)
 Three months ended March 31,
 20162015
REVENUES    
    Sempra Energy Consolidated$5$8
    SDG&E 3 3
    SoCalGas 17 19
COST OF SALES    
    Sempra Energy Consolidated$30$19
    SDG&E 14 5


Guarantees

Sempra Energy has provided guarantees to certain of its solar and wind farm joint ventures and entered into completion guarantees related to the financing of the Cameron LNG JV project, as we discuss above in Note 4 above and in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.




OTHER INCOME, NET

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

OTHER INCOME, NET  
(Dollars in millions)  
 Three months ended March 31,
 2017 2016
Sempra Energy Consolidated:   
Allowance for equity funds used during construction$72
 $27
Investment gains(1)16
 10
Gains on interest rate and foreign exchange instruments, net63
 3
Foreign currency transaction gains (losses)10
 (2)
Sale of other investments—
 1
Electrical infrastructure relocation income(2)—
 1
Regulatory interest, net(3)2
 2
Sundry, net6
 7
Total$169
 $49
SDG&E:   
Allowance for equity funds used during construction$15
 $11
Regulatory interest, net(3)2
 2
Sundry, net1
 1
Total$18
 $14
SoCalGas:   
Allowance for equity funds used during construction$11
 $10
Total$11
 $10
(1)Represents investment gains on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans, recorded in Operation and Maintenance on the Condensed Consolidated Statements of Operations.
(2)Income at Luz del Sur associated with the relocation of electrical infrastructure.
(3)Interest on regulatory balancing accounts.
INCOME TAXES
OTHER INCOME, NET  
(Dollars in millions)  
  Three months ended March 31,
  20162015
Sempra Energy Consolidated:    
Allowance for equity funds used during construction$27$27
Investment gains(1) 10 9
Electrical infrastructure relocation income(2) 1 ―
Gains on interest rate and foreign exchange instruments, net 3 ―
Sale of other investments 1 ―
Foreign currency transaction losses (2) (1)
Regulatory interest, net(3) 2 1
Sundry, net 7 3
   Total$49$39
SDG&E:    
Allowance for equity funds used during construction$11$8
Regulatory interest, net(3) 2 1
Sundry, net 1 ―
   Total$14$9
SoCalGas:    
Allowance for equity funds used during construction$10$9
Sundry, net ― (1)
   Total$10$8
(1)Represents investment gains on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans.
(2)Income at Luz del Sur associated with the relocation of electrical infrastructure.
(3)Interest on regulatory balancing accounts.
INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
 
Income tax
expense
 
Effective
income tax rate
 
Income tax
expense
 
Effective
income tax rate
 Three months ended March 31,
 2017 2016(1)
Sempra Energy Consolidated$295
 39% $108
 24%
SDG&E90
 36
 65
 32
SoCalGas98
 33
 83
 29


(1)Reflects the adoption of ASU 2016-09 as of January 1, 2016, as we discuss in Note 2.


INCOME TAXES


INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
     Effective    Effective 
   Income tax income  Income tax  income 
   expense tax rate  expense tax rate 
   Three months ended March 31,
   20162015
Sempra Energy Consolidated$142 31%$163 27%
SDG&E 72 36  88 37 
SoCalGas 87 31  95 31 
    

Sempra Energy, SDG&E and SoCalGas record income taxes for interim periods utilizing a forecasted effective tax rate anticipated for the full year, as required by U.S. GAAP. The income tax effect of items that can be reliably forecasted is factored into the forecasted effective tax rate, and the impact is recognized proportionately over the year. Items that cannot be reliably forecasted (e.g., foreign currency translation and inflation adjustments, remeasurement of deferred tax asset valuation allowances, income tax expense or benefit associated with the gain or loss on sale or impairment of a book investment, resolution of prior years’ income tax items, remeasurementand certain impacts of deferred tax asset valuation allowances, Mexican currency translation and inflation adjustments, and deferred income tax benefit associated with the impairment of a book investment)regulatory matters) are recorded in the interim period in which they actually occur, which can result in variability in the effective income tax expense.
rate.
Sempra Energy’s income tax expense infor the three months ended March 31, 2017 and 2016 includes deferred income tax expense related to Sempra Mexico’s power plant held for sale, as we discuss in Note 3.
For SDG&E and SoCalGas, the California Public Utilities Commission (CPUC) requires flow-through rate-making treatment for the current income tax benefit or expense arising from certain property-related and other temporary differences between the treatment for financial reporting and income tax, which will reverse over time. Under the regulatory accounting treatment required for these flow-throughflo


w-through temporary differences, deferred income tax assets and liabilities are not recorded to deferred income tax expense, but rather to a regulatory asset or liability, which impacts the current effective income tax rate. As a result, changes in the relative size of these items compared to pretax income, from period to period, can cause variations in the effective income tax rate. The following items are subject to flow-through treatment:
§  
▪repairs expenditures related to a certain portion of utility plant assets
§  
▪the equity portion of AFUDC
§  
▪a portion of the cost of removal of utility plant assets
§  
▪utility self-developed software expenditures
§  
▪depreciation on a certain portion of utility plant assets
§  
▪state income taxes
The AFUDC related to equity recorded for regulated construction projects at Sempra Mexico has similar flow-through treatment.
As we discuss in Note 10 below and in Notes 6 and 14 of the Notes to Consolidated Financial Statements in the Annual Report, the final decision in the 2016 General Rate Case (2016 GRC FD) was issued by the CPUC in June 2016 and required SDG&E and SoCalGas to each establish a two-way income tax expense memorandum account to track any revenue variances resulting from certain differences arising between the income tax expense forecasted in the 2016 GRC and the income tax expense incurred from 2016 through 2018. The tracking accounts will remain open until the CPUC decides to close them. We expect that certain amounts recorded in the tracking accounts may give rise to regulatory assets or liabilities.
We provide additional information about our accounting for income taxes in Notes 1 and 6 of the Notes to Consolidated Financial Statements in the Annual Report.


NOTE 6. DEBT AND CREDIT FACILITIES


LINES OF CREDIT

At March 31, 2016,2017, Sempra Energy Consolidated had an aggregate of $4.2$4.3 billion in three primary committed lines of credit for Sempra Energy, Sempra Global and the California Utilities to provide liquidity and to support commercial paper,paper. The principal terms of these committed lines of credit, which expire in October 2020, are described below and in Note 5 of the major components of which we detail below.Notes to Consolidated Financial Statements in the Annual Report. Available unused credit on these lines at March 31, 20162017 was approximately $3.1$2.7 billion. Our foreign operations have additional general purpose credit facilities aggregating $1.1$1.7 billion at March 31, 2016.2017. Available unused credit on these lines totaled $876 million$1 billion at March 31, 2016.2017.

PRIMARY U.S. COMMITTED LINES OF CREDIT      
(Dollars in millions)      
   At March 31, 2017
   Total facility Commercial paper outstanding Adjustment for combined limit Letters of credit outstanding Available unused credit
Sempra Energy(1) $1,000
 $—
 $—
 $(65) $935
Sempra Global(2) 2,335
 (1,197) —
 —
 1,138
California Utilities(3):          
 SDG&E 750
 (343) —
 —
 407
 SoCalGas 750
 —
 (93) —
 657
 Less: combined limit of $1 billion for both utilities (500) —
 93
 —
 (407)
   1,000
 (343) —
 —
 657
Total $4,335
 $(1,540) $—
 $(65) $2,730
Sempra Energy

Sempra Energy has a $1 billion, five-year syndicated revolving credit agreement expiring in October 2020. Citibank, N.A. serves as administrative agent for the syndicate of 20 lenders, and no single lender has greater than a 7-percent share.
Borrowings bear interest at benchmark rates plus a margin that varies with Sempra Energy’s credit ratings. The facility requires Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. At March 31, 2016, Sempra Energy was in compliance with this and all other financial covenants under the credit facility.(1) The facility also provides for issuance of up to $400 million of letters of credit on behalf of Sempra Energy with the amount of borrowings
otherwise available under the facility reduced by the amount of outstanding letters of credit.
At March 31, 2016, Sempra Energy had no outstanding borrowings or letters of credit supported by the facility.


Sempra Global

Sempra Global has a $2.21 billion, five-year syndicated revolving credit agreement expiring in October 2020. Citibank, N.A. serves as administrative agent for the syndicate of 20 lenders, and no single lender has greater than a 7-percent share.
(2) Sempra Energy guarantees Sempra Global’s obligations under the credit facility. Borrowings bear interest at benchmark rates plus a margin that varies with Sempra Energy’s credit ratings.
(3) The facility requires Sempra Energy to maintain a ratio of total indebtedness to total capitalization (as defined in the agreement) of no more than 65 percent at the end of each quarter. At March 31, 2016, Sempra Energy was in compliance with this and all other financial covenants under the credit facility.
At March 31, 2016, Sempra Global had $879 million of commercial paper outstanding supported by the facility and $1.33 billion of available unused credit on the line.


California Utilities

SDG&E and SoCalGas have a combined $1 billion, five-year syndicated revolving credit agreement expiring in October 2020. JPMorgan Chase Bank, N.A. serves as administrative agent for the syndicate of 20 lenders, and no single lender has greater than a 7-percent share. The agreement permits each utility to individually borrow up to $750 million, subject to a combined limit of $1 billion for both utilities. It also provides for the issuance of letters of credit on behalf of each utility subject to a combined letter of credit commitment of $250 million for both utilities. The amount of borrowings otherwise available under the facility is reduced by the amount of outstanding letters of credit.

Borrowings bear interest at benchmark rates plus a margin that varies with the borrowing utility’s credit rating. The agreement requires each utility to

Sempra Energy, SDG&E and SoCalGas must maintain a ratio of total indebtedness to total capitalization (as defined in theeach agreement) of no more than 65 percent at the end of each quarter. At March 31, 2016, the California Utilities wereEach entity is in compliance with this and all other financial covenants under theits respective credit facility.
Each utility’s obligations under the agreement are individual obligations, and a default by one utility would not constitute a default by the other utility or preclude borrowings by, or the issuance of letters of credit on behalf of, the other utility.
At March 31, 2016, SDG&E and SoCalGas had $166 million and $5 million, respectively, of commercial paper outstanding, supported by the facility. Available unused credit on the linefacility at March 31, 2016 was $584 million and $745 million at SDG&E and SoCalGas, respectively, subject to the $1 billion maximum combined credit limit.2017.


CREDIT FACILITIES IN SOUTH AMERICA AND MEXICO
(U.S. dollar equivalent in millions)     
    At March 31, 2017
  Denominated in Total facility Amount outstanding  Available unused credit
Sempra South American Utilities(1):        
 Peru(2)Peruvian sol $392
 $(155)(3) $237
 ChileChilean peso 115
 —
  115
Sempra Mexico:        
 IEnova(4)U.S. dollar 1,170
 (446)  724
Total  $1,677
 $(601)  $1,076
Sempra South American Utilities

Sempra South American Utilities has Peruvian Sol- and Chilean Peso-denominated credit facilities aggregating $547 million U.S. dollar equivalent, expiring between 2016 and 2018.(1) The credit facilities were entered into to finance working capital and for general corporate purposes.purposes and expire between 2017 and 2020.
(2) The Peruvian facilities require a debt to equity ratio of no more than 170 percent. Atpercent, with which we were in compliance at March 31, 2016, Sempra South American Utilities was in compliance with this financial covenant under the credit facilities. At March 31, 2016, Sempra South American Utilities had outstanding borrowings of $165 million and2017.
(3) Includes bank guarantees of $15 million against the Peruvian facilities, and $255 million of available unused credit. There were no outstanding borrowings at March 31, 2016 under the $112 million Chilean facility.$12 million.


Sempra Mexico

IEnova has a $600 million, five-year revolving credit agreement(4) Five-year revolver expiring in August 2020. The lenders are Banco Santander (México), S.A., Institución de Banca Múltiple, Grupo Financiero Santander México, The Bank2020 with a syndicate of Tokyo - Mitsubishi UFJ, LTD., The Bank of Nova Scotia and Sumitomo Mitsui Banking Corporation. At March 31, 2016, IEnova had $91 million of outstanding borrowings supported by the facility, and available unused credit on the line was $509 million.eight lenders.


WEIGHTED AVERAGE INTEREST RATES

The weighted average interest rates on the total short-term debt at Sempra Energy Consolidated were 1.12 percent and 1.09 percent at March 31, 2016 and December 31, 2015, respectively. At March 31, 2016, the weighted average interest rates on total short-term debt at SDG&E and SoCalGasSempra Energy Consolidated were 1.021.6 percent and 0.401.51 percent at March 31, 2017 and December 31, 2016, respectively. The weighted average interest rate on total short-term debt at SDG&E was 1.011.0 percent at March 31, 2017. At December 31, 2015.


2016, the weighted average interest rate on total short-term debt at SoCalGas was 0.75 percent.
LONG-TERM DEBT

SDG&E
Sempra South American Utilities
In April 2016, SDG&E notified bondholders that it intends to redeem, prior to maturity, certain outstanding long-term debt instruments with a total principal amountFebruary 2017, Luz del Sur publicly offered and sold $50 million of $105 million. At March 31, 2016, the debt remains classified as long-term on Sempra Energy’s and SDG&E’s Condensed Consolidated Balance Sheets. These instruments have a coupon rate of 5corporate bonds at 6.38 percent, and a maturity date of December 2027. SDG&E expects to repay the debtmaturing in the second quarter of 2016.


2023.
INTEREST RATE SWAPS

We discuss our fair value interest rate swaps and interest rate swaps to hedge cash flows in Note 7.





NOTE 7. DERIVATIVE FINANCIAL INSTRUMENTS

We use derivative instruments primarily to manage exposures arising in the normal course of business. Our principal exposures are commodity market risk, benchmark interest rate risk and foreign exchange rate exposures. Our use of derivatives for these risks is integrated into the economic management of our anticipated revenues, anticipated expenses, assets and liabilities. Derivatives may be effective in mitigating these risks (1) that could lead to declines in anticipated revenues or increases in anticipated expenses, or (2) that our asset values may fall or our liabilities increase. Accordingly, our derivative activity summarized below generally represents an impact that is intended to offset associated revenues, expenses, assets or liabilities that are not included in the tables below.
In certain cases, we apply the normal purchase or sale exception to derivative instruments and have other commodity contracts that are not derivatives. These contracts are not recorded at fair value and are therefore excluded from the disclosures below.
In all other cases, we record derivatives at fair value on the Condensed Consolidated Balance Sheets. We designate each derivative as (1) a cash flow hedge, (2) a fair value hedge, or (3) undesignated. Depending on the applicability of hedge accounting and, for the California Utilities and other operations subject to regulatory accounting, the requirement to pass impacts through to customers, the impact of derivative instruments may be offset in other comprehensive income (loss) (cash flow hedge), on the balance sheet (fair value hedges and regulatory offsets), or recognized in earnings. We classify cash flows from the settlements of derivative instruments as operating activities on the Condensed Consolidated Statements of Cash Flows.


HEDGE ACCOUNTING

We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated cash flows associated with revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity instruments, foreign currency instruments and interest rate instruments. Designating cash flow hedges is dependent on the business context in which the instrument is being used, the effectiveness of the instrument in offsetting the risk that the future cash flows of a given revenue or expense item may vary, and other criteria.
We may designate an interest rate derivative as a fair value hedging instrument if it effectively converts our own debt from a fixed interest rate to a variable rate. The combination of the derivative and debt instrument results in fixing that portion of the fair value of the debt that is related to benchmark interest rates. Designating fair value hedges is dependent on the instrument being used, the effectiveness of the instrument in offsetting changes in the fair value of our debt instruments, and other criteria.

ENERGY DERIVATIVES
Our market risk is primarily related to natural gas and electricity price volatility and the specific physical locations where we transact. We use energy derivatives to manage these risks. The use of energy derivatives in our various businesses depends on the particular energy market, and the operating and regulatory environments applicable to the business, as follows:
§  
▪The California Utilities use energy derivatives, both natural gas and electricity derivatives, for the benefit of customers, with the objective of managing price risk and basis risks, and stabilizing and lowering natural gas and electricity costs. These derivatives include fixed price natural gas and electricity positions, options, and basis risk instruments, which are either exchange-traded or over-the-counter financial instruments, or bilateral physical transactions. This activity is governed by risk management and transacting activity plans that have been filed with and approved by the CPUC. Natural gas and electricity derivative activities are recorded as commodity costs that are offset by regulatory account balances and are recovered in rates. Net commodity cost impacts on the Condensed Consolidated Statements of Operations are reflected in Cost of Electric Fuel and Purchased Power or in Cost of Natural Gas.
§  
▪SDG&E is allocated and may purchase congestion revenue rights (CRRs), which serve to reduce the regional electricity price volatility risk that may result from local transmission capacity constraints. Unrealized gains and losses do not impact earnings, as they are offset by regulatory account balances. Realized gains and losses associated with CRRs, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations.
§  
▪Sempra Mexico, Sempra LNG & Midstream, and Sempra Natural GasRenewables may use natural gas and electricity derivatives, as appropriate, to optimize the earnings of their assets which support the following businesses: liquefied natural gas (LNG), natural gas transportation and storage, and power generation, and Sempra Natural Gas’ storage.generation. Gains and losses associated with undesignated derivatives are recognized in Energy-Related Businesses Revenues or in Cost of Natural Gas, Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations. Certain of these derivatives may also be designated as cash flow hedges. Sempra Mexico also uses natural gas energy derivatives with the objective of managing price risk and lowering natural gas prices at its Mexican distribution operations. These derivatives, which are recorded as commodity costs that are offset by regulatory account balances and recovered in rates, are recognized in Cost of Natural Gas on the Condensed Consolidated Statements of Operations.


distribution operations. These derivatives, which are recorded as commodity costs that are offset by regulatory account balances and recovered in rates, are recognized in Cost of Natural Gas on the Condensed Consolidated Statements of Operations.
§  
▪From time to time, our various businesses, including the California Utilities, may use other energy derivatives to hedge exposures such as the price of vehicle fuel.
We summarize net energy derivative volumes at March 31, 20162017 and December 31, 20152016 as follows:
NET ENERGY DERIVATIVE VOLUMES
(Quantities in millions)
CommodityUnit of measure March 31,
2017		 December 31,
2016
California Utilities:     
SDG&E:     
Natural gasMMBtu(1) 44
 48
ElectricityMWh(2) 4
 4
Congestion revenue rightsMWh 45
 48
SoCalGas – natural gasMMBtu —
 1
      
Energy-Related Businesses:     
Sempra LNG & Midstream – natural gasMMBtu 16
 31
(1)Million British thermal units
(2)Megawatt hours
NET ENERGY DERIVATIVE VOLUMES
(Quantities in millions)
    March 31,December 31,
Segment and CommodityUnit of measure20162015
California Utilities:   
    SDG&E:   
        Natural gasMMBtu(1)6070
        ElectricityMWh(2)―1
        Congestion revenue rightsMWh3336
    SoCalGas – natural gasMMBtu―1
      
Energy-Related Businesses:   
    Sempra Natural Gas – natural gasMMBtu3943
(1)Million British thermal units
(2)Megawatt hours


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


INTEREST RATE DERIVATIVES

We are exposed to interest rates primarily as a result of our current and expected use of financing. WeThe California Utilities, as well as other Sempra Energy subsidiaries and joint ventures, periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. We may utilize interest rate swaps typically designated as fair value hedges, as a means to achieve our targeted level of variable rate debt as a percent of total debt. In addition, we may utilize interest rate swaps, typically designated as cash flow hedges, to lock in interest rates on outstanding debt or in anticipation of future financings.
Interest rate derivatives are utilized by the California Utilities as well as by other Sempra Energy subsidiaries. Interest rate derivatives are generally accounted for as hedges, and although the California Utilities generally recover borrowing costs in rates over time, the use of interest rate derivatives is subject to certain regulatory constraints, and the impact of interest rate derivatives may not be recovered from customers as timely as described above with regard to energy derivatives. Separately, Otay Mesa VIE has entered into interest rate swap agreements, designated as cash flow hedges, to moderate its exposure to interest rate changes.

At March 31, 20162017 and December 31, 2015,2016, the net notional amounts of our interest rate derivatives, excluding the cross-currency swaps discussed below,joint ventures, were:
INTEREST RATE DERIVATIVES
(Dollars in millions)
 March 31, 2017 December 31, 2016
 Notional debt Maturities Notional debt Maturities
Sempra Energy Consolidated:       
Cash flow hedges(1)$910
 2017-2032 $924
 2017-2032
SDG&E:       
Cash flow hedges(1)302
 2017-2019 305
 2017-2019
INTEREST RATE DERIVATIVES
(Dollars in millions)
  March 31, 2016December 31, 2015
 Notional debtMaturitiesNotional debtMaturities
Sempra Energy Consolidated:      
    Cash flow hedges(1)$3812016-2028$3842016-2028
    Fair value hedges 3002016 3002016
SDG&E:      
    Cash flow hedge(1) 3122016-2019 3152016-2019
(1)Includes Otay Mesa VIE. All of SDG&E’s interest rate derivatives relate to Otay Mesa VIE.

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

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


We are also exposed to exchange rate movements at our Mexican subsidiaries and joint ventures, which have U.S. dollar denominated cash balances, receivables, payables and debt (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. They also have deferred income tax assets and liabilities denominated in the Mexican peso, which must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities and certain nonmonetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes. We utilize foreign currency derivatives as a means to manage the risk of exposure to significant fluctuations in our income tax expense and equity earnings from these impacts. In January 2016,impacts, however we entered into foreign currency derivatives with a notional amount totaling $550 million.

At March 31, 2016generally do not hedge our deferred income tax assets and December 31, 2015, the net notional amounts of our foreign currency derivatives were:
FOREIGN CURRENCY DERIVATIVES
(Dollars in millions)
  March 31, 2016December 31, 2015
 Notional debtMaturitiesNotional debtMaturities
Sempra Mexico:      
    Cross-currency swaps$4082018-2023$4082018-2023
    Other foreign currency derivatives 5502016 ――

liabilities.
In addition, Sempra South American Utilities and its joint ventures use foreign currency derivatives at its subsidiaries and joint ventures as a means to manage foreign currency rate risk. We discuss such swapsthese derivatives at Chilquinta Energía’s Eletrans joint venture investment in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.
At March 31, 2017 and December 31, 2016, the net notional amounts of our foreign currency derivatives, excluding joint ventures, were:


FOREIGN CURRENCY DERIVATIVES
(Dollars in millions)
 March 31, 2017 December 31, 2016
 Notional amount Maturities Notional amount Maturities
Sempra Energy Consolidated:       
Cross-currency swaps$408
 2017-2023 $408
 2017-2023
Other foreign currency derivatives(1)922
 2017-2018 86
 2017-2018
(1)In the three months ended March 31, 2017, we entered into foreign currency derivatives with notional amounts totaling $850 million that expire in December 2017.
FINANCIAL STATEMENT PRESENTATION

EachThe Condensed Consolidated Balance Sheet reflectsSheets reflect the offsetting of net derivative positions and cash collateral with the same counterparty when a legal right of offset exists. The following tables provide the fair values of derivative instruments on the Condensed Consolidated Balance Sheets at March 31, 20162017 and December 31, 2015,2016, including the amount of cash collateral receivables that were not offset, as the cash collateral is in excess of liability positions.


DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
 March 31, 2017
 Current
assets:
Fixed-price
contracts
and other
derivatives(1)		 Other
assets:
Sundry		 Current liabilities:
Fixed-price
contracts
and other
derivatives(2)		 Deferred
credits
and other
liabilities:
Fixed-price
contracts
and other
derivatives
Sempra Energy Consolidated:       
Derivatives designated as hedging instruments:       
Interest rate and foreign exchange instruments(3)$—
 $1
 $(56) $(155)
Derivatives not designated as hedging instruments:       
Foreign exchange instruments98
 —
 —
 —
Commodity contracts not subject to rate recovery67
 31
 (60) (21)
Associated offsetting commodity contracts(54) (21) 54
 21
Commodity contracts subject to rate recovery25
 71
 (60) (163)
Associated offsetting commodity contracts(4) —
 4
 —
Associated offsetting cash collateral—
 —
 9
 15
Net amounts presented on the balance sheet132
 82
 (109) (303)
Additional cash collateral for commodity contracts
not subject to rate recovery
9
 —
 —
 —
Additional cash collateral for commodity contracts
subject to rate recovery
20
 —
 —
 —
Total(4)$161
 $82
 $(109) $(303)
SDG&E:       
Derivatives designated as hedging instruments:       
Interest rate instruments(3)$—
 $—
 $(13) $(9)
Derivatives not designated as hedging instruments:       
Commodity contracts subject to rate recovery23
 71
 (59) (163)
Associated offsetting commodity contracts(4) —
 4
 —
Associated offsetting cash collateral—
 —
 9
 15
Net amounts presented on the balance sheet19
 71
 (59) (157)
Additional cash collateral for commodity contracts
not subject to rate recovery
1
 —
 —
 —
Additional cash collateral for commodity contracts
subject to rate recovery
19
 —
 —
 —
Total(4)$39
 $71

$(59)
$(157)
SoCalGas:       
Derivatives not designated as hedging instruments:       
Commodity contracts subject to rate recovery$2
 $—
 $(1) $—
Net amounts presented on the balance sheet2
 —
 (1) —
Additional cash collateral for commodity contracts
subject to rate recovery
1
 —
 —
 —
Total$3
 $—
 $(1) $—
(1)Included in Current Assets: Other for SoCalGas.
(2)Included in Current Liabilities: Other for SoCalGas.
(3)Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.
(4)Normal purchase contracts previously measured at fair value are excluded.


DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS(Dollars in millions)
 March 31, 2016
        Deferred
        credits
  Current   Current and other
  assets:   liabilities: liabilities:
  Fixed-price   Fixed-price Fixed-price
  contracts Other contracts contracts
  and other assets: and other and otherDecember 31, 2016
 derivatives(1) Sundry derivatives(2) derivativesCurrent
assets:
Fixed-price
contracts
and other
derivatives(1)		 Other
assets:
Sundry		 Current liabilities:
Fixed-price
contracts
and other
derivatives(2)		 Deferred
credits
and other
liabilities:
Fixed-price
contracts
and other
derivatives
Sempra Energy Consolidated:Sempra Energy Consolidated:               
Derivatives designated as hedging instruments:Derivatives designated as hedging instruments:               
Interest rate and foreign exchange instruments(3) Interest rate and foreign exchange instruments(3)$5$―$(15)$(166)$7
 $2
 $(24) $(228)
Commodity contracts not subject to rate recovery—
 —
 (14) —
Derivatives not designated as hedging instruments:Derivatives not designated as hedging instruments:               
Interest rate and foreign exchange instruments 3 ― ― ―
Commodity contracts not subject to rate recovery Commodity contracts not subject to rate recovery 144 20 (144) (9)248
 36
 (254) (28)
Associated offsetting commodity contracts Associated offsetting commodity contracts (135) (9) 135 9(242) (27) 242
 27
Associated offsetting cash collateral Associated offsetting cash collateral ― ― 7 ―—
 (1) 16
 1
Commodity contracts subject to rate recovery Commodity contracts subject to rate recovery 23 51 (68) (61)37
 73
 (57) (150)
Associated offsetting commodity contracts Associated offsetting commodity contracts (4) (1) 4 1(9) (1) 9
 1
Associated offsetting cash collateral Associated offsetting cash collateral ― ― 31 24—
 —
 5
 13
Net amounts presented on the balance sheet Net amounts presented on the balance sheet 36 61 (50) (202)41
 82
 (77) (364)
Additional cash collateral for commodity contracts        
not subject to rate recovery 20 ― ― ―
Additional cash collateral for commodity contracts        
subject to rate recovery 32 ― ― ―
Additional cash collateral for commodity contracts
not subject to rate recovery
10
 —
 —
 —
Additional cash collateral for commodity contracts
subject to rate recovery
32
 —
 —
 —
Total(4) Total(4)$88$61$(50)$(202)$83
 $82
 $(77) $(364)
SDG&E:SDG&E:               
Derivatives designated as hedging instruments:Derivatives designated as hedging instruments:               
Interest rate instruments(3) Interest rate instruments(3)$―$―$(14)$(25)$—
 $—
 $(13) $(12)
Derivatives not designated as hedging instruments:Derivatives not designated as hedging instruments:               
Commodity contracts not subject to rate recovery ― ― (1) ―
Associated offsetting cash collateral ― ― 1 ―
Commodity contracts subject to rate recovery Commodity contracts subject to rate recovery 20 51 (65) (61)33
 73
 (51) (150)
Associated offsetting commodity contracts Associated offsetting commodity contracts (2) (1) 2 1(6) (1) 6
 1
Associated offsetting cash collateral Associated offsetting cash collateral ― ― 31 24—
 —
 3
 13
Net amounts presented on the balance sheet Net amounts presented on the balance sheet 18 50 (46) (61)27
 72
 (55) (148)
Additional cash collateral for commodity contracts        
not subject to rate recovery 2 ― ― ―
Additional cash collateral for commodity contracts        
subject to rate recovery 30 ― ― ―
Additional cash collateral for commodity contracts
not subject to rate recovery
1
 —
 —
 —
Additional cash collateral for commodity contracts
subject to rate recovery
30
 —
 —
 —
Total(4) Total(4)$50$50$(46)$(61)$58
 $72
 $(55) $(148)
SoCalGas:SoCalGas:               
Derivatives not designated as hedging instruments:Derivatives not designated as hedging instruments:               
Commodity contracts not subject to rate recovery$―$―$(1)$―
Associated offsetting cash collateral ― ― 1 ―
Commodity contracts subject to rate recovery Commodity contracts subject to rate recovery 3 ― (3) ―$4
 $—
 $(6) $—
Associated offsetting commodity contracts Associated offsetting commodity contracts (2) ― 2 ―(3) —
 3
 —
Associated offsetting cash collateral—
 —
 2
 —
Net amounts presented on the balance sheet Net amounts presented on the balance sheet 1 ― (1) ―1
 —
 (1) —
Additional cash collateral for commodity contracts        
not subject to rate recovery 1 ― ― ―
Additional cash collateral for commodity contracts        
subject to rate recovery 2 ― ― ―
Additional cash collateral for commodity contracts
not subject to rate recovery
1
 —
 —
 —
Additional cash collateral for commodity contracts
subject to rate recovery
2
 —
 —
 —
Total Total$4$―$(1)$―$4
 $—
 $(1) $—
(1)Included in Current Assets: Other for SoCalGas.        
(2)Included in Current Liabilities: Other for SoCalGas.        
(3)Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.      
(4)Normal purchase contracts previously measured at fair value are excluded.      
(1) Included in Current Assets: Other for SoCalGas.
(2) Included in Current Liabilities: Other for SoCalGas.
(3) Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.
(4) Normal purchase contracts previously measured at fair value are excluded.




DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
  December 31, 2015
         Deferred
         credits
   Current   Current and other
   assets:   liabilities: liabilities:
   Fixed-price   Fixed-price Fixed-price
   contracts Other contracts contracts
   and other assets: and other and other
  derivatives(1) Sundry derivatives(2) derivatives
Sempra Energy Consolidated:        
Derivatives designated as hedging instruments:        
    Interest rate and foreign exchange instruments(3)$4$1$(15)$(156)
    Commodity contracts not subject to rate recovery 13 ― ― ―
Derivatives not designated as hedging instruments:        
    Commodity contracts not subject to rate recovery 245 32 (239) (21)
        Associated offsetting commodity contracts (232) (20) 232 20
        Associated offsetting cash collateral (6) ― 4 ―
    Commodity contracts subject to rate recovery 28 49 (61) (64)
        Associated offsetting commodity contracts (2) (2) 2 2
        Associated offsetting cash collateral ― ― 28 26
    Net amounts presented on the balance sheet 50 60 (49) (193)
    Additional cash collateral for commodity contracts        
        not subject to rate recovery 2 ― ― ―
    Additional cash collateral for commodity contracts        
        subject to rate recovery 28 ― ― ―
    Total(4)$80$60$(49)$(193)
SDG&E:        
Derivatives designated as hedging instruments:        
    Interest rate instruments(3)$―$―$(14)$(23)
Derivatives not designated as hedging instruments:        
    Commodity contracts not subject to rate recovery ― ― (1) ―
        Associated offsetting cash collateral ― ― 1 ―
    Commodity contracts subject to rate recovery 27 49 (60) (64)
        Associated offsetting commodity contracts (2) (2) 2 2
        Associated offsetting cash collateral ― ― 28 26
    Net amounts presented on the balance sheet 25 47 (44) (59)
    Additional cash collateral for commodity contracts        
        not subject to rate recovery 1 ― ― ―
    Additional cash collateral for commodity contracts        
        subject to rate recovery 27 ― ― ―
    Total(4)$53$47$(44)$(59)
SoCalGas:        
Derivatives not designated as hedging instruments:        
    Commodity contracts not subject to rate recovery$―$―$(1)$―
        Associated offsetting cash collateral ― ― 1 ―
    Commodity contracts subject to rate recovery 1 ― (1) ―
    Net amounts presented on the balance sheet 1 ― (1) ―
    Additional cash collateral for commodity contracts        
        subject to rate recovery 1 ― ― ―
    Total$2$―$(1)$―
(1)Included in Current Assets: Other for SoCalGas.        
(2)Included in Current Liabilities: Other for SoCalGas.        
(3)Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.      
(4)Normal purchase contracts previously measured at fair value are excluded.      


The table below includes the effects of derivative instruments designated as fair value hedges on the Condensed Consolidated Statement of Operations for the three months ended March 31, 2016. There were no fair value hedges outstanding during the three months ended March 31, 2017.
FAIR VALUE HEDGE IMPACTS
(Dollars in millions)
   Pretax gain on derivatives recognized in earnings
   Three months ended
  LocationMarch 31, 2016
Sempra Energy Consolidated:  
Interest rate instruments(1)Interest Expense$2
    
(1)There was no hedge ineffectiveness in the three months ended March 31, 2016. All other changes in the fair value of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt and recorded in Other Income, Net.


The table below includes the effects of derivative instruments designated as cash flow hedges on the Condensed Consolidated Statements of Operations and in OCI and AOCI for the three months ended March 31 were:31:

CASH FLOW HEDGE IMPACTS
(Dollars in millions)
 
Pretax gain (loss)
recognized in OCI
   
Pretax gain (loss) reclassified
from AOCI into earnings
 Three months ended March 31,   Three months ended March 31,
 2017 2016 Location 2017 2016
Sempra Energy Consolidated:         
Interest rate and foreign
exchange instruments(1)		$16
 $(11) Interest Expense $3
 $(4)
Interest rate instruments(5) (137) Equity Earnings (Losses),
Before Income Tax		 (2) (3)
Interest rate and foreign
exchange instruments		(9) (18) 
Equity (Losses) Earnings,
Net of Income Tax
 (2) (1)
Foreign exchange instruments(9) —
 Revenues: Energy-
Related Businesses		 (2) —
Commodity contracts not subject
to rate recovery		3
 1
 Revenues: Energy-
Related Businesses		 (9) 7
Total(2)$(4) $(165)   $(12) $(1)
SDG&E:         
Interest rate instruments(1)(2)$—
 $(5) Interest Expense $(3) $(3)
(1)Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.
(2)There was negligible hedge ineffectiveness related to these cash flow hedges in the three months ended March 31, 2017 and 2016.
FAIR VALUE HEDGE IMPACTS
(Dollars in millions)
   Pretax gain on derivatives
   recognized in earnings
   Three months ended March 31,
 Location20162015
Sempra Energy Consolidated:     
    Interest rate instrumentsInterest Expense$2$2
    Interest rate instrumentsOther Income, Net ― 1
    Total(1) $2$3
(1)There was no hedge ineffectiveness in either the three months ended March 31, 2016 or 2015. All other changes in the fair values of the interest rate swap agreements are exactly offset by changes in the fair value of the underlying long-term debt and recorded in Other Income, Net.


CASH FLOW HEDGE IMPACTS
(Dollars in millions)
  Pretax (loss) gain  Pretax (loss) gain reclassified
  recognized in OCI  from AOCI into earnings
  (effective portion)  (effective portion)
  Three months ended March 31,  Three months ended March 31,
 20162015 Location20162015
Sempra Energy Consolidated:          
    Interest rate and foreign          
        exchange instruments(1)$(11)$(18) Interest Expense$(4)$(6)
      Equity (Losses) Earnings,    
    Interest rate instruments (137) (78)     Before Income Tax (3) (3)
    Interest rate and foreign     Equity Earnings,    
        exchange instruments (18) ―     Net of Income Tax (1) ―
    Commodity contracts not     Revenues: Energy-Related    
        subject to rate recovery 1 (1)     Businesses 7 7
    Total(2)$(165)$(97)  $(1)$(2)
SDG&E:          
    Interest rate instruments(1)(2)$(5)$(5) Interest Expense$(3)$(3)
(1)Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE.
(2)Amounts include negligible hedge ineffectiveness in the three months ended March 31, 2016 and 2015.


For Sempra Energy Consolidated, we expect that lossesnet gains of $21$12 million, which are net of income tax expense, that are currently recorded in AOCI (including $11 million of losses in noncontrolling interests related to Otay Mesa VIE at SDG&E) related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings. SoCalGas expects that negligible losses, net of income tax benefit, that are currently recorded in AOCI (including $12 million in noncontrolling interests, substantially all of which is related to Otay Mesa VIE at SDG&E) related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings. Actual amounts ultimately reclassified into earnings depend on the interest rates in effect when derivative contracts that are currently outstanding mature.

SoCalGas expects that negligible losses, which are net of income tax benefit, that are currently recorded in AOCI related to cash flow hedges will be reclassified into earnings during the next twelve months as the hedged items affect earnings.
For all forecasted transactions, the maximum remaining term over which we are hedging exposure to the variability of cash flows at March 31, 20162017 is approximately 1315 years and 32 years for Sempra Energy Consolidated and SDG&E, respectively. The maximum remaining term for which we are hedging exposure to the variability of cash flows at our equity method investees is 1918 years.


The effects of derivative instruments not designated as hedging instruments on the Condensed Consolidated Statements of Operations for the three months ended March 31 were:



UNDESIGNATED DERIVATIVE IMPACTS
(Dollars in millions)
  Pretax gain (loss) on derivatives recognized in earnings
  Three months ended
March 31,
 Location2017 2016
Sempra Energy Consolidated:    
Foreign exchange instrumentsOther Income, Net$65
 $3
Foreign exchange instruments
Equity (Losses) Earnings,
Net of Income Tax
—
 2
Commodity contracts not subject
to rate recovery
Revenues: Energy-Related
Businesses
14
 (1)
Commodity contracts not subject
to rate recovery
Operation and Maintenance(1) —
Commodity contracts subject
to rate recovery
Cost of Electric Fuel
and Purchased Power
(29) (12)
Commodity contracts subject
to rate recovery
Cost of Natural Gas—
 (1)
Total $49
 $(9)
SDG&E:    
Commodity contracts subject
to rate recovery
Cost of Electric Fuel
and Purchased Power
$(29) $(12)
SoCalGas:    
Commodity contracts not subject
to rate recovery
Operation and Maintenance$(1) $—
Commodity contracts subject
to rate recovery
Cost of Natural Gas—
 (1)
Total $(1) $(1)
UNDESIGNATED DERIVATIVE IMPACTS
(Dollars in millions)
   Pretax gain (loss) on derivatives
   recognized in earnings
   Three months ended March 31,
 Location20162015
Sempra Energy Consolidated:     
    Foreign exchange instrumentsOther Income, Net$3$―
    Foreign exchange instrumentsEquity Earnings,    
     Net of Income Tax 2 (1)
    Commodity contracts not subjectRevenues: Energy-Related    
        to rate recovery    Businesses (1) 3
    Commodity contracts subjectCost of Electric Fuel    
        to rate recovery    and Purchased Power (12) (20)
    Commodity contracts subject     
        to rate recoveryCost of Natural Gas (1) 1
    Total $(9)$(17)
SDG&E:     
    Commodity contracts subjectCost of Electric Fuel    
        to rate recovery    and Purchased Power$(12)$(20)
SoCalGas:     
    Commodity contracts subject     
        to rate recoveryCost of Natural Gas$(1)$1


CONTINGENT FEATURES

For Sempra Energy Consolidated and SDG&E, certain of our derivative instruments contain credit limits which vary depending on our credit ratings. Generally, these provisions, if applicable, may reduce our credit limit if a specified credit rating agency reduces our ratings. In certain cases, if our credit ratings were to fall below investment grade, the counterparty to these derivative liability instruments could request immediate payment or demand immediate and ongoing full collateralization. 
For Sempra Energy Consolidated, the total fair value of this group of derivative instruments in a net liability position is $6 million at both March 31, 20162017 and December 31, 2015.2016 is $7 million and $10 million, respectively. At March 31, 2016,2017, if the credit ratings of Sempra Energy were reduced below investment grade, $7$10 million of additional assets could be required to be posted as collateral for these derivative contracts.
For SDG&E, the total fair value of this group of derivative instruments in a net liability position is $5$1 million at both March 31, 20162017 and negligible at December 31, 2015.2016. At March 31, 2016,2017, if the credit ratings of SDG&E were reduced below investment grade, $6$4 million of additional assets could be required to be posted as collateral for these derivative contracts.
For Sempra Energy Consolidated, SDG&E and SoCalGas, some of our derivative contracts contain a provision that would permit the counterparty, in certain circumstances, to request adequate assurance of our performance under the contracts. Such additional assurance, if needed, is not material and is not included in the amounts above.






NOTE 8. FAIR VALUE MEASUREMENTS

We discuss the valuation techniques and inputs we use to measure fair value and the definition of the three levels of the fair value hierarchy in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. We have not changed the valuation techniques or types of inputs we use to measure fair value during the three months ended March 31, 2016.
RECURRING FAIR VALUE MEASURES

Recurring Fair Value Measures
The three tables below, by level within the fair value hierarchy, set forth our financial assets and liabilities that were accounted for at fair value on a recurring basis at March 31, 20162017 and December 31, 2015.2016. We classify financial assets and liabilities in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities, and their placement within the fair value hierarchy levels.
We have not changed the valuation techniques or types of inputs we use to measure recurring fair value during the three months ended March 31, 2017.
The fair value of commodity derivative assets and liabilities is presented in accordance with our netting policy, as we discuss in Note 7 under “Financial Statement Presentation.”
The determination of fair values, shown in the tables below, incorporates various factors, including but not limited to, the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests).
Our financial assets and liabilities that were accounted for at fair value on a recurring basis at March 31, 20162017 and December 31, 20152016 in the tables below include the following:
§  
▪Nuclear decommissioning trusts reflect the assets of SDG&E’s nuclear decommissioning trusts, excluding cash balances. A third party trustee values the trust assets using prices from a pricing service based on a market approach. We validate these prices by comparison to prices from other independent data sources. Equity and certain debt securitiesSecurities are valued using quoted prices listed on nationally recognized securities exchanges or based on closing prices reported in the active market in which the identical security is traded (Level 1). Other debt securities are valued based on yields that are currently available for comparable securities of issuers with similar credit ratings (Level 2).
§  
▪For commodity contracts, interest rate derivatives and foreign exchange instruments, we primarily use a market approach with market participant assumptions to value these derivatives. Market participant assumptions include those about risk, and the risk inherent in the inputs to the valuation techniques. These inputs can be readily observable, market corroborated, or generally unobservable. We have exchange-traded derivatives that are valued based on quoted prices in active markets for the identical instruments (Level 1). We also may have other commodity derivatives that are valued using industry standard models that consider quoted forward prices for commodities, time value, current market and contractual prices for the underlying instruments, volatility factors, and other relevant economic measures (Level 2). Level 3 recurring items relate to CRRs and long-term, fixed-price electricity positions at SDG&E, as we discuss below underin “Level 3 Information.”
§  
▪Rabbi Trust investments include marketable securities that we value using a market approach based on closing prices reported in the active market in which the identical security is traded (Level 1). These investments in marketable securities were negligible at both March 31, 20162017 and December 31, 2015.2016.
There were no transfers into or out of Level 1, Level 2 or Level 3 for Sempra Energy Consolidated, SDG&E or SoCalGas during the periods presented.


RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
 Fair value at March 31, 2016
  Level 1 Level 2 Level 3 Netting(1) Total
Assets:          
    Nuclear decommissioning trusts:          
          Equity securities$623$―$―$―$623
          Debt securities:          
              Debt securities issued by the U.S. Treasury and other          
                   U.S. government corporations and agencies 62 43 ― ― 105
              Municipal bonds ― 156 ― ― 156
              Other securities ― 190 ― ― 190
          Total debt securities 62 389 ― ― 451
    Total nuclear decommissioning trusts(2) 685 389 ― ― 1,074
    Interest rate and foreign exchange instruments ― 8 ― ― 8
    Commodity contracts not subject to rate recovery 1 19 ― 20 40
    Commodity contracts subject to rate recovery ― 1 68 32 101
Total$686$417$68$52$1,223
            
Liabilities:          
    Interest rate and foreign exchange instruments$―$181$―$―$181
    Commodity contracts not subject to rate recovery 3 6 ― (7) 2
    Commodity contracts subject to rate recovery ― 67 57 (55) 69
Total$3$254$57$(62)$252
           
 Fair value at December 31, 2015
  Level 1 Level 2 Level 3 Netting(1) Total
Assets:          
    Nuclear decommissioning trusts:          
          Equity securities$619$―$―$―$619
          Debt securities:          
              Debt securities issued by the U.S. Treasury and other          
                   U.S. government corporations and agencies 47 44 ― ― 91
              Municipal bonds ― 156 ― ― 156
              Other securities ― 182 ― ― 182
          Total debt securities 47 382 ― ― 429
    Total nuclear decommissioning trusts(2) 666 382 ― ― 1,048
    Interest rate and foreign exchange instruments ― 5 ― ― 5
    Commodity contracts not subject to rate recovery 22 16 ― (4) 34
    Commodity contracts subject to rate recovery ― 1 72 28 101
Total$688$404$72$24$1,188
            
Liabilities:          
    Interest rate and foreign exchange instruments$―$171$―$―$171
    Commodity contracts not subject to rate recovery 5 3 ― (4) 4
    Commodity contracts subject to rate recovery ― 68 53 (54) 67
Total$5$242$53$(58)$242
(1)Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(2)Excludes cash balances and cash equivalents.          
RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
 Fair value at March 31, 2017
 Level 1 Level 2 Level 3 Netting(1) Total
Assets:         
Nuclear decommissioning trusts:         
Equity securities$606
 $5
 $—
 $—
 $611
Debt securities:         
Debt securities issued by the U.S. Treasury and other         
U.S. government corporations and agencies40
 11
 —
 —
 51
Municipal bonds—
 221
 —
 —
 221
Other securities—
 167
 —
 —
 167
Total debt securities40
 399
 —
 —
 439
Total nuclear decommissioning trusts(2)646
 404
 —
 —
 1,050
Interest rate and foreign exchange instruments—
 99
 —
 —
 99
Commodity contracts not subject to rate recovery—
 23
 —
 9
 32
Commodity contracts subject to rate recovery—
 2
 90
 20
 112
Total$646
 $528
 $90
 $29
 $1,293
          
Liabilities:         
Interest rate and foreign exchange instruments$—
 $211
 $—
 $—
 $211
Commodity contracts not subject to rate recovery—
 6
 —
 —
 6
Commodity contracts subject to rate recovery25
 8
 186
 (24) 195
Total$25
 $225
 $186
 $(24) $412
          
 Fair value at December 31, 2016
 Level 1 Level 2 Level 3 Netting(1) Total
Assets:         
Nuclear decommissioning trusts:         
Equity securities$508
 $—
 $—
 $—
 $508
Debt securities:         
Debt securities issued by the U.S. Treasury and other         
U.S. government corporations and agencies36
 16
 —
 —
 52
Municipal bonds—
 206
 —
 —
 206
Other securities—
 141
 —
 —
 141
Total debt securities36
 363
 —
 —
 399
Total nuclear decommissioning trusts(2)544
 363
 —
 —
 907
Interest rate and foreign exchange instruments—
 9
 —
 —
 9
Commodity contracts not subject to rate recovery—
 15
 —
 9
 24
Commodity contracts subject to rate recovery1
 3
 96
 32
 132
Total$545
 $390
 $96
 $41
 $1,072
          
Liabilities:         
Interest rate and foreign exchange instruments$—
 $252
 $—
 $—
 $252
Commodity contracts not subject to rate recovery16
 11
 —
 (17) 10
Commodity contracts subject to rate recovery19
 8
 170
 (18) 179
Total$35
 $271
 $170
 $(35) $441
(1)Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(2)Excludes cash balances and cash equivalents.



RECURRING FAIR VALUE MEASURES – SDG&E
(Dollars in millions)
 Fair value at March 31, 2017
 Level 1 Level 2 Level 3 Netting(1) Total
Assets:         
Nuclear decommissioning trusts:         
Equity securities$606
 $5
 $—
 $—
 $611
Debt securities:         
Debt securities issued by the U.S. Treasury and other         
U.S. government corporations and agencies40
 11
 —
 —
 51
Municipal bonds—
 221
 —
 —
 221
Other securities—
 167
 —
 —
 167
Total debt securities40
 399
 —
 —
 439
Total nuclear decommissioning trusts(2)646
 404
 —
 —
 1,050
Commodity contracts not subject to rate recovery—
 —
 —
 1
 1
Commodity contracts subject to rate recovery—
 —
 90
 19
 109
Total$646
 $404
 $90
 $20
 $1,160
          
Liabilities:         
Interest rate instruments$—
 $22
 $—
 $—
 $22
Commodity contracts subject to rate recovery25
 7
 186
 (24) 194
Total$25
 $29
 $186
 $(24) $216
          
 Fair value at December 31, 2016
 Level 1 Level 2 Level 3 Netting(1) Total
Assets:         
Nuclear decommissioning trusts:         
Equity securities$508
 $—
��$—
 $—
 $508
Debt securities:         
Debt securities issued by the U.S. Treasury and other         
U.S. government corporations and agencies36
 16
 —
 —
 52
Municipal bonds—
 206
 —
 —
 206
Other securities—
 141
 —
 —
 141
Total debt securities36
 363
 —
 —
 399
Total nuclear decommissioning trusts(2)544
 363
 —
 —
 907
Commodity contracts not subject to rate recovery—
 —
 —
 1
 1
Commodity contracts subject to rate recovery1
 2
 96
 30
 129
Total$545
 $365
 $96
 $31
 $1,037
          
Liabilities:         
Interest rate instruments$—
 $25
 $—
 $—
 $25
Commodity contracts subject to rate recovery17
 7
 170
 (16) 178
Total$17
 $32
 $170
 $(16) $203
(1)Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(2)Excludes cash balances and cash equivalents.

RECURRING FAIR VALUE MEASURES – SDG&E
(Dollars in millions)
 Fair value at March 31, 2016
  Level 1 Level 2 Level 3 Netting(1) Total
Assets:          
    Nuclear decommissioning trusts:          
          Equity securities$623$―$―$―$623
          Debt securities:          
              Debt securities issued by the U.S. Treasury and other          
                   U.S. government corporations and agencies 62 43 ― ― 105
              Municipal bonds ― 156 ― ― 156
              Other securities ― 190 ― ― 190
          Total debt securities 62 389 ― ― 451
    Total nuclear decommissioning trusts(2) 685 389 ― ― 1,074
    Commodity contracts not subject to rate recovery ― ― ― 2 2
    Commodity contracts subject to rate recovery ― ― 68 30 98
Total$685$389$68$32$1,174
            
Liabilities:          
    Interest rate instruments$―$39$―$―$39
    Commodity contracts not subject to rate recovery 1 ― ― (1) ―
    Commodity contracts subject to rate recovery ― 66 57 (55) 68
Total$1$105$57$(56)$107
           
 Fair value at December 31, 2015
  Level 1 Level 2 Level 3 Netting(1) Total
Assets:          
    Nuclear decommissioning trusts:          
          Equity securities$619$―$―$―$619
          Debt securities:          
              Debt securities issued by the U.S. Treasury and other          
                   U.S. government corporations and agencies 47 44 ― ― 91
              Municipal bonds ― 156 ― ― 156
              Other securities ― 182 ― ― 182
          Total debt securities 47 382 ― ― 429
    Total nuclear decommissioning trusts(2) 666 382 ― ― 1,048
    Commodity contracts not subject to rate recovery ― ― ― 1 1
    Commodity contracts subject to rate recovery ― ― 72 27 99
Total$666$382$72$28$1,148
            
Liabilities:          
    Interest rate instruments$―$37$―$―$37
    Commodity contracts not subject to rate recovery 1 ― ― (1) ―
    Commodity contracts subject to rate recovery ― 67 53 (54) 66
Total$1$104$53$(55)$103
(1)Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
(2)Excludes cash balances and cash equivalents.          



RECURRING FAIR VALUE MEASURES – SOCALGAS
(Dollars in millions)
  Fair value at March 31, 2016
   Level 1 Level 2 Level 3 Netting(1) Total
Assets:          
    Commodity contracts not subject to rate recovery$―$―$―$1$1
    Commodity contracts subject to rate recovery ― 1 ― 2 3
Total$―$1$―$3$4
            
Liabilities:          
    Commodity contracts not subject to rate recovery$1$―$―$(1)$―
    Commodity contracts subject to rate recovery ― 1 ― ― 1
Total$1$1$―$(1)$1
            
  Fair value at December 31, 2015
   Level 1 Level 2 Level 3 Netting(1) Total
Assets:          
    Commodity contracts subject to rate recovery$―$1$―$1$2
Total$―$1$―$1$2
            
Liabilities:          
    Commodity contracts not subject to rate recovery$1$―$―$(1)$―
    Commodity contracts subject to rate recovery ― 1 ― ― 1
Total$1$1$―$(1)$1
 (1)Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.



RECURRING FAIR VALUE MEASURES – SOCALGAS
(Dollars in millions)
 Fair value at March 31, 2017
 Level 1 Level 2 Level 3 Netting(1) Total
Assets:         
Commodity contracts subject to rate recovery$—
 $2
 $—
 $1
 $3
Total$—
 $2
 $—
 $1
 $3
          
Liabilities:         
Commodity contracts subject to rate recovery$—
 $1
 $—
 $—
 $1
Total$—
 $1
 $—
 $—
 $1
          
 Fair value at December 31, 2016
 Level 1 Level 2 Level 3 Netting(1) Total
Assets:         
Commodity contracts not subject to rate recovery$—
 $—
 $—
 $1
 $1
Commodity contracts subject to rate recovery—
 1
 —
 2
 3
Total$—
 $1
 $—
 $3
 $4
          
Liabilities:         
Commodity contracts subject to rate recovery$2
 $1
 $—
 $(2) $1
Total$2
 $1
 $—
 $(2) $1
(1)Includes the effect of the contractual ability to settle contracts under master netting agreements and with cash collateral, as well as cash collateral not offset.
Level 3 Information

The following table sets forth reconciliations of changes in the fair value of congestion revenue rights (CRRs)CRRs and long-term, fixed-price electricity positions classified as Level 3 in the fair value hierarchy for Sempra Energy Consolidated and SDG&E:
LEVEL 3 RECONCILIATIONS
(Dollars in millions)
 Three months ended March 31,
 2017 2016
Balance at January 1$(74) $19
Realized and unrealized losses(13) (1)
Settlements(9) (7)
Balance at March 31$(96) $11
Change in unrealized losses relating to   
 instruments still held at March 31$(16) $(1)

 


LEVEL 3 RECONCILIATIONS
(Dollars in millions)
 Three months ended March 31,
 20162015
Balance as of January 1$19$107
    Realized and unrealized (losses) gains (1) 6
    Settlements (7) (11)
Balance as of March 31$11$102
Change in unrealized (losses) gains relating to    
    instruments still held at March 31$(1)$1

SDG&E’s Energy and Fuel Procurement department, in conjunction with SDG&E’s finance group, is responsible for determining the appropriate fair value methodologies used to value and classify CRRs and long-term, fixed-price electricity positions on an ongoing basis. Inputs used to determine the fair value of CRRs and fixed-price electricity positions are reviewed and compared with market conditions to determine reasonableness. SDG&E expects all costs related to these instruments to be recoverable through customer rates. As such, there is no impact to earnings from changes in the fair value of these instruments.
CRRs are recorded at fair value based almost entirely on the most current auction prices published by the California Independent System Operator (CAISO)(ISO), an objective source. Annual auction prices are published once a year, typically in the middle of November, and remain in effectare the basis for valuation for the following year. The impact associated with discounting is negligible. Because these auction prices are a less observable input, these instruments are classified as Level 3. The fair value of these instruments is derived from auction price differences between two locations. FromFor CRRs settling from January 1, 2017 to December 31, 2017, the auction price inputs ranged from $(12) per MWh to $7 per MWh at a given location, and for CRRs settling from January 1, 2016 to December 31, 2016, the auction prices rangeprice inputs ranged from $(24) per MWh to $10 per MWh at a given location, and from January 1, 2015 to December 31, 2015, the auction prices ranged from $(16) per MWh to $8 per MWh at a given location. Positive values between two locations represent expected future reductions in congestion costs, whereas negative values between two locations represent expected future charges. Valuation of our CRRs is sensitive to a change in auction price. If auction prices at one location increase (decrease) relative to another location, this could result in a higher (lower) fair value measurement. We summarize CRR volumes in Note 7.


Long-term, fixed-price electricity positions that are valued using significant unobservable data are classified as Level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net electricity positions classified as Level 3 is derived from a discounted cash flow model using market electricity forward price inputs. At March 31, 2016, these electricity forward pricesThese inputs range from $15.85$14.50 per MWh to $57.43$43.25 per MWh.MWh at March 31, 2017. A significant increase or decrease in market electricity forward prices would result in a significantly higher or lower fair value, respectively. We summarize long-term, fixed-price electricity position volumes in Note 7.
Realized gains and losses associated with CRRs and long-term electricity positions, which are recoverable in rates, are recorded in Cost of Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations. Unrealized gains and losses are recorded as regulatory assets and liabilities and therefore also do not affect earnings.
FAIR VALUE OF FINANCIAL INSTRUMENTS


Fair Value of Financial Instruments

The fair values of certain of our financial instruments (cash, temporary investments, accounts and notes receivable, currentshort-term amounts due to/from unconsolidated affiliates, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts because of the short-term nature of these instruments. Investments in life insurance contracts that we hold in support of our Supplemental Executive Retirement, Cash Balance Restoration and Deferred Compensation Plans are carried at cash surrender values, which represent the amount of cash that could be realized under the contracts. The following table provides the carrying amounts and fair values of certain other financial instruments that are not recorded at fair value on the Condensed Consolidated Balance Sheets at March 31, 20162017 and December 31, 2015:2016:

FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
 March 31, 2017
 Carrying
amount		 Fair value
  Level 1 Level 2 Level 3 Total
Sempra Energy Consolidated:         
Long-term amounts due from unconsolidated affiliates(1)$168
 $—
 $78
 $86
 $164
Total long-term debt(2)(3)14,971
 —
 15,123
 496
 15,619
SDG&E:         
Total long-term debt(3)(4)$4,493
 $—
 $4,546
 $302
 $4,848
SoCalGas:         
Total long-term debt(5)$3,009
 $—
 $3,121
 $—
 $3,121
          
 December 31, 2016
 Carrying
amount		 Fair value
  Level 1 Level 2 Level 3 Total
Sempra Energy Consolidated:         
Long-term amounts due from unconsolidated affiliates(1)$184
 $—
 $91
 $84
 $175
Total long-term debt(2)(3)15,068
 —
 15,455
 492
 15,947
SDG&E:         
Total long-term debt(3)(4)$4,654
 $—
 $4,727
 $305
 $5,032
SoCalGas:         
Total long-term debt(5)$3,009
 $—
 $3,131
 $—
 $3,131
(1)Excluding accumulated interest outstanding of $19 million and $17 million at March 31, 2017 and December 31, 2016, respectively.
(2)Before reductions for unamortized discount (net of premium) and debt issuance costs of $105 million and $109 million at March 31, 2017 and December 31, 2016, respectively, and excluding build-to-suit and capital lease obligations of $382 million and $383 million at March 31, 2017 and December 31, 2016, respectively. We discuss our long-term debt in Note 6 above and in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.
(3)Level 3 instruments include $302 million and $305 million at March 31, 2017 and December 31, 2016, respectively, related to Otay Mesa VIE.
(4)Before reductions for unamortized discount and debt issuance costs of $43 million and $45 million at March��31, 2017 and December 31, 2016, respectively, and excluding capital lease obligations of $239 million and $240 million at March 31, 2017 and December 31, 2016, respectively.
(5)Before reductions for unamortized discount and debt issuance costs of $26 million and $27 million at March 31, 2017 and December 31, 2016, respectively.

FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
  March 31, 2016
  Carrying Fair value
  amount Level 1Level 2Level 3Total
Sempra Energy Consolidated:           
Noncurrent due from unconsolidated affiliates(1)
$173 $―$92$72$164
Total long-term debt(2)(3)
 13,761  ― 14,363 652 15,015
Preferred stock of subsidiary 20  ― 23 ― 23
SDG&E:           
Total long-term debt(3)(4)
$4,285 $―$4,517$312$4,829
SoCalGas:           
Total long-term debt(5)
$2,513 $―$2,731$―$2,731
Preferred stock 22  ― 25 ― 25
             
  December 31, 2015
  Carrying Fair value
  amount Level 1Level 2Level 3Total
Sempra Energy Consolidated:           
Noncurrent due from unconsolidated affiliates(1)
$175 $―$97$69$166
Total long-term debt(2)(3)
 13,761  ― 13,985 648 14,633
Preferred stock of subsidiary 20  ― 23 ― 23
SDG&E:           
Total long-term debt(3)(4)
$4,304 $―$4,355$315$4,670
SoCalGas:           
Total long-term debt(5)
$2,513 $―$2,621$―$2,621
Preferred stock 22  ― 25 ― 25
(1)Excluding accumulated interest outstanding of $13 million and $11 million at March 31, 2016 and December 31, 2015, respectively.
(2)Before reductions for unamortized discount (net of premium) and debt issuance costs of $106 million and $107 million at March 31, 2016 and December 31, 2015, respectively, and excluding build-to-suit and capital lease obligations of $386 million and $387 million at March 31, 2016 and December 31, 2015, respectively. We discuss our long-term debt in Note 6 above and in Note 5 of the Notes to Consolidated Financial Statements in the Annual Report.
(3)Level 3 instruments include $312 million and $315 million at March 31, 2016 and December 31, 2015, respectively, related to Otay Mesa VIE.
(4)Before reductions for unamortized discount and debt issuance costs of $43 million at March 31, 2016 and December 31, 2015, and excluding capital lease obligations of $243 million and $244 million at March 31, 2016 and December 31, 2015, respectively.
(5)Before reductions for unamortized discount and debt issuance costs of $24 million at March 31, 2016 and December 31, 2015, and excluding capital lease obligations of $1 million at March 31, 2016 and December 31, 2015.

We basedetermine the fair value of certain noncurrentlong-term amounts due from unconsolidated affiliates and long-term debt and preferred stockbased on a market approach using quoted market prices for identical or similar securities in thinly-traded markets (Level 2). We value certain other noncurrentlong-term amounts due from unconsolidated affiliates of Sempra South American Utilities using a perpetuity approach based on the obligation’s fixed interest rate, the absence of a stated maturity date and a discount rate reflecting local borrowing costs (Level 3). We value other long-term debt using an income approach based on the present value of estimated future cash flows discounted at rates available for similar securities (Level 3).


We provide the fair values for the securities held in the nuclear decommissioning trust funds related to the San Onofre Nuclear Generating Station (SONGS) in Note 9 below.9.



Non-Recurring Fair Value Measures – Sempra Energy Consolidated

Sempra Natural Gas – Rockies Express
In March 2016, Sempra Natural Gas agreed to sell its 25-percent interest in Rockies Express to a subsidiary of Tallgrass Development, LP for cash consideration of $440 million, subject to adjustment at closing. We consider the sale price for our equity interest in Rockies Express to be a market participants’ view of the total value of Rockies Express and have measured the fair value of our investment based on the equity sale price. In March 2016, we recorded a noncash impairment of our investment in Rockies Express of $44 million ($27 million after-tax), which is included in Equity Earnings, Before Income Tax, on the Condensed Consolidated Statement of Operations for the three months ended March 31, 2016. Use of this market participant input as the indicator of fair value is a Level 2 measurement in the fair value hierarchy.
The following table summarizes significant inputs impacting non-recurring fair value measures related to our investment in Rockies Express:


NON-RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
 Estimated Fair% ofInputs used to 
 fair valuefair valuedevelopRange of
 valueValuation techniquehierarchymeasurementmeasurementinputs
Investment in        
Rockies Express$440(1)Market approachLevel 2100%Equity sale price100%
(1)At measurement date of March 29, 2016. At March 31, 2016, our investment in Rockies Express had a carrying value of $436 million, reflecting subsequent equity method activity to record a distribution.

NOTE 9. SAN ONOFRE NUCLEAR GENERATING STATION (SONGS)

SDG&E has a 20-percent ownership interest inWe provide below updates to ongoing matters related to SONGS, a nuclear generating facility near San Clemente, California whichthat ceased operations in June 2013. On June 6, 2013, after an extended outage beginningand in 2012, Southern California Edison Company (Edison), the majority owner and operator of SONGS, notified which SDG&E that it had reachedhas a decision to permanently retire20-percent ownership interest. We discuss SONGS and seek approval from the Nuclear Regulatory Commission (NRC) to start the decommissioning activities for the entire facility. SONGS is subject to the jurisdictionfurther in Note 13 of the NRC and the CPUC.
SDG&E, and each of the other owners, holds its undivided interest as a tenant in commonNotes to Consolidated Financial Statements in the property. Each owner is responsible for financing its share of expenses and capital expenditures. SDG&E’s share of operating expenses is included in Sempra Energy’s and SDG&E’s Condensed Consolidated Statements of Operations.Annual Report.
REPLACEMENT STEAM GENERATORS


SONGS Steam Generator Replacement Project

As part of the Steam Generator Replacement Project, (SGRP), the steam generators were replaced in SONGS Units 2 and 3, and the Units returned to service in 2010 and 2011, respectively. Both Units were shut down in early 2012 after a water leak occurred in the Unit 3 steam generator. Southern California Edison Company (Edison), the majority owner and operator of SONGS, concluded that the leak was due to unexpected wear from tube-to-tube contact. At the time the leak was identified, Edison also inspected and tested Unit 2 and subsequently found unexpected tube wear in Unit 2’s steam generator. These issues with the steam generators ultimately resulted in Edison’s decision to permanently retire SONGS.SONGS in June 2013.
The replacement steam generators were designed and provided by Mitsubishi Heavy Industries, Ltd., Mitsubishi Nuclear Energy Systems, Inc., and Mitsubishi Heavy Industries America, Inc. (collectively MHI). In July 2013, SDG&E filed a lawsuit against MHI seeking to recover damages SDG&E has incurred and will incur related to the design defects in the steam generators. In October 2013, Edison instituted binding arbitration proceedings against MHI seeking damages as well.recovery of damages. The other SONGS co-owners, SDG&E and the City of Riverside, participated as claimants and respondents.
On March 13, 2017, the International Chamber of Commerce International Court of Arbitration (Tribunal) found MHI liable for breach of contract, subject to a contractual limitation of liability, and rejected claimants’ other claims. The Tribunal awarded $118 million in damages to the SONGS co-owners, but determined that MHI was the prevailing party and awarded it 95 percent of its arbitration costs. The damage award is participatingoffset by these costs, resulting in a net award of approximately $60 million in favor of the arbitration asSONGS co-owners. SDG&E’s specific allocation of the damage award is $24 million reduced by costs awarded to MHI of approximately $12 million, resulting in a claimant and respondent. We discuss these proceedingsnet damage award of $12 million, which was paid by MHI to SDG&E in Note 11.


March 2017. These amounts include certain adjustments to calculations supporting the Tribunal’s findings. In accordance with the Amended Settlement Agreement to Resolvediscussed below, which may be modified or set aside, SDG&E recorded the CPUC’s Order Instituting Investigationproceeds from the MHI arbitration by reducing Operation and Maintenance Expense for previously incurred legal costs of $11 million, and shared the remaining $1 million equally between ratepayers and shareholders.
SETTLEMENT AGREEMENT TO RESOLVE THE CPUC’S ORDER INSTITUTING INVESTIGATION (OII) into theINTO THE SONGS OutageOUTAGE (SONGS OII)

In November 2012, in response to the outage, the CPUC issued the SONGS OII, which was intended to determine the ultimate recovery of the investment in SONGS and the costs incurred since the commencement of this outage, including purchased replacement power costs, which are typically recovered through the Energy Resource Recovery Account (ERRA).outage.
In AprilNovember 2014, SDG&E filed with the CPUC issued a final decision approving an Amended and Restated Settlement Agreement (Amended Settlement Agreement) in the SONGS OII proceeding executed by SDG&E along with Edison, The Utility Reform Network (TURN), the CPUC Office of Ratepayer Advocates (ORA) and two other intervenors who joined the Settlement Agreement to the SONGS OII proceeding (collectively, the Settling Parties).
In September 2014, the Settling Parties executed an Amended and Restated Settlement Agreement (Amended Settlement Agreement), which amended the Settlement Agreement, and in November 2014, the CPUC issued a final decision approving the Amended Settlement Agreement.intervenors. The Amended Settlement Agreement does not affect on-goingongoing or future proceedings before the NRC,Nuclear Regulatory Commission (NRC), or litigation or arbitration related to potential future recoveries from third parties (except for the allocation to ratepayers of any recoveries as described below)addressed in the final decision) or proceedings addressing decommissioning activities and costs. We discussdescribe the terms and provisions of the Amended Settlement Agreement and related filings in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report.
In April 2015, a petitionMay 2016, following the filing of petitions for modification (PFM) was filed withby various parties, the CPUC by Alliance for Nuclear Responsibility (A4NR), an intervenor inissued a procedural ruling reopening the SONGSrecord of the OII proceeding, askingto address the CPUC to set aside its decision approvingissue of whether the Amended Settlement Agreement is reasonable and reopenin the public interest.
In December 2016, the CPUC issued another procedural ruling directing parties to the SONGS OII proceeding. In June 2015, TURN, a party to determine whether an agreement could be reached to modify the Amended Settlement Agreement filed a response supportingpreviously approved by the A4NR petition. TURN does not questionCPUC, to resolve allegations that unreported ex parte communications between Edison and the merits ofCPUC resulted in an unfair advantage at the Amended Settlement Agreement, buttime the settlement agreement was negotiated. Pursuant to the ruling, if no agreement is concerned that certain allegations regarding Edison raisedreached by A4NR have undermined the public’s confidence in the regulatory process. SDG&E has responded that TURN’s concerns regarding public perception do not impact the reasonableness of the Amended Settlement Agreement and are insufficient to overturn it. SDG&E is unable to determine what actionsApril 28, 2017, the CPUC will take, if any, in responseconsider other options


including entertaining additional testimony, hearings and briefs. Subsequent to the A4NR PFM.
In August 2015, ORA, alsoruling, the parties have met to confer and, as a party toresult of these discussions, the Amended Settlement Agreement,parties have engaged a mediator and scheduled mediation sessions in June 2017. Given the pending mediation, the parties filed a PFMjoint motion with the CPUC withdrawing its support for the Amended Settlement Agreement and asking the CPUC to reopen the SONGS OII proceeding. The ORA does not question the merits of the Amended Settlement Agreement, but is concerned with the CPUC’s approach toward recent disclosures concerning Edison ex parte communications with the CPUC. SDG&E respondedin April 2017 requesting that the ORA’s PFMApril 28, 2017 deadline be extended until August 15, 2017. The joint motion is insufficient to overturnpending before the Amended Settlement Agreement, because the ORA fails to make a caseCPUC.
There is no assurance that the Amended Settlement Agreement is no longerwill not be renegotiated, modified or set aside as a result of the mediation or the larger OII proceedings, which could result in the public interest.a substantial reduction in our expected recovery and have a material adverse effect on Sempra Energy’s and SDG&E is unable to determine what actions the CPUC will take, if any, in response to the ORA PFM.&E’s results of operations, financial condition and cash flows.

Accounting and Financial Impacts

Through December 31, 2015 and March 31, 2016,2017, the cumulative after-tax loss from plant closure recorded by Sempra Energy and SDG&E is $125 million, including a reduction in the after-tax loss of $13 million in the first quarter of 2015 based on the CPUC’s approval in March 2015 of SDG&E’s compliance filing and establishment of the SONGS settlement revenue requirement.
million. The remaining regulatory asset for the expected recovery of SONGS costs, consistent with the Amended Settlement Agreement, is $243$175 million ($4334 million current and $200$141 million long-term) at March 31, 2016 and is recorded on the Condensed Consolidated Balance Sheets in Other Current Assets and Regulatory Assets Noncurrent, respectively, at Sempra Energy, and in Regulatory Assets Current and Other Regulatory Assets Noncurrent, respectively, at SDG&E. 2017. The amortization period prescribed for the regulatory asset is 10 years, which began on February 1, 2012. However, since the CPUC’s final decision approving the Amended Settlement Agreement was not issued until November 2014, amortization did not commence untilending in January 2015.2022.
NUCLEAR DECOMMISSIONING AND FUNDING


Settlement with Nuclear Electric Insurance Limited (NEIL)

NEIL insures domestic and international nuclear utilities for the costs associated with interruptions, damages, decontaminations and related nuclear risks. In October 2015, the SONGS co-owners (Edison, SDG&E and the City of Riverside) reached an agreement with NEIL to resolve all of SONGS’ insurance claims arising out of the failures of the replacement steam generators for a total payment by NEIL of $400 million, SDG&E’s share of which is $80 million. Pursuant to the terms of the SONGS OII Amended Settlement Agreement, after reimbursement of legal fees and a 5-percent allocation to shareholders, the net proceeds of $75 million were allocated to ratepayers through ERRA. We discuss NEIL further in Note 11.


Nuclear Decommissioning and Funding

As a result of Edison’s decision to permanently retire SONGS Units 2 and 3, Edison has begunbegan the decommissioning phase of the plant. We discussDecommissioning of Unit 1, removed from service in 1992, is largely complete. The remaining work for Unit 1 will be done once Units 2 and 3 are dismantled. In December 2016, Edison announced that, following a 10-month competitive bid process, it had contracted with a joint venture of AECOM and EnergySolutions (known as SONGS Decommissioning Solutions) as the processgeneral contractor to complete the dismantlement of decommissioning SONGS and oversight by the NRC in Note 13SONGS. The majority of the Notesdismantlement work is expected to Consolidated Financial Statements intake 10 years. SDG&E is responsible for 20 percent of the Annual Report.
total contract price.
In accordance with state and federal requirements and regulations, SDG&E has assets held in nuclear decommissioning trusts referred to as the Nuclear Decommissioning Trusts (NDT), to fund its share of decommissioning costs for SONGS Units 1, 2 and 3. DecommissioningThe amounts collected in rates for SONGS’ decommissioning are invested in the NDT, which is comprised of Unit 1, removedexternally managed trust funds. Amounts held by the NDT are invested in accordance with CPUC regulations. The NDT assets are presented on the Sempra Energy and SDG&E Condensed Consolidated Balance Sheets at fair value with the offsetting credits recorded in Regulatory Liabilities Arising from service in 1992, is largely complete. The remaining work will be done whenRemoval Obligations.
In April 2016, the CPUC adopted a decision approving a total decommissioning cost estimate for SONGS Units 2 and 3 are decommissioned. At March 31, 2016, the fair value of $4.4 billion (in 2014 dollars), of which SDG&E’s NDT assets was $1.1 billion. share is $899 million. Except for the use of funds for the planning of decommissioning activities or NDT administrative costs, CPUC approval is required for SDG&E to access the NDT assets to fund SONGS decommissioning costs for Units 2 and 3. In July 2015,SDG&E has received authorization from the CPUC authorized SDG&E’s request to access trustNDT funds forof up to $55 $302 million for 2013 through 2017 (2017 forecasted) SONGS decommissioning costs. This includes up to $84 million authorized by the CPUC in decommissioning costs incurred in 2013, including $18 million that is expectedFebruary 2017 to be withdrawn pending satisfactory clarification byfrom the NDT for forecasted 2017 SONGS Units 2 and 3 costs as decommissioning costs are incurred.
In December 2016, the Internal Revenue Service (IRS) and the U.S. Department of the Treasury issued proposed regulations that certainclarify the definition of “nuclear decommissioning costs,” which are costs that may be paid for or reimbursed from a qualified fund. The proposed regulations state that costs related to the construction and maintenance of independent spent fuel costs and other costsmanagement installations are eligibleincluded in the definition of “nuclear decommissioning costs, payable from qualified nuclear decommissioning trusts. Wecosts.” The proposed regulations will be effective prospectively once they are uncertainfinalized; however, the IRS has stated that it will not challenge taxpayer positions consistent with the proposed regulations for taxable years ending on or after the date the proposed regulations were issued. SDG&E is working with outside counsel to clarify with the IRS some of the provisions in the proposed regulations so as to when such clarificationconfirm that the proposed regulations will allow SDG&E to access the NDT for reimbursement or payment of the spent fuel management costs that were or will be provided.
In November 2015, the CPUC authorized SDG&E’s request to access trust funds for $36 million for SONGS Units 2 and 3 decommissioning costs incurred in 2014, including $13 million that also2016 and subsequent years. It is unclear when SDG&E will receive clarification or when the proposed regulations will be withdrawn pending satisfactory clarification by the IRS. SDG&E expects to request and receive approval in the second quarter of 2016 to access trust funds for Units 2 and 3 decommissioning costs incurred in 2015.finalized.
In April 2016, the CPUC adopted a decision approving a total decommissioning cost estimate for SONGS Units 2 and 3 of $4.411 billion, of which SDG&E’s share is $899 million. The decision also approves an annual advice letter request process for SDG&E to request trust fund disbursements for decommissioning costs based on a forecast for 2016 and thereafter. Disbursements from the trust will then be made up to this annual forecast amount as decommissioning expenses are incurred. All disbursements will be subject to future refund until a reasonableness review of the actual decommissioning costs is conducted, which would be no less frequently than every three years.
We discuss the NDT and matters related to its funding and the funding of decommissioning costs by the NDT further in Note 13 of the Notes to Consolidated Financial Statements in the Annual Report.



Nuclear Decommissioning Trusts

The amounts collected in rates for SONGS’ decommissioning are invested in externally managed trust funds. Amounts held by the trusts are invested in accordance with CPUC regulations. These trusts are presented on the Sempra Energy and SDG&E Condensed Consolidated Balance Sheets at fair value with the offsetting credits recorded in Regulatory Liabilities Arising from Removal Obligations.

The following table shows the fair values and gross unrealized gains and losses for the securities held in the NDT. We provide additional fair value disclosures for the NDT in Note 8.


NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
 Cost 
Gross
unrealized
gains
 
Gross
unrealized
losses
 
Estimated
fair
value
At March 31, 2017:       
Debt securities:       
Debt securities issued by the U.S. Treasury and other       
U.S. government corporations and agencies(1)$51
 $—
 $—
 $51
Municipal bonds(1)216
 6
 (1) 221
Other securities(2)166
 2
 (1) 167
Total debt securities433
 8
 (2) 439
Equity securities255
 358
 (2) 611
Cash and cash equivalents12
 —
 —
 12
Total$700
 $366
 $(4) $1,062
At December 31, 2016:       
Debt securities:       
Debt securities issued by the U.S. Treasury and other       
U.S. government corporations and agencies$52
 $—
 $—
 $52
Municipal bonds203
 4
 (1) 206
Other securities141
 2
 (2) 141
Total debt securities396
 6
 (3) 399
Equity securities143
 366
 (1) 508
Cash and cash equivalents119
 —
 —
 119
Total$658
 $372
 $(4) $1,026
(1)Maturity dates are 2017-2047.
(2)Maturity dates are 2017-2066.
NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
     Gross Gross Estimated
     unrealized unrealized fair
   Cost gains losses value
At March 31, 2016:        
Debt securities:        
    Debt securities issued by the U.S. Treasury and other        
         U.S. government corporations and agencies(1)$101$4$―$105
    Municipal bonds(2) 146 10 ― 156
    Other securities(2) 192 6 (8) 190
Total debt securities 439 20 (8) 451
Equity securities 214 413 (4) 623
Cash and cash equivalents 9 ― (1) 8
    Total$662$433$(13)$1,082
At December 31, 2015:        
Debt securities:        
    Debt securities issued by the U.S. Treasury and other        
         U.S. government corporations and agencies$89$2$―$91
    Municipal bonds 148 8 ― 156
    Other securities 194 1 (13) 182
Total debt securities 431 11 (13) 429
Equity securities 214 412 (7) 619
Cash and cash equivalents 15 ― ― 15
    Total$660$423$(20)$1,063
(1)Maturity dates are 2016-2065.
(2)Maturity dates are 2016-2115.


The following table shows the proceeds from sales of securities in the NDT and gross realized gains and losses on those sales:


SALES OF SECURITIES
(Dollars in millions)
 Three months ended
March 31,
 2017 2016
Proceeds from sales(1)$357
 $93
Gross realized gains45
 3
Gross realized losses(5) (8)
(1)Excludes securities that are held to maturity.

SALES OF SECURITIES
(Dollars in millions)
  Three months ended March 31,
  20162015
Proceeds from sales(1)$93$94
Gross realized gains 3 2
Gross realized losses (8) (4)
(1)Excludes securities that are held to maturity.

Net unrealized gains (losses) are included in Regulatory Liabilities Arising from Removal Obligations on Sempra Energy’s and SDG&E’s Condensed Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification.In the first quarter of 2017, sale and purchase activities in our NDT increased significantly compared to the same period in 2016 as a result of continuing changes to our asset allocations initiated in the fourth quarter of 2016 to reduce our equity volatility, lower our duration risk, and increase exposure to municipal bonds and intermediate credit. This shift in our asset mix is intended to reduce the overall risk profile of the NDT, as the plant is in the decommissioning stage.
We provide additional information about SONGS in Note 11.




NOTE 10. CALIFORNIA UTILITIES' REGULATORY MATTERS

We discuss regulatory matters affecting our California Utilities in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, and provide updates to those discussions and details of any new matters below.
CALIFORNIA UTILITIES MATTERS


JOINT MATTERS


CPUC General Rate Case (GRC)

The CPUC uses a general rate caseGRC proceeding to set sufficient 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 California Utilities filed their 2016 General Rate Case (2016 GRC) applications in November 2014. These filings requested revenue requirement increases of $133 million and $256 million for SDG&E and SoCalGas, respectively, over their 2015 revenue requirements.
In September 2015, the California Utilities filed settlement agreements with the CPUC that resolve all material matters related to the proceeding, except for the revenue requirement implications of certain income tax benefits associated with flow-through repair allowance tax deductions, discussed below. The settlement agreements are with eight of eleven intervening parties. For SoCalGas, the settlement proposes a total revenue requirement in 2016 of $2.219 billion, which is $133 million less than its original request. The proposed settlement represents an increase of $122 million, or 6 percent, over the 2015 total revenue requirement. For SDG&E, the settlement proposes a total revenue requirement in 2016 of $1.811 billion, which is $100 million less than its original request (as revised). The proposed settlement represents an increase of $17 million, or one percent, over the 2015 total revenue requirement. This increase reflects a $16 million adjustment to the 2015 estimated revenue requirement since the November 2014 filings. The filed settlement agreements also call for attrition adjustments of 3.5 percent for both 2017 and 2018. Because the 2016 settlement has not been finalized, the California Utilities will collect rates identical to 2015 authorized amounts until a 2016 decision is approved.
The California Utilities also filed a separate agreement, reached with ORA, proposing that a fourth year (2019) be added to the GRC period, with a revenue requirement increase of 4.3 percent over 2018. On April 29, 2016, the CPUC issued a proposed decision in a separate proceeding denying the potential of four-year GRC cycles citing that an extension to the GRC period would delay the implementation of the risk-based decision making framework.
The settlement agreements described above exclude a proposal, for both SDG&E and SoCalGas, regarding certain intra-rate case income tax benefits. The proposal recommends that the CPUC adjust SoCalGas’ rate base by $92 million and SDG&E’s rate base by $93 million, and additionally reduce both utilities’ revenue requirements by amounts tracked in tax memorandum accounts for the year 2015, which total $74 million for SoCalGas and $39 million for SDG&E. We believe the proposed treatment would violate and contradict long standing rate making and income tax policy, and would represent a material departure from historical practice. If this proposal is adopted, the outcome would reduce the revenue requirement amounts agreed to in the respective settlement agreements described above. SDG&E and SoCalGas do not expect that the prospective reduction to rate base described above would result in an immediate earnings impact if this proposal is adopted. However, if this proposal is adopted, SDG&E and SoCalGas may record a material charge against earnings for amounts in the tax memorandum accounts when the proposed decision is received.
We anticipate all matters to be resolved in the CPUC’s final decision on the 2016 GRC proceeding. We expect the CPUC to issue a final decision in the proceeding in the second quarter of 2016.

Natural Gas Pipeline Operations Safety Assessments
In June 2014,2016, the CPUC issued a final decision addressing SDG&E’s and SoCalGas’ Pipeline Safety Enhancement Plan (PSEP). Specifically, the decision determined the following for Phase 1 of the program:
§  approved the utilities’ model for implementing PSEP;
§  approved a process, including a reasonableness review, to determine the amount that the utilities will be authorized to recover from ratepayers for the interim costs incurred through the date of the final decision to implement PSEP, which is recorded in regulatory accounts authorized by the CPUC;
§  approved balancing account treatment, subject to a reasonableness review, for incremental costs yet to be incurred to implement PSEP; and
§  established the criteria to determine the amounts that would not be eligible for cost recovery, including:
□  certain costs incurred or to be incurred searching for pipeline test records,
□  the cost of pressure testing pipelines installed after July 1, 1961 for which the company has not found sufficient records of testing, and
□  any undepreciated balances for pipelines installed after 1961 that were replaced due to insufficient documentation of pressure testing.
As a result of this decision, SoCalGas recorded an after-tax earnings charge of $5 million in 2014 for costs incurred in prior periods that were no longer subject to recovery. After taking the amounts disallowed for recovery into consideration, as of March 31, 2016, SDG&E and SoCalGas have recorded PSEP costs of $12 million and $177 million, respectively, in the CPUC-authorized regulatory account. In regard to requesting recovery from customers for PSEP costs incurred and recorded in accordance with2016 GRC (2016 GRC FD), the Triennial Cost Allocation Proceeding (TCAP) decision, SDG&E and SoCalGasdetails of which are authorized to file an application with the CPUC for recovery of such costs up to the date of the TCAP decision and then annually for costs incurred through the end of each calendar year beginning with the period ended December 31, 2015. SoCalGas and SDG&E currently expect to file such applications no later than the second quarter of the year following and would expect a decision from the CPUC approximately 12 to 18 months following the date of the application (i.e., a decision on the recovery of costs recorded in the PSEP regulatory accounts as of December 31, 2015 would be expected by mid-2017).
In October 2014, SDG&E and SoCalGas filed a PFM with the CPUC requesting authority to begin to recover PSEP costs from customers in the year in which the costs are incurred, subject to refund pending the results of a reasonableness review by the CPUC, instead of in a subsequent year. This request is pending at the CPUC.
In December 2014, SDG&E and SoCalGas filed an application with the CPUC for recovery of $0.1 million and $46 million, respectively, in costs recorded in the regulatory account through June 11, 2014. In June 2015, SDG&E and SoCalGas agreed to remove certain projects from the filing and defer their review to future proceedings and, as a result, are now requesting recovery of $0.1 million and $26.8 million, respectively. The ORA, TURN, and the Southern California Generation Coalition (SCGC) have recommended disallowances related to completed projects, as well as facilities build-out costs, de-scoped projects, and project management and consulting costs. We expect a decision on this application in the second quarter of 2016.
In July 2014, the ORA and TURN filed a joint application for rehearing of the CPUC’s June 2014 final decision. In March 2015, the CPUC issued a decision denying the ORA’s and TURN’s second request for rehearing, but keeping the record open to admit additional evidence on the limited issue of pressure testing or replacing pipelines installed between January 1, 1956 and July 1, 1961. The ORA and TURN allege that the CPUC made a legal error in directing that ratepayers, not shareholders, be responsible for the costs associated with testing or replacing transmission pipelines that were installed between January 1, 1956 and July 1, 1961 for which the California Utilities do not have a record of a pressure test. In December 2015, the CPUC issued a final decision finding that ratepayers should not bear the costs associated with pressure testing subject pipelines, or, if replaced, ratepayers should bear neither the average cost of pressure testing nor the undepreciated balance of abandoned pipelines. Through March 31, 2016, the after-tax disallowed costs for SoCalGas and SDG&E are $2.6 million and $0.5 million, respectively. In January 2016, SoCalGas and SDG&E jointly filed a request with the CPUC seeking rehearing of its December 2015 decision. A CPUC decision on the rehearing request is expected in 2016.

SDG&E MATTERS


SONGS

We discuss regulatory and other matters related to SONGS in Note 9.


Wildfire Claims Cost Recovery

In September 2015, SDG&E filed an application with the CPUC requesting rate recovery of an estimated $379 million in costs related to the October 2007 wildfires that have been recorded to the Wildfire Expense Memorandum Account (WEMA). These costs represent a portion of the estimated total of $2.4 billion in costs and legal fees that SDG&E has incurred to resolve third-party damage claims arising from the October 2007 wildfires. The requested amount of $379 million is the net estimated cost incurred by SDG&E after deductions for insurance reimbursement ($1.1 billion), third party settlement recoveries ($824 million) and allocations to Federal Energy Regulatory Commission (FERC)-jurisdictional rates ($80 million), and reflects a voluntary 10 percent shareholder contribution applied to the net WEMA balance ($42 million). SDG&E requested a CPUC decision by the end of 2016 and is proposing to recover the costs in rates over a six- to ten-year period. In April 2016, a ruling was issued establishing the scope and schedule for the proceeding, which will be managed in two phases. Phase 1 will address SDG&E’s operational and management prudence surrounding the 2007 wildfires. Phase 2 will address whether SDG&E’s actions and decision-making in connection with settling legal claims in relation to the wildfires were reasonable. Evidentiary hearings in Phase 1 are scheduled to be held in January 2017, with a final decision scheduled to be issued in the second half of 2017. The procedural schedule for Phase 2 will be determined after Phase 1 is concluded.
In September 2015, the presiding judge assigned by the FERC to SDG&E’s annual Electric Transmission Formula Rate filing (TO4 Formula Cycle 2) issued an initial decision and an order on summary judgment that authorized SDG&E to recover all of the costs incurred and allocated to SDG&E’s FERC-regulated operations, including $23.1 million of costs associated with the 2007 wildfires. In October 2015, the CPUC filed a request for rehearing of the FERC’s September 2015 order, which requested abeyance of SDG&E’s request to recover 2007 wildfire damage expenses. On April 21, 2016, the FERC affirmed its findings in the September 2015 order and denied the CPUC’s request for rehearing. The FERC decision finalizes SDG&E’s base transmission revenue requirement and the $23.1 million of wildfire damage expenses.
We provide additional information about wildfire litigation costs and their recovery in Note 11.


SOCALGAS MATTERS


Aliso Canyon Natural Gas Storage Facility

We discuss various regulatory matters regarding the Aliso Canyon natural gas storage facility and leak in Note 11.


CALIFORNIA UTILITIES — MAJOR PROJECTS

We discuss the California Utilities’ major projects in detaildiscussed in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report,Report. The 2016 GRC FD was effective retroactive to January 1, 2016. SDG&E and provide updates to those discussionsSoCalGas recorded $9 million and details$12 million, respectively, in the tables below.second quarter of 2016 for the retroactive after-tax earnings impact related to the first quarter of 2016.
The 2016 GRC FD required the establishment of two-way income tax expense memorandum accounts to track any revenue differences resulting from differences between the income tax expense forecasted in the GRC and the income tax expense incurred by SDG&E and SoCalGas from 2016 through 2018. The accounts will remain open, and the balance in the accounts will be reviewed in subsequent GRC proceedings, until the CPUC decides to close them. Starting in the second quarter of 2016, SoCalGas and SDG&E began recording liabilities associated with tracking the differences in the income tax expense forecasted in the GRC proceedings and the income tax expense incurred. At March 31, 2017, the recorded liability associated with these tracked amounts totaled $39 million and $3 million for SoCalGas and SDG&E, respectively.

SDG&E and SoCalGas are scheduled to file their next GRC applications in the third quarter of 2017. The applications will seek test year revenue requirements for 2019 and attrition year adjustments for 2020 and 2021.
Risk Assessment Mitigation Phase (RAMP) Report
In December 2014, the CPUC issued a decision incorporating a risk-based decision-making framework into all future GRC application filings for major natural gas and electric utilities in California. The framework is intended to assist in assessing safety risks and the utilities’ plans to help ensure that such risks are adequately addressed. In advance of filing the California Utilities’ 2019 GRC applications, two proceedings occurred: the Safety Model Assessment Proceeding and the RAMP. In the Safety Model Assessment Proceeding, the California Utilities demonstrated the models used to prioritize and mitigate risks in order for the CPUC to establish guidelines and standards for these models.
In November 2016, SDG&E and SoCalGas filed their first RAMP report presenting a comprehensive assessment of their key safety risks and proposed activities for mitigating such risks. The report details these risks, which include critical operational issues such as natural gas pipeline safety and wildfire safety, and addresses their classification, scoring, mitigation, alternatives, safety culture, quantitative analysis, data collection and lessons learned. As part of the new framework, funding for any incremental projects or activities is not addressed in the RAMP report and would be subsequently requested in the California Utilities’ upcoming GRC applications.
In March 2017, the CPUC’s Safety and Enforcement Division issued its evaluation report providing generally favorable feedback on the California Utilities’ RAMP report, but recommending more detailed analysis of the risks we presented in the report. The new GRC framework does not require the CPUC to adopt the RAMP report, and we expect that the California Utilities will need to further refine their RAMP assessments and proposed projects and activities, which will ultimately inform the SDG&E and SoCalGas 2019 GRC applications to be filed later this year.
CPUC Cost of Capital
In February 2017, SDG&E, SoCalGas, Pacific Gas and Electric Company (PG&E) and Edison, along with the ORA and TURN, entered into a memorandum of understanding and filed a joint petition with the CPUC seeking a two-year extension for each of the utilities to file its next respective cost of capital application, extending the date to file the next cost of capital application to April 2019 for a 2020 test year. In addition to the two-year extension of the deadline to file the next cost of capital application, the memorandum of understanding contains provisions to reduce the return on equity (ROE) for SDG&E from 10.30 percent to 10.20 percent and for SoCalGas from 10.10 percent to 10.05 percent, effective from January 1, 2018 through December 31, 2019. SDG&E’s and SoCalGas’ ratemaking capital structures will remain at current levels until modified, if at all, by a future cost of capital decision by the CPUC. Also, the utilities will update their cost of capital for actual cost of long-term debt through August 2017 and forecasted cost through


2018, and update preferred stock costs for anticipated issuances (if any) through 2018. The automatic cost of capital adjustment mechanism (CCM) will be in effect to adjust 2019 cost of capital, if necessary. Unless changed by the operation of the CCM, the updated costs of long-term debt and preferred stock (if applicable) and new ROEs will remain in effect through December 31, 2019. No protests were filed in response to the joint petition, and the CPUC issued a proposed decision in April 2017 approving the request. The proposed decision was subsequently withdrawn. We expect that a proposed decision will again be issued.
MAJOR PROJECTS – UPDATES
Joint Utilities Projects
Southern Gas System Reliability Project
§In April 2016, the CPUC issued a proposed decision finding that there is a need for enhanced system reliability for the southern portion of the SoCalGas and SDG&E gas system, but concluding that the utilities have failed to demonstrate that there is a need for their proposed pipeline project. Instead, the proposed decision determines that certain non-physical alternatives will provide enhanced supply reliability, without the need to construct pipeline facilities.
§At March 31, 2016, SoCalGas has approximately $23 million of development costs invested in the project, classified as Property, Plant and Equipment on Sempra Energy's and SoCalGas' Condensed Consolidated Balance Sheets. Some or all of these assets could become impaired if the project and potential alternative uses for these assets were ultimately rejected by the CPUC. SoCalGas and SDG&E filed comments with the CPUC in April 2016.
Pipeline Safety & Reliability Project
§SDG&E and SoCalGas filed an amended application with the CPUC in March 2016 providing detailed analysis and testimony supporting the proposed project. The revised request also presents additional information on the costs and benefits of project alternatives, safety evaluation and compliance analysis, and statutory and procedural requirements. SDG&E and SoCalGas seek approval to construct the proposed project, estimated at a cost of $633 million, and authority to recover the associated revenue requirement in rates.
SDG&E Projects
Cleveland National Forest (CNF) Transmission Projects
§In March 2016, the U.S. Forest Service issued a final decision authorizing issuance of the CNF Master Special Use Permit renewing SDG&E's land rights and authorizing the construction, operation and maintenance of facilities located on national forest lands for the next 50 years, as well as approving the majority of the fire-hardening activities proposed by SDG&E.
§Proposed decision issued by the CPUC in April 2016, which granted SDG&E a permit to construct. Final CPUC decision expected in the second quarter of 2016.
Sycamore-Peñasquitos Transmission Project
§March 2016 final environmental impact report (EIR) recommended an alternative that undergrounds more of the project than originally proposed, and is viewed as environmentally superior. The CPUC may consider this alternative.
§CPUC's recommended alternative has an estimated cost of $250 million to $300 million, compared to the original project cost estimate of $120 million to $150 million, and would also delay the project schedule by approximately 10 months.
§CPUC decision expected in the second half of 2016.
South Orange County Reliability Enhancement
§CPUC issued its final EIR for the project in April 2016. The EIR concluded that an alternative project is considered environmentally superior to SDG&E's proposal. The final EIR states that the CPUC is not required to adopt the environmentally superior alternative if there are overriding considerations in favor of another alternative. The CPUC will consider the findings in determining whether to approve SDG&E's proposed project or an alternative to it.
§Final CPUC decision expected in the second half of 2016.
     

NOTE 11. COMMITMENTS AND CONTINGENCIES


LEGAL PROCEEDINGS

We accrue losses for a legal proceeding when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. However, the uncertainties inherent in legal proceedings make it difficult to estimate with reasonable certainty the costs and effects of resolving these matters. Accordingly, actual costs incurred may differ materially from amounts accrued, may exceed applicable insurance coverage and could materially adversely affect our business, cash flows, results of operations, financial condition and prospects. Unless otherwise indicated, we are unable to estimate reasonably possible losses in excess of any amounts accrued.
At March 31, 2016, Sempra Energy’s2017, accrued liabilities for legal proceedings, including associated legal fees and costs of litigation, on a consolidated basis, were $37 million. At March 31, 2016, accrued liabilities$18 million for legal proceedingsSempra Energy Consolidated, including $11 million for SDG&E and $5 million for SoCalGas. Amounts for Sempra Energy and SoCalGas were $29include $5 million and $6 million, respectively, excluding amounts for matters related to the Aliso Canyon natural gas leak, which we discuss below.



SDG&E
2007 Wildfire Litigation

In October 2007, San Diego County experienced several catastrophic wildfires. Reports issued by the California Department of Forestry and Fire Protection (Cal Fire) concluded that two of these fires (the Witch and Rice fires) were SDG&E “power line caused” and that a third fire (the Guejito fire) occurred when a wire securing a Cox Communications’ (Cox) fiber optic cable came into contact with an SDG&E power line “causing an arc and starting the fire.” A September 2008 staff report issued by the CPUC’s Consumer Protection and Safety Division, now known as the Safety and Enforcement Division, reached substantially the same conclusions as the Cal Fire reports, but also contended that the power lines involved in the Witch and Rice fires and the lashing wire involved in the Guejito fire were not properly designed, constructed and maintained.
Numerous parties sued SDG&E and Sempra Energy in San Diego County Superior Court seeking recovery of unspecified amounts of damages, including punitive damages, from the three fires. They asserted various bases for recovery, including inverse condemnation based upon a California Court of Appeal decision finding that another California investor-owned utility was subject to strict liability, without regard to foreseeability or negligence, for property damages resulting from a wildfire ignited by power lines. SDG&E has resolved almost all of these lawsuits. One case remains subject to a damages-only trial, where the value of any compensatory damages resulting from the fires will be determined.lawsuits associated with three wildfires that occurred in October 2007. Two appeals areremain pending after judgment in the trial court. SDG&E does not expect additional plaintiffs to file lawsuits given the applicable statutes of limitation, but could receive additional settlement demands and damage estimates from the remaining plaintiffplaintiffs until the case iscases are resolved. SDG&E establishesmaintains reserves for the wildfire litigation and makes adjustments to these reserves as information becomes available and amounts are estimable.
SDG&E has concluded that it is probable that it will be permitted to recover in rates a substantial portion of the costs incurred to resolve wildfire claims in excess of its liability insurance coverage and the amounts recovered from third parties. Accordingly, at March 31, 2016,2017, Sempra Energy and SDG&E have recorded assets of $363$350 million in Regulatory Assets (long-term) and Other Regulatory Assets (long-term), respectively, on their Condensed Consolidated Balance Sheets including $360($349 million related to CPUC-regulated operations which represents the amount substantially equaland $1 million related to the aggregate amount it has paid and reserved for payment for the resolution of wildfire claims and related costs in excess of its liability insurance coverage and amounts recovered from third parties. OnFederal Energy Regulatory Commission (FERC)-regulated operations). In September 25, 2015, SDG&E filed an application with the CPUC seeking authority to recover these CPUC-related costs as we discuss in Note 10.rates over a six- to ten-year period. The requested amount is the net estimated CPUC-related cost incurred by SDG&E after deductions for insurance reimbursement and third party settlement recoveries, and reflects a voluntary 10-percent shareholder contribution applied to the net Wildfire Expense Memorandum Account balance. In April 2016, the CPUC issued a ruling establishing the scope and schedule for the proceeding, which will be managed in two phases. Phase 1 addresses SDG&E’s operational and management prudence surrounding the 2007 wildfires. We expect a final CPUC decision in late 2017. Phase 2 will address whether SDG&E’s actions and decision-making in connection with settling legal claims in relation to the wildfires were reasonable, with a final CPUC decision expected by early 2019. Should SDG&E conclude that recovery in rates is no longer probable, SDG&E will record a charge against earnings at the time such conclusion is reached. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated at March 31, 2016,2017, the resulting after-tax charge against earnings would have been up to approximately $213$207 million. A failure to obtain substantial or full recovery of these costs from customers, or any negative assessment of the likelihood of recovery, would likely have a material adverse effect on SDG&E’s and Sempra Energy’s and SDG&E’s results of operations and cash flows.
We provide additional information about excess wildfire claims cost recovery and related CPUC actions in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report and discuss how we assess the probability of recovery of our regulatory assets in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
Smart Meters Patent Infringement Lawsuit
In October 2011, SDG&E was sued by a Texas design and manufacturing company in Federal District Court, Southern District of California, and later transferred to the Federal District Court, Western District of Oklahoma as part of Multi-District Litigation (MDL) proceedings, alleging that SDG&E’s recently installed smart meters infringed certain patents. The meters were purchased from a third party vendor that has agreed to defend and indemnify SDG&E. The lawsuit seeks injunctive relief and recovery of unspecified amounts of damages. The MDL court has finished ruling on pre-trial matters, and SDG&E expects that it will return the case to the Southern District of California.
Lawsuit Against Mitsubishi Heavy Industries, Ltd.MHI
On July 18, 2013, SDG&E filedparticipated as a lawsuitclaimant and respondent in the Superior Court of California in the County of San Diego against Mitsubishi Heavy Industries, Ltd., Mitsubishi Nuclear Energy Systems, Inc., and Mitsubishi Heavy Industries America, Inc. (collectively MHI). The lawsuit seeks to recover damages SDG&E has incurred and will incur related to the design defects in the steam generators MHI provided to the SONGS nuclear power plant. The lawsuit asserts a number of causes of action, including fraud, based on the representations MHI made about its qualifications and ability to design generators free from defects of the kind that resulted in the permanent shutdown of the plant and further seeks to set aside the contractual limitation of damages that MHI has asserted. On July 24, 2013, MHI removed the lawsuit to the United States District Court for the Southern District of California and on August 8, 2013, MHI moved to stay the proceeding pending resolution of the dispute resolution process involving MHI and Edison arising from their contract for the purchase and sale of the steam generators. On October 16, 2013, Edison initiated an arbitration proceeding initiated by Edison in October 2013 against MHI seeking damages stemming from the failure of the MHI replacement steam generators.generators at the SONGS nuclear power plant. In late December 2013, MHI answered and filed a counterclaim against Edison. On March 14, 2014, MHI’s motion to stay the United States District Court proceeding was granted with instructions that require the parties to allow SDG&E to participate in the ongoing Edison/MHI arbitration. As a result, SDG&E participated in the arbitration as a claimant and respondent. The arbitration hearing concluded at the end of April 2016, and a decision could come as early as this year.2016.

Investment in Wind Farm

In 2011,March 2017, the CPUC and FERC approved SDG&E’s estimated $285 million tax equity investment in a wind farm project and its purchaseTribunal found MHI liable for breach of renewable energy credits from that project. SDG&E’s contractual obligations to both invest in the Rim Rock wind farm and to purchase renewable energy credits from the wind farm under the power purchase agreement arecontract, subject to the satisfactiona contractual limitation of certain conditions which, if not achieved, would allow SDG&E to terminate the power purchase agreement and not make the investment. In December 2013, SDG&E received a closing notice from the project developer indicating that all such conditions had been met. SDG&E responded to the closing notice asserting that the contractual conditions had not been satisfied. On December 19, 2013, SDG&E filed a complaint against the project developer in San Diego Superior Court, asking that the court determine that SDG&E is entitled to terminate both the investment contract and the power purchase agreement due to the project developer’s failure to satisfy certain conditions. The project developer filed a separate complaint against SDG&E in Montana state court asking that court to determine that SDG&E breached the investment contract and the power purchase agreement, and asking for several categories of relief, including requiring SDG&E to invest in the project, requiring SDG&E to continue performing under the power purchase agreement, and payment of damages.
On January 27, 2014, the Montana court ordered SDG&E to continue making payments under the power purchase agreement pending a hearing on the project developer’s preliminary injunction motion. On March 14, 2014, SDG&E notified the project developer that the investment agreement expired by its own terms because a closing had not occurred by that date. The project developer disputed SDG&E’s position. On March 28, 2014, SDG&E filed an amended complaint against the project developer in San Diego seeking damages and declaratory relief that SDG&E was entitled to terminate the power purchase agreement and to permit the investment agreement to expire. On April 25, 2014, the Montana court granted the project developer’s preliminary injunction motion to prevent SDG&E from terminating the power purchase agreement on the grounds that the project developer would be irreparably harmed if the payments were not made while the parties’ respective rights were being determined in the litigation. The court did not rule on the merits of the parties’ claims. On July 18, 2014, the Montana Supreme Courtliability, but determined that MHI was the parties’ contractual agreement to resolve any disputesprevailing party and awarded it 95 percent of its arbitration costs. We discuss this arbitration and decision further in San Diego was mandatory, and ordered that the Montana action be dismissed. The San Diego court has scheduled a trial in May 2016. On February 11, 2016, SDG&E, the project developer and several of the project developer’s parent and affiliated entities entered into a conditional settlement agreement. Under the conditional settlement agreement, among other things, the parties agreed to terminate the tax equity investment arrangement, continue the power purchase agreement for the wind farm generation, and release all claims against each other. The conditional settlement agreement will not result in rate increases to SDG&E customers or a material impact on Sempra Energy’s or SDG&E’s financial condition, results of operations or cash flows. On February 16, 2016, SDG&E and the project developer filed a petition for approval of the settlement agreement with the CPUC. The conditional settlement agreement is not fully effective until approved by the CPUC; SDG&E expects a decision in 2016. The May 2016 trial date set in the San Diego court has been stayed until the settlement is addressed by the CPUC.

Note 9.
SoCalGas
Aliso Canyon Natural Gas Storage Facility Gas Leak
InOn October 23, 2015, SoCalGas discovered a leak at one of its injection and withdrawalinjection-and-withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility, located in the northern part of the San Fernando Valley in Los Angeles County. The Aliso Canyon facility has been operated by SoCalGas since 1972. SS25 is more than one mile away from and 1,200 feet above the closest homes. It is one of more than 100 injection and withdrawalinjection-and-withdrawal wells at the storage facility.
Stopping the Leak, and Local Community Mitigation Efforts. SoCalGas worked closely with several of the world’s leading experts to stop the leak, including planning and obtaining all necessary approvals for drilling relief wells. Onon February 18, 2016, the California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources (DOGGR) confirmed that the well was permanently sealed.
On December 24, 2015, byPursuant to a stipulation and court order SoCalGas agreed to implement a formal plan for assisting residents inby the nearby community to temporarily relocate, as well as to pay for additional overtime and costs associated with extra Los Angeles Police Department security patrols, among other things.County Superior Court (Superior Court), SoCalGas has been providingprovided temporary relocation support to residents in the nearby community who requested it before the well was permanently sealed. In addition, SoCalGas provided air filtration and purification systems to those residents inFollowing the nearby community requesting them.
As a result of receiving the confirmation from DOGGR that SS25 was permanently sealed, SoCalGas started winding down its temporary relocation support in accordance with the termspermanent sealing of the formal relocation plan. Subject to certain exceptions, the period for temporary relocation support to residents who temporarily relocated to short-term housing, such as hotels, was scheduled to end on February 25, 2016. This deadline was challenged by the County of Los Angeles (County), who expressed concern about potential lingering health effects and stated that they intended to perform indoor air testing. The California Superior Court issued an order extending such period for an additional 22 days for certain residents. On March 18, 2016, the County sought a further extension through the end of the litigation, which was denied, but the Superior Court stayed its order pending a potential appeal to the California Court of Appeal. Following an appeal by the County, on April 13, 2016, the Court of Appeal remanded the matter back to the California Superior Court for further consideration of the record and extended the relocation support term to at least April 27, 2016. The Superior Court set the matter for hearing on April 27, 2016, and gave the parties an opportunity to file supplemental briefing and evidence. On April 27, 2016, the Superior Court heard oral argument on the matter and ultimately entered an order further extending the relocation support term pending the completion of the County’s indoor testing. The Superior Court set a case management conference on June 7, 2016, for further consideration of the relocation program, and instructed the County and SoCalGas to file a joint update with the Court on May 31, 2016 regarding the status of the relocation support.
To put the relocation dispute in perspective, on January 31, 2016,well, the Los Angeles County Department of Public Health (LA County DPH) stated, “The average levels(DPH) conducted indoor testing of benzene and other trace chemicals that have been measuredcertain homes in the Porter Ranch community, are currently at or below levels seen elsewhere in the county, and do not pose an increase in the risk of short‐term or long‐term health effects.” Following the sealing of the well, included in its April 9, 2016 update to its Aliso Canyon webpage, the LA County DPH affirmed that “levels of chemicals of concern are now consistent with expected background levels for the Los Angeles air basin.”
In seeking the extension of the relocation support term, the County has contendedconcluded that indoor testing is required in order to determine whetherconditions did not present a long-term health risk and that it iswas safe for residents to return home. On March 24,In May 2016, the County released its indoor sampling work planSuperior Court ordered SoCalGas to test approximately 100 houses foroffer to clean residents’ homes at SoCalGas’ expense as a broad rangecondition to ending the relocation program. SoCalGas completed the residential cleaning program and the relocation program ended in July 2016.
Apart from the Superior Court order, 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 chemicals, including volatile organic compounds, semi-volatile organic compounds, metals, and sulfur compounds in the air and on surfaces. These substances are commonly found in households at varying levels. We were informed that this testing was completed on April 8, 2016, and that the County is currently analyzing the results. The County has reported that it anticipates completing its analysis and releasing a final report by late May 2016. In mid-March 2016, a third party engaged by SoCalGas conducted screening of indoor air for methane and mercaptans (odorants added to natural gas) in 71 houses inall residents located within the Porter Ranch community nearNeighborhood 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. Based on this screening, no mercaptans were detected,facility and concentrationshave experienced symptoms from the natural gas leak (the Directive). SoCalGas disputes the Directive, contending that it is invalid and unenforceable, and has filed a petition for writ of methane were well below levels of concern as established bymandate to set aside the California Environmental Protection Agency’s Department of Toxic Substances Control.
Directive.
The total costs incurred to remediate and stop the leak and to mitigate local community impacts will beare significant and may increase, and we may be subject to civil or administrative fines, costs or other penalties, if awarded or imposed. To the extent any of these costs are 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.
Cost Estimates and Accounting Impact. AtAs of March 31, 2016,2017, SoCalGas recorded estimated costs of $665$799 million related to the leak. Of this amount, approximately 70 percent is for the temporary relocation program (including cleaning costs and certain labor costs) and approximately 1520 percent is for attemptsefforts to control the well, stop the leak, stop or reduce the emissions, and the estimated cost of the root cause analysis being conducted by an independent third party to determine the cause of the leak. The remaining amountportion of the $799 million includes estimated legal costs necessaryincurred to defend litigation, the value of lost gas, the costs to mitigate the actual natural gas released, and other costs. As the value of lost gas reflects the current replacement cost, the value may fluctuate until such time as replacement gas is purchased and injected into storage. SoCalGas made a commitment in December 2015 to mitigateadjusts its estimated total liability associated with the actual natural gas released and has been working on a plan to accomplish the mitigation.leak as additional information becomes available. The $665$799 million represents management’s best estimate of these costs related to the leak. Of these costs, certain amounts havea substantial portion has been paid and $302$49 million is recordedaccrued as Reserve for Aliso Canyon Costs atas of March 31, 20162017 on SoCalGas’ and Sempra Energy’s Condensed Consolidated Balance Sheets for amounts expected to be paid after March 31, 2016. We will refine these estimates as further information becomes available. SoCalGas’ estimate2017.
As of temporary relocation costs was primarily determined considering the current experience of temporary relocations through the hearing date of April 27, 2016 discussed above. The remainder of the reserve was estimated primarily based on work plans, the rate of cost accumulation and estimated duration of the various activities, or other estimates. Any differences in actual costs incurred will impact these estimates. Based on the order of the Superior Court on April 27, 2016, which scheduled the next hearing on June 7, 2016, for purposes of this estimate we assume the period for temporary relocation support to residents who temporarily relocated has been extended to June 7, 2016. While such support period could end before June 7, 2016, due to the fact that temporary relocation support has been extended several times, there can be no assurance that future extensions will not be granted. The cost of the temporary relocation support is significant, and the costs of any further extensions of the relocation support term, which are not included in our estimate, could result in a material increase in our cost estimate.
At March 31, 2016,2017, we recorded the expected recovery of the costs described in the immediately preceding paragraph related to the leak (less insurance retentions) of $660$621 million as Insurance Receivable for Aliso Canyon Costs on SoCalGas’ and Sempra Energy’s Condensed Consolidated Balance Sheets. This amount is net of insurance retentions and $173 million of insurance proceeds we received through March 31, 2017 related to control-of-well expenses and temporary relocation costs. If we were to conclude that this receivable or a portion of it was no longer probable of recovery from insurers, some or all of this receivable would be charged against earnings.
earnings, which could have a material adverse effect on SoCalGas’ and Sempra Energy’s financial condition, results of operations and cash flows.
The above amounts do not include any unsettled damage awards,claims, restitution, or any civil, administrative or criminal fines, costs or other penalties that may be imposed in connection with the incident or our responses thereto, as it is not possible to predict the outcome of any criminalcivil or civilcriminal proceeding or any administrative action in which such damage awards, restitution or civil, administrative or criminal fines, costs or other penalties could be imposed, and any such amounts, if awarded or imposed or otherwise paid, cannot be reasonably estimated at this time. In addition, the recorded amounts above amounts do not include the costs to clean additional homes pursuant to the DPH Directive, future legal costs necessary to defend litigation, and other potential costs that we currently do not anticipate incurring or that we cannot reasonably estimate.

On
In March 17, 2016, the CPUC issued a decision directingordered SoCalGas to establish a memorandum account to prospectively track its authorized revenue requirement and all revenues that it receives for its normal, business-as-usual costs to own and operate the Aliso Canyon gas storage field.field and, in September 2016, approved SoCalGas’ request to begin tracking these revenues as of March 17, 2016. The CPUC will determine at a later time whether, and to what extent, the authorized revenues tracked revenuesin the memorandum account may be refunded to ratepayers. Pursuant to the CPUC’s decision, on March 24, 2016, SoCalGas filed an advice letter requesting to establish a memorandum account to track all business-as-usual costs to own
Insurance. Excluding directors and operate the Aliso Canyon storage field, which has been protested by TURN and SCGC. On April 22, 2016, the CPUC’s Energy Division issued a suspension notice for SoCalGas’ advice letter citing the need for additional time for staff review. This suspension period could last up to 120 days.
Insurance. Weofficers liability insurance, we have at least four kinds of insurance policies that together provide in excess of $1between $1.2 billion to $1.4 billion in insurance coverage.coverage, depending on the nature of the claims. We cannot predict all of the potential categories of costs or the total amount of costs that we may incur as a result of the leak. In reviewing each of our policies, and subjectSubject to various policy limits, exclusions and conditions, based upon what we know as of the filing date of this report, we believe that our insurance policies collectively should cover the following categories of costs: the costs incurred for temporary relocation (including cleaning costs and certain labor costs), costs to address the leak and stop or reduce emissions, the root cause analysis being conducted to determine the cause of the leak, the value of lost natural gas, and estimated costs incurred to mitigate the actual natural gas released, the costs associated with litigation and claims by nearby residents and businesses, any costs to clean additional homes pursuant to the DPH Directive, and, in some circumstances depending on their nature and manner of assessment, fines and penalties. We have been communicating with our insurance carriers and, as discussed above, we have received insurance payments for a portion of control-of-well expenses and a portion of temporary relocation costs. We intend to pursue the full extent of our insurance coverage.coverage for the costs we have incurred or may incur. 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, itsuch costs could result inhave a material charge against the earnings of SoCalGasadverse effect on SoCalGas’ and Sempra Energy.
Energy’s cash flows, financial condition and results of operations.
Our recorded estimate atas of March 31, 20162017 of $665$799 million of certain costs in connection with the Aliso Canyon storage facility leak may rise significantly as more information becomes available, and toany costs not included in our estimate could be material. 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 and SoCalGas’ cash flows, financial condition and results of operations. In addition, the costs not included in the $665 million estimate could be material, and to the extent not covered by insurance, could have a material adverse effect on Sempra Energy’s and SoCalGas’ cash flows, financial condition and results of operations.
Governmental Investigations and Civil and Criminal Litigation. Various governmental agencies, including the DOGGR, LA County DPH, South Coast Air Quality Management District (SCAQMD), California Air Resources Board (CARB), Los Angeles Regional Water Quality Control Board, California Division of Occupational Safety and Health, (DOSH), CPUC, Pipeline and Hazardous Materials Safety Administration (PHMSA), U.S. Environmental Protection Agency (EPA), Los Angeles County District Attorney’s Office and California Attorney General’s Office, have investigated or are investigating this incident. OnOther federal agencies (e.g., the U.S. Department of Energy (DOE) and the U.S. Department of the Interior) investigated the incident as part of the joint interagency task force discussed below. In January 25, 2016, the DOGGR and the CPUC selected Blade Energy Partners (Blade) to conduct an independent analysis under their supervision and to be funded by SoCalGas to investigate the technical root cause of the Aliso Canyon gas leak. We expectThe timing of the root cause analysis to be completed in late 2016 or early 2017, butis under the timing is dependent on thecontrol of Blade, DOGGR and the CPUC.
As of April 28, 2016, 138May 8, 2017, 266 lawsuits, have been filed (134including over 22,000 plaintiffs, are pending in the Los Angeles County Superior Court 2 in San Diego County Superior Court, and 2 in the United States District Court for the Southern District of California) against SoCalGas, some of which have also named Sempra Energy, and, in derivative and securities law claims on behalf of Sempra Energy and/or SoCalGas, certain officers and directors of Sempra Energy and/or SoCalGas.Energy. These various lawsuits assert causes of action for negligence, negligence per se, strict liability, property damage, fraud, public and private nuisance (continuing and permanent), trespass, breachinverse condemnation, fraudulent concealment, unfair business practices and loss of fiduciary duties, and violation of federal securities laws,consortium, among other things, and additional litigation may be filed against us in the future related to this incident. ManyA complaint alleging violations of theseProposition 65 was also filed. These complaints seek compensatory and punitive damages, civil penalties, injunctive relief, costs of future medical monitoring and attorneys’ fees, and several seek class action status,status. All of these cases, other than a matter brought by the Los Angeles County District Attorney, the federal securities class action and one of the shareholder derivative actions discussed below, are coordinated before a single court in the Los Angeles County Superior Court for pretrial management.
In addition to the lawsuits described above, a federal securities class action alleging violation of the federal securities laws has been filed against Sempra Energy and certain of its officers and certain of its directors in the United States District Court for the Southern District of California (SDCA), and five shareholder derivative actions alleging breach of fiduciary duties against certain officers and certain directors of Sempra Energy and/or SoCalGas are pending, one in the SDCA and four in the coordination proceeding in the Los Angeles County Superior Court. In March 2017, the SDCA dismissed the shareholder derivative action pending in that court, ruling that the plaintiff did not have standing to pursue the alleged claims; the plaintiff was given leave to seek to amend his complaint to cure its deficiencies.
Pursuant to the coordination proceeding in the Los Angeles County Superior Court, in March 2017, the individuals and business entities asserting tort and Proposition 65 claims filed a Second Amended Consolidated Master Case Complaint for Individual Actions, through which their separate lawsuits will be managed for pretrial purposes. The consolidated complaint asserts causes of action for negligence, negligence per se, private and public nuisance (continuing and permanent), trespass, inverse condemnation, strict liability, negligent and intentional infliction of emotional distress, fraudulent concealment, loss of consortium and violations of Proposition 65 against SoCalGas, with certain causes also naming Sempra Energy. The consolidated complaint seeks compensatory and punitive damages for personal injuries, lost wages and/or lost profits, property damage and diminution in property value, injunctive relief, costs


of future medical monitoring, civil penalties (including penalties associated with Proposition 65 claims alleging violation of requirements for warning about certain chemical exposures), and attorneys’ fees.
In January 2017, pursuant to the coordination proceeding, two consolidated class action complaints were filed against SoCalGas and Sempra Energy, one on behalf of a putative class of persons and businesses who own or lease real property within a five-mile radius of the well (the Property Class Action), and a second on behalf of a putative class of all persons and entities conducting business within five miles of the facility (the Business Class Action). Both complaints assert claims for strict liability for ultra-hazardous activities, negligence and violation of California Unfair Competition Law. The Property Class Action also asserts claims for negligence per se, trespass, permanent and continuing public and private nuisance, and inverse condemnation. The Business Class Action also asserts a claim for negligent interference with prospective economic advantage. Both complaints seek compensatory, statutory and punitive damages, injunctive relief and attorneys’ fees. The Los Angeles City Attorney and
Three actions filed by public entities are pending, as follows. These lawsuits are also included in the coordination proceeding in the Los Angeles County Counsel have also filed a complaintSuperior Court. First, in July 2016, the County of Los Angeles, on behalf of itself and the people of the State of California, filed a complaint against SoCalGas in the Los Angeles County Superior Court for public nuisance, unfair competition, breach of franchise agreement, breach of lease, and violationdamages. This suit alleges that the four natural gas storage fields operated by SoCalGas in Los Angeles County require safety upgrades, including the installation of a sub-surface safety shut-off valve on every well. It additionally alleges that SoCalGas failed to comply with the California Unfair Competition Law. TheDPH Directive. It seeks preliminary and permanent injunctive relief, civil penalties, and damages for the County’s costs to respond to the leak, as well as punitive damages and attorneys’ fees.
Second, in August 2016, the California Attorney General, acting in heran independent capacity and on behalf of the people of the State of California and the CARB, joined this lawsuit. Thetogether with the Los Angeles City Attorney, filed a third amended complaint which as amended includeson behalf of the people of the State of California against SoCalGas alleging public nuisance, violation of the California Attorney General, adds allegations ofUnfair Competition Law, violations of California Health and Safety Code sections 41700, prohibiting discharge of air contaminants that cause annoyance to the public, and 25510, requiring reporting of the release of hazardous material, as well as California Government Code section 12607 for equitable relief for the protection of natural resources. The complaint seeks an order for injunctive relief, to abate the public nuisance, and to impose civil penalties. The SCAQMD also
Third, in March 2017, the County of Los Angeles filed a petition for writ of mandate against DOGGR and its State Oil & Gas Supervisor, as to which SoCalGas is the real party in interest. The petition alleges that DOGGR has failed to comply with the provisions of Senate Bill (SB) 380, which requires a comprehensive safety review of the Aliso Canyon facility before injection of natural gas may resume, because DOGGR declared the safety review complete before the root cause analysis was complete. The County further alleges that the California Environmental Quality Act requires DOGGR to perform an Environmental Impact Review before the resumption of injection of natural gas at the facility may be approved. The petition seeks a writ of mandate requiring DOGGR and the State Oil & Gas Supervisor to comply with SB 380, and declaratory and injunctive relief against any authorization to inject natural gas, as well as attorneys’ fees.
A complaint filed by the SCAQMD against SoCalGas seeking civil penalties for alleged violations of several nuisance-related statutory provisions arising from the leak and delays in stopping the leak. That suit seeks upleak was settled in February 2017, pursuant to $250,000which SoCalGas paid $8.5 million, of which $1 million is to be used to pay for a health study. The SCAQMD’s complaint was dismissed in civil penalties for each day the violations occurred.February 2017.
OnSeparately, in February 2, 2016, the Los Angeles County District Attorney’s Office filed a misdemeanor criminal complaint against SoCalGas seeking penalties and other remedies for alleged failure to provide timely notice of the leak pursuant to California Health and Safety Code section 25510(a), Los Angeles County Code section 12.56.030, and Title 19 California Code of Regulations section 2703(a), and for allegedly violating California Health and Safety Code section 41700 prohibiting discharge of air contaminants that cause annoyance to the public.
In September 2016, SoCalGas entered into a settlement agreement with the District Attorney’s Office in which it agreed to plead no contest to the notice charge under Health and Safety Code section 25510(a) and agreed to pay the maximum fine of $75,000, penalty assessments of approximately $233,500, and up to $4 million in operational commitments, reimbursement and assessments in exchange for the District Attorney’s Office moving to dismiss the remaining counts at sentencing and settling the complaint (collectively referred to as the District Attorney Settlement). In November 2016, SoCalGas completed the commitments and obligations under the District Attorney Settlement, and on November 29, 2016, the Court approved the settlement and entered judgment on the notice charge. Certain individuals residing near Aliso Canyon who objected to the settlement have filed a notice of appeal of the judgment, as well as a petition asking the Superior Court to set aside the November 29, 2016 order and grant them restitution. The Superior Court dismissed the petition in January 2017, ruling that the petitioners have a remedy at law via their direct appeal.
The costs of defending against these civil and criminal lawsuits, and cooperating with these investigations, and any damages, restitution, and civil, administrative and criminal fines, costs and other penalties, 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.
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 proceeding will be conducted in two phases, with Phase 1 conducting an analysis of the feasibility of reducing or eliminating the use of Aliso Canyon and Phase 2 considering the potential implementation of the Phase 1 analysis. In accordance with the Phase 1 schedule, public participation hearings began in April 2017, and workshops are expected to occur later in 2017.
The scope of the order, which is subject to modification, expressly excludes issues with respect to air quality, public health, causation, culpability or cost responsibility regarding the Aliso Canyon gas 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 facility or any portion of that facility has been out of service for nine consecutive months, SoCalGas provided notification for transparency, and because the process for obtaining authorization to resume injection operations at the facility is taking longer to complete than initially contemplated. In response, and as required by Section 455.5, the CPUC issued a draft OII to address whether the Aliso Canyon facility or any portion of that facility has been out of service for nine consecutive months pursuant to Section 455.5, and if it is determined to have been out of service, whether the CPUC should adjust SoCalGas’ rates to reflect the period the facility is deemed to have been out of service. If the CPUC adopts the order as drafted and as required under Section 455.5, hearings on the investigation will be consolidated with SoCalGas’ next GRC proceeding. In the event that the CPUC determines that all or any portion of the facility has been 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 and results of operations.
Governmental Orders and Additional Regulation and Reliability. OnRegulation. In January 6, 2016, the Governor of the State of California issued the Governor’san Order proclaiming a state of emergency to exist in Los Angeles County due to the natural gas leak at the Aliso Canyon facility. The Governor’s Order implemented orders to stop the leak and implementsimposes various other orders with respect to: stopping the leak; protecting public health and safety; ensuring accountability; and strengthening oversight. Most of the directives in the Governor’s Order have been fulfilled, with the following remaining open items: (1) the prohibition against SoCalGas injecting any natural gas into the Aliso Canyon facility will continue until a comprehensive review, utilizing independent experts, of the safety of the storage wells is completed; (2) applicable agencies must convene an independent panel of scientific and medical experts to review public health concerns stemming from the natural gas leak and evaluate whether additional measures are needed to protect public health; (3) the CPUC must ensure that SoCalGas covers costs related to the natural gas leak and its response, while protecting ratepayers, and CARB was ordered to develop a program to fully mitigate the leak’s emissions of methane by March 31, 2016, with such program to be funded by SoCalGas; and (4) DOGGR, CPUC, CARB and California Energy Commission (CEC) must submit to the Governor’s Office a report that assesses the long-term viability of natural gas storage facilities in California.
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Protecting Public Health and Safety: State agencies will: continue the prohibition against SoCalGas injecting any gas into the Aliso Canyon storage facility until a comprehensive review, utilizing independent experts, of the safety of the storage wells and the air quality of the surrounding community is completed; expand real-time monitoring of emissions in the surrounding community; convene an independent panel of scientific and medical experts to review public health concerns stemming from the natural gas leak and evaluate whether additional measures are needed to protect public health; and take all actions necessary to ensure the continued reliability of natural gas and electricity supplies in the coming months during the moratorium on gas injections into the Aliso Canyon storage facility.
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Ensuring Accountability: The CPUC will ensure that SoCalGas covers costs related to the natural gas leak and its response, while protecting ratepayers; and CARB will develop a program to fully mitigate the leak’s emissions of methane by March 31, 2016, with such program to be funded by SoCalGas.
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Strengthening Oversight: The DOGGR will promulgate emergency regulations for gas storage facility operators throughout the state, requiring: at least daily inspection of gas storage well heads using gas leak detection technology such as infrared imaging; ongoing verification of the mechanical integrity of all gas storage wells; ongoing measurement of annular gas pressure or annular gas flow within wells; regular testing of all safety valves used in wells; minimum and maximum pressure limits for each gas storage facility in the state; and a comprehensive risk management plan for each facility that evaluates and prepares for risks, including corrosion potential of pipes and equipment. Additionally, the DOGGR, the CPUC, the CARB and the California Energy Commission will submit to the Governor’s Office a report that assesses the long-term viability of natural gas storage facilities in California.
In December 2015, SoCalGas made a commitment in December 2015 to mitigate the actual natural gas released from the leak and has been working on a plan to accomplish the mitigation. OnIn March 31, 2016, pursuant to the Governor’s Order, the CARB issued its Aliso Canyon Methane Leak Climate Impacts Mitigation Program, which sets forth its recommended approach to achieve full mitigation of the emissions from the Aliso Canyon natural gas leak. The CARB program preliminarily assumes that the leak released approximately 100,000 metric tons of methane. It states that full mitigation requires that the program generate reductions in short-lived climate pollutants and other greenhouse gases be at least equivalent to thatthe amount of the emissions from the leak, and that the appropriate global warming potential to be used in deriving the amount of reductions required is based on a 20-year term rather(rather than the 100-year term the CARB and other state and federal agencies use in regulating emissions,emissions), resulting in a target of approximately 8,000,0009,000,000 metric tons of carbon dioxide equivalent. CARB’s program also requiresprovides that all of the mitigation is to occur in California over the next five to ten years without the use of allowances or offsets. In October 2016, CARB issued its final report concluding that the incident resulted in total emissions from 90,350 to 108,950 metric tons of methane, and asserting that SoCalGas should mitigate 109,000 metric tons of methane to fully mitigate the greenhouse gas impacts of the leak. We have not agreed to this proposed formulationwith CARB’s estimate of methane released and continue to work with CARB on thedeveloping a mitigation plan.
OnIn January 23, 2016, the Hearing Board of the SCAQMD ordered SoCalGas to among other things: stop all injections oftake various actions in connection with injecting and withdrawing natural gas except as directed by the CPUC, withdraw the maximum amount of natural gas feasible in a contained and safe manner, subject to orders of the CPUC, and permanently seal the well once the leak has ceased; continuously monitor the well site with infrared cameras until 30 days after the leak has ceased; provide the public with daily air monitoring data collected by SoCalGas; provide the SCAQMD with certain natural gas injection, withdrawal and emissions data from the Aliso Canyon facility; prepare and submit to the SCAQMD for its approval an enhanced leak detection and reporting well inspection program for the Aliso Canyon facility; provide the SCAQMD with funding to develop a continuous air monitoring plan for the Aliso Canyon facility and the nearby schools and community; prepare and submit to the SCAQMD for its approval an air quality notification plan to provide notice to SCAQMD, other public agencies and the nearby community in the event of a future reportable release; and provide the SCAQMD with funding to conduct an independent health study on the potential impacts of exposure on the constituents of the natural gas released from the facility, as well as any odor suppressants used to mitigate odors from the leaking well.
On April 1, 2016, the Secretary of the U.S. Department of Energy (DOE) and PHMSA jointly announced the formation of an Interagency Task Force on Natural Gas Storage Safety in response to the leak at Aliso Canyon, sealing the well, monitoring, reporting, safety and funding a health impact study, among other things (Abatement Order). SoCalGas fulfilled its obligations under the Abatement Order to assess and make recommendations on best practices, response plans and safe operation of gas storage facilities. PHMSA has indicated plans to initiate additional regulatory actions on natural gas storage nationally. Eachthe satisfaction of the SCAQMD and its Hearing Board, except for the condition that SoCalGas agree to fund the reasonable costs of a study of the health impacts of the leak. Pursuant to the settlement agreement between SCAQMD and SoCalGas described above, the SCAQMD agreed that the health study condition was satisfied and, in March 2017, the Hearing Board terminated the Abatement Order.
PHMSA, DOGGR, SCAQMD, EPA and CARB hashave each commenced separate rulemaking proceedings to adopt further regulations covering natural gas storage facilities and injection wells. The U.S. Senate also passed two piecesDOGGR issued new regulations following the Governor’s Order as described above, and in 2016, the California Legislature enacted four separate bills providing for additional regulation of legislation, which include a provision requiring the establishment of an Aliso Canyon Task Force. This generally mirrors the focus and structure of the Task Force on Natural Gas Storage Safety. The legislation requires the Task Force to examine a specific set of issues related to the leak, including impacts on health and electricity prices.
natural gas storage facilities. Additional hearings in the state legislatureCalifornia Legislature, as well as with various other federal and state regulatory agencies,


have been or are expected tomay be scheduled, additional legislation has been proposed in the state legislature,California Legislature, and additional laws, orders, rules and regulations may be adopted. The Los Angeles County Board of Supervisors has formed a task force to review and potentially implement new, more stringent land use (zoning) requirements and associated regulations and enforcement protocols for oil and gas activities, including natural gas storage field operations, which could materially affect new or modified uses of the Aliso Canyon and other natural gas storage fields located in Los Angeles County.
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 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.
On April 22, 2016, DOSH issued notices of intent to issue four “serious” citations to SoCalGas, alleging violations of Title 8 of the California Code of Regulations sections 5155(e)(1), 5192(q)(6)(E), 6845(a), and 6851(a). The notices allege (1) a failure to monitor concentrations of airborne contaminant exposure to employees, (2) an Incident Commander did not receive sufficient training, (3) insufficient testing and inspection of well casing and tubing and (4) insufficient inspection and maintenance to prevent leaks. The maximum penalty that DOSH could issue for these four alleged violations is a total of $280,000.
Natural Gas Storage Operations. SoCalGas estimates that approximately 57 billion cubic feet (Bcf) of natural gas has been delivered to customers or moved to other gas storage facilities from an initial starting point of approximately 77 Bcf of gas in storage on October 23, 2015 at the Aliso Canyon facility. The CPUC has directed SoCalGas to maintain a minimum of 15 Bcf of working natural gas to help ensure reliability of the system through the springOperations and summer months, and based on the CARB estimates of lost gas, the facility is approximately at this level. Effective February 5, 2016, the DOGGR amended the California Code of Regulations to require all underground natural gas storage facility operators, including SoCalGas, to take further steps to help ensure the safety of their gas storage operations. SoCalGas is in the process of conducting a measurement of natural gas lost from the leak and will provide that information to the relevant regulatory bodies.
Reliability.Natural gas withdrawn from storage is important for service reliability during peak demand periods, including heating needs in the winter, as well as peak electric generation needs in the summer.summer and heating needs in the winter. Aliso Canyon, with a storage capacity of 86 Bcf,billion cubic feet (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. SoCalGas calculated that approximately 4.62 Bcf of natural gas was released from the Aliso Canyon represents 63 percent of SoCalGas’ owned natural gas storage capacity.facility as a result of the leak. SoCalGas has not injected natural gas into Aliso Canyon since October 25, 2015, pursuant to orders by DOGGR and the Governor, and in accordance with the Governor’s Order and subject to contrary CPUC reliability-based direction. On March 4, 2016, the DOGGR issued Order 1109, Order to Take Specific Actions RegardingSB 380. Limited withdrawals of natural gas from Aliso Canyon Gas Storage Facility (Safety Review Testing Regime). On April 7,have been made in 2017 to augment gas supplies during critical demand periods. In November 2016, SoCalGas announced its safety frameworksubmitted a request to comply with the DOGGR Order 1109, which consists of phased testing for each of the activeseeking authorization to resume injection wells inoperations at the Aliso Canyon storage facility. SoCalGas will continue this moratoriumIn accordance with SB 380, DOGGR held public meetings in the affected community to provide the public an opportunity to comment on further injections until the completion of thissafety review and any necessary approvals have been obtained.
On April 5, 2016, four energy agencies—the CPUC, the California Energy Commission, the California Independent System Operator,findings, and the Los Angeles Department of Water and Power—issued an Aliso Canyon Action Plancomment period has expired. It remains for DOGGR to Preserve Gas and Electric Reliability forissue its safety determination, after which the Los Angeles Basin. In their Action Plan,CPUC’s executive director must concur with DOGGR’s safety determination, before injections at the agencies recognized that: Aliso Canyon is critical to meeting peak demand in both winter and summer; the Greater Los Angeles region could face an estimated 16 days of gas curtailments this upcoming summer—assuming no withdrawals of any of the 15 Bcf held at Aliso Canyon; and unless gas is withdrawn from Aliso Canyon, 14 of these days are likely to be large enough to interrupt electric generators located in the LA Basin. To help mitigate concerns about natural gas service reliability to customers, including related impacts on natural gas-fueled power generation, SoCalGas, SDG&E and 24 customer organizations filed a settlement agreement with the CPUC on April 29, 2016 regarding procedures to help deal with service reliability issues this upcoming summer. The procedures, which would address supply shortages and surpluses using temporarily modified Operational Flow Order (OFO) tariff provisions, would be in place through no later than November 30, 2016. SoCalGas, SDG&E, and the other settlement parties have asked the CPUC to approve this package of reliability-related provisions by May 26, 2016. Therefacility can be no assurance that these measures, if approved, will prevent gas curtailments or power outages during the period Aliso Canyon remains offline.
resume.
If the Aliso Canyon facility were to be taken out of service for any meaningful period of time, it could result in an impairment of the facility and significantly higher than expected operating costs and/or additional capital expenditures, and natural gas reliability and electric generation could be jeopardized. At March 31, 2016,2017, the Aliso Canyon facility has a net book value of $415$550 million, including $180$225 million of construction work in progress for the project to construct a new compression station. Any significant impairment of this asset could have a material adverse effect on SoCalGas’ and Sempra Energy��sEnergy’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.

Other
SoCalGas, along with Monsanto Co., Solutia, Inc., Pharmacia Corp. and Pfizer, Inc., are defendants in seven Los Angeles County Superior Court lawsuits filed beginning in April 2011 seeking recovery of unspecified amounts of damages, including punitive damages, as a result of plaintiffs’ exposure to PCBs (polychlorinated biphenyls). The lawsuits allege plaintiffs were exposed to PCBs not only through the food chain and other various sources but from PCB-contaminated natural gas pipelines owned and operated by SoCalGas. This contamination allegedly caused plaintiffs to develop cancer and other serious illnesses. Plaintiffs assert various bases for recovery, including negligence and products liability. SoCalGas has settled six of the seven lawsuits for an amount that is not significant.

Sempra Mexico

Property Disputes and Permit Challenges and Property Disputes

Sempra Mexico has been engaged in a long-running land dispute relating to property adjacent to its Energía Costa Azul LNG terminal near Ensenada, Mexico. Ownership of the adjacent property is not required by any of the environmental or other regulatory permits issued for the operation of the terminal. A claimant to the adjacent property has nonetheless asserted that his health and safety are endangered by the operation of the facility, and filed an action in the Federal Court challenging the permits. In February 2011, based on a complaint by the claimant, the municipality of Ensenada opened an administrative proceeding and sought to temporarily close the terminal based on claims of irregularities in municipal permits issued six years earlier. This attempt was promptly countermanded by Mexican federal and Baja California state authorities. No terminal permits or operations were affected as a result of these proceedings or events and the terminal has continued to operate normally. In the second quarter of 2014, the municipality of Ensenada dismissed the administrative proceeding. In the second quarter of 2015, the Administrative Court of Baja California confirmed the municipality of Ensenada’s ruling and dismissed the proceeding. Sempra Mexico expects additional Mexican court proceedings and governmental actions regarding the claimant’s assertions as to whether the terminal’s permits should be modified or revoked in any manner.
The claimant also filed complaints in the federal Agrarian Court challenging the refusal of the Secretaría de la Reforma Agraria (now the Secretaría de Desarrollo Agrario, Territorial y Urbano, or SEDATU) in 2006 to issue a title to him for the disputed property. In November 2013, the Agrarian Court ordered that SEDATU issue the requested title and cause it to be registered. Both SEDATU and Sempra Mexico challenged the ruling, due to lack of notification of the underlying process. In November 2015, the AgrarianBoth challenges are pending to be resolved by a Federal Court denied Sempra Mexico’s challenge, but the ruling does not affect any property rights. Another appeal filed by SEDATU is pending.in Mexico. Sempra Mexico expects additional proceedings regarding the claims, although such proceedings are not related to the permit challenges referenced above.
claims.
The property claimant also filed a lawsuit in July 2010 against Sempra Energy in Federal District Court in San Diego seeking compensatory and punitive damages as well as the earnings from the Energía Costa Azul LNG terminal based on his allegations that he was wrongfully evicted from the adjacent property and that he has been harmed by other allegedly improper actions. In September 2015, the Court granted Sempra Energy’s motion for summary judgment and closed the case. In October 2015, theThe claimant filed a notice of appeal ofhas appealed the summary judgment and an earlier order dismissing certain of his causes of action. Argument on the appeal was held in March 2017.
Additionally, several administrative challenges are pending in Mexico before the Mexican environmental protection agency (SEMARNAT) and the Federal Tax and Administrative Courts seeking revocation of the environmental impact authorization (EIA) issued to Energía Costa Azul in 2003. These cases generally allege that the conditions and mitigation measures in the EIAenvironmental impact authorization are inadequate and challenge findings that the activities of the terminal are consistent with regional development guidelines. The Mexican Supreme Court decided to exercise jurisdiction over one such case, and in March 2014, issued a resolution denying the relief sought by the plaintiff on the grounds its action was not timely presented. A similar administrative challenge seeking to revoke the port concession for our marine operations at our Energía Costa Azul LNG terminal was filed with and rejected by the Mexican Communications and Transportation Ministry. In April 2015, the Federal court confirmed the Mexican Communications and Transportation Ministry’s ruling denying the request to revoke the port concession and decided in favor of Energía Costa Azul.
Two real property cases have been filed against Energía Costa Azul in whichAzul. In one, the plaintiffs seek to annul the recorded property titlestitle for parcelsa parcel on which the Energía Costa Azul LNG terminal is situated and to obtain possession of a different parcelsparcel that allegedly sitsits in the same place; one of these cases was dismissed in September 2013 at the direction of the state appellate court.place. A thirdsecond complaint was served in April 2013 seeking to invalidate the contract by which Energía Costa Azul purchased another of the terminal parcels, on the grounds the purchase price was unfair. In January 2016, the second complaint was dismissed by the Federal Agrarian Court. Sempra Mexico expects further proceedings on the remainingthese two matters.



Sempra Natural Gas

Since April 2012,In 2015, the Yaqui tribe, with the exception of the Bácum community, granted its consent and a totalright-of-way easement agreement for the construction of 14 lawsuits have beenthe Guaymas-El Oro segment of IEnova’s Sonora natural gas pipeline that crosses its territory. Representatives of the Bácum community filed against Mobile Gasan amparo claim in Mobile County CircuitMexican Federal Court alleging thatdemanding the right to withhold consent for the project, the stoppage of work in the first half of 2008 Mobile Gas spilled tert-butyl mercaptan, an odorant added to natural gas for safety reasons,Yaqui territory and damages. The judge granted a suspension order that prohibited the construction through the Bácum community territory only. As a result, IEnova was delayed in Eight Mile, Alabama. Eleventhe construction of the lawsuitsapproximately 14 kilometers of pipeline that pass through territory of the Yaqui tribe. The Comisión Federal de Electricidad agreed to extend the deadline for commercial operations until the second quarter of 2017. Later-appointed Bácum authorities have requested that the Mexican Federal Court dismiss the amparo claim. In the meantime, the portion of the pipeline crossing the Bácum territory has been settled.completed.
In December 2012, Backcountry Against Dumps, Donna Tisdale and the Protect Our Communities Foundation filed a complaint in the United States District Court for the Southern District of California seeking to invalidate the presidential permit issued by the DOE for Energía Sierra Juárez’s cross-border generation tie line (Gen-tie line) connecting the Energía Sierra Juárez wind project in Mexico to the electric grid in the United States. The remaining three lawsuits,suit alleged violations of the National Environmental Policy Act (NEPA), the Endangered Species Act, the Migratory Bird Treaty Act and the Bald and Golden Eagle Protection Act. Plaintiffs filed a motion for summary judgment, which include approximately 250 individual plaintiffs, allege nuisance, fraudthe court largely denied in September 2015. One NEPA claim, however, was not resolved – whether the Environmental Impact Statement’s (EIS) assessment of alleged extraterritorial impacts of the Gen-tie line in the United States on the environment in Mexico was inadequate (the “extraterritorial impact issue”) – and negligence causeswas the subject of action,additional briefing in 2016. On January 30, 2017, the Court issued a ruling on the extraterritorial impact issue and, seek unspecified compensatorycontrary to its prior ruling, ruled that the EIS was deficient for not considering the effects in Mexico of both the U.S. and punitive damages.Mexican portion of the Gen-tie line and the wind farm itself. The Court has not yet made a decision on the ultimate remedy, and a final judgment has not been entered.


Other Litigation

Sempra Energy holds a noncontrolling interest in RBS Sempra Commodities, LLP (RBS Sempra Commodities), a limited liability partnership in the process of being liquidated. The Royal Bank of Scotland plc (RBS), our partner in the joint venture, was notified bypaid an £86 million assessment in October 2014 to the United Kingdom’s Revenue and Customs Department (HMRC) that it was investigatingfor denied value-added tax (VAT) refund claims made by various businessesfiled in connection with the purchase and sale of carbon credit allowances. HMRC advised RBS that it had determined that it had grounds to deny such claims by RBS related to transactionsallowances by RBS Sempra Energy Europe (RBS SEE), a former indirect subsidiary of RBS Sempra Commodities that wasCommodities. RBS SEE has since been sold to JP Morgan.Morgan and later to Mercuria Energy Group, Ltd. HMRC asserted that RBS was not entitled to reduce its VAT liability by VAT paid on certain carbon credit purchases during 2009 because RBS knew or should have known that certain vendors in the trading chain did not remit their own VAT to HMRC. In September 2012, HMRC issued a protectiveAfter paying the assessment, of £86 million for the VAT paid in connection with these transactions. In October 2014, RBS filed a Notice of Appeal of the September 2012 assessment with the First-tierFirst-Tier Tribunal. AsThe First-Tier Tribunal held a condition of the appeal, RBS was requiredpreliminary hearing in September 2016 to pay the assessed amount. The payment also stops the accrual of interest that could arise should it ultimately be determined that RBS has a liability for some of the tax. RBS has asserted thatdetermine whether HMRC’s assessment was time-barred. A preliminaryIn January 2017, the First-Tier Tribunal issued a decision in favor of HMRC concluding that the assessment was not time-barred. RBS has decided not to appeal the First-Tier Tribunal’s decision to the Upper Tribunal. There will be a hearing is scheduled for September 19on the substantive matter regarding whether RBS knew or should have known that certain vendors in the trading chain did not remit their VAT to 21, 2016. In JuneHMRC.
During 2015, liquidators, for threeacting on behalf of ten companies (the Companies) that engaged in carbon credit trading via chains that included a company that RBS SEE traded with directly, filed a claim in the High Court of Justice asserting damages of £73 million against RBS and RBS Sempra Commodities allegingMercuria Energy Europe Trading Limited (the Defendants). The claim alleges that RBS Sempra Commodities’ and RBS SEE’sthe Defendants’ participation in transactions involving the salepurchase and purchasesale of carbon credits resulted in the companies’ incurringCompanies’ carbon credit trading transactions creating a VAT liability they were unable to pay. In October 2015, the liquidators’ counsel filed an amended claim adding seven additional trading companies to the claim and asserting damages of £156 million for all 10 companies. Additionally, the claimants dropped RBS Sempra Commodities LLP as a defendant, adding the successor to RBS SEE and JP Morgan, Mercuria Energy Europe Trading Limited (Mercuria), in its stead. JP Morgan has notified us that Mercuria Energy Group, Ltd. has sought indemnity for the claim, and JP Morgan has in turn sought indemnity from us.
Our remaining balance in RBS Sempra Commodities is accounted for under the equity method. The investment balance of $67 million at March 31, 20162017 reflects remaining distributions expected to be received from the partnership as it is liquidated. The timing and amount of distributions may be impacted by these matters. We discuss RBS Sempra Commodities further in Note 4 of the Notes to Consolidated Financial Statements in the Annual Report.
In August 2007, the U.S. Court of Appeals for the Ninth Circuit issued a decision reversing and remanding certain FERC orders declining to provide refunds regarding short-term bilateral sales up to one month in the Pacific Northwest for the January 2000 to June 2001 time period. In December 2010, the FERC approved a comprehensive settlement previously reached by Sempra Energy and RBS Sempra Commodities with the State of California. The settlement resolved all issues with regard to sales between the California Department of Water Resources and Sempra Commodities in the Pacific Northwest, but potential claims may exist regarding sales in the Pacific Northwest between Sempra Commodities and other parties. The FERC is in the process of addressing these potential claims on remand. Pursuant to the agreements related to the formation of RBS Sempra Commodities, we have indemnified RBS should the liability from the final resolution of these matters be greater than the reserves related to Sempra Commodities. Pursuant to our agreement with the Noble Group Ltd., one of the buyers of RBS Sempra Commodities’ businesses, we have also indemnified Noble Americas Gas & Power Corp. and its affiliates for all losses incurred by such parties resulting from these proceedings as related to Sempra Commodities.
We are also defendants in ordinary routine litigation incidental to our businesses, including personal injury, employment litigation, product liability, property damage and other claims. Juries have demonstrated an increasing willingness to grant large awards, including punitive damages, in these types of cases.


CONTRACTUAL COMMITMENTS

We discuss below significant changes in the first three months of 20162017 to contractual commitments discussed in NoteNotes 1 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.


Natural Gas Contracts

Sempra Natural Gas’LNG & Midstream’s natural gas purchase and transportation commitments have decreased by $46$90 million since December 31, 2015,2016, primarily due to payments on existing contracts and changes in forward natural gas prices in the first three months of 2016.2017. Net future payments are expected to decrease by $60 million in 2016, and increase by $10$77 million in 2017 and $4$13 million in 2018 compared to December 31, 2015.

2016.



In May 2016, Sempra LNG & Midstream permanently released certain pipeline capacity that it held with Rockies Express and others, which we discuss in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report. Sempra LNG & Midstream reached an agreement to settle a breach of contract claim against a counterparty in bankruptcy court for $57 million, which was approved by the court on April 25, 2017. Sempra LNG & Midstream expects to receive payment in the second quarter of 2017, which, upon receipt, will be recorded as a reduction to Other Cost of Sales on Sempra Energy’s Condensed Consolidated Statement of Operations.
LNG Purchase Agreement

Sempra Natural GasLNG & Midstream has a purchase agreement for the supply of LNG to the Energía Costa Azul terminal. The agreementcommitment amount is pricedcalculated using a predetermined formula based on natural gas market indices.estimated forward prices of the index applicable from 2017 to 2029. At March 31, 2017, the commitment amount is expected to decrease by $174 million in 2017, $41 million in 2018, $32 million in 2019, $38 million in 2020, $40 million in 2021 and $677 million thereafter (through contract termination in 2029) compared to December 31, 2016, reflecting changes in estimated forward prices since December 31, 2016 and actual transactions for the first three months of 2017. These LNG commitment amounts are based on the assumption that all cargoes, less those already confirmed to be diverted, under the agreement are delivered. Although this contractagreement specifies a number of cargoes to be delivered, under its terms, the customer may divert certain cargoes, which would reduce amounts paid under the contractsagreement by Sempra Natural Gas.
Sempra Natural Gas’ commitment under the LNG purchase agreement, reflecting changes in forward prices since December 31, 2015 and actual transactions for the first three months of 2016, is expected to decrease by $146 million in 2016, $3 million in 2017, $7 million in 2018, $18 million in 2019, and $30 million in 2020 and increase by $20 million thereafter (through contract termination in 2029) compared to December 31, 2015. These amounts are based on forward prices of the index applicable to the contract from 2016 to 2028 and an estimated one percent escalation per year beyond 2028 through contract termination in 2029. The LNG commitment amounts above are based on the requirement for Sempra Natural Gas to accept the maximum possible delivery of cargoes under the agreement.& Midstream. Actual LNG purchases in the current and prior years have been significantly lower than the maximum amounts possibleamount provided under the agreement due to the customer electing to divert cargoes as allowed by the agreement.
Capital Leases – Power Purchase Agreements

In the first quarter of 2017, SDG&E satisfied all of the conditions precedent for a CPUC-approved 20-year power purchase agreement with a 500-MW intermediate storage power plant facility that is under construction. Beginning with the initial delivery of the contracted power, scheduled in 2018, the power purchase agreement will be accounted for as a capital lease. Future minimum lease payments under the new power purchase agreement are as follows:
FUTURE MINIMUM PAYMENTS – POWER PURCHASE AGREEMENT
(Dollars in millions)
2017$—
201888
2019105
2020105
2021105
Thereafter1,706
Total minimum lease payments(1)2,109
Less: interest(2)(1,559)
Present value of net minimum lease payments$550
(1)This amount will be recorded over the life of the lease as Cost of Electric Fuel and Purchased Power on Sempra Energy’s and SDG&E’s Condensed Consolidated Statements of Operations. This expense will receive ratemaking treatment consistent with purchased-power costs, which are recovered in rates.
(2)Amount necessary to reduce net minimum lease payments to estimated present value at the inception of the lease.

Construction and Development Projects
SDG&E
In the first three months of 2017, significant net increases to contractual commitments at SDG&E were $68 million primarily for construction and infrastructure improvements for transmission systems. Net future payments under these contractual commitments are expected to increase by $31 million in 2017 and $42 million in 2018, decrease by $2 million in 2019, increase by $3 million in 2020 and $1 million in 2021, and decrease by $7 million thereafter compared to December 31, 2016.
NUCLEAR INSURANCE

SDG&E and the other owners of SONGS have insurance to cover claims from nuclear liability incidents arising at SONGS. This insurance provides $375$450 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides for up to $13.2$13 billion of secondary financial protection (SFP). If a nuclear liability loss occurring at any U.S. licensed/commercial reactor exceeds the $375$450 million insurance limit, all nuclear reactor owners could be required to contribute to the SFP. In such case, SDG&E’s contribution would be up to $50.93$50.9 million. This amount is subject to an


annual maximum of $7.6 million, unless a default occurs by any other SONGS owner. If the SFP is insufficient to cover the liability loss, SDG&E could be subject to an additional assessment.
The SONGS owners, including SDG&E, also have $2.75$1.5 billion of nuclear property, decontamination, and debris removal insurance, subject to a $2.5 million deductible for “each and every loss.” This insurance coverage is provided through Nuclear Electric Insurance Limited (NEIL). The NEIL policies have specific exclusions and limitations that can result in reduced or eliminated coverage. Insured members as a group are subject to retrospective premium assessments to cover losses sustained by NEIL under all issued policies. SDG&E could be assessed up to $9.7$10.4 million of retrospective premiums based on overall member claims. SeeAll of SONGS’ insurance claims arising out of the failures of the MHI replacement steam generators have been settled with NEIL, as we discuss in Note 9 under “Settlement with NEIL” for discussion13 of an agreement between the SONGS co-owners and NEILNotes to settle all claims underConsolidated Financial Statements in the NEIL policies associated with the SONGS outage.
Annual Report.
The nuclear property insurance program includes an industry aggregate loss limit for non-certified acts of terrorism (as defined by the Terrorism Risk Insurance Act). The industry aggregate loss limit for property claims arising from non-certified acts of terrorism is $3.24 billion. This is the maximum amount that will be paid to insured members who suffer losses or damages from these non-certified terrorist acts.


U.S. DEPARTMENT OF ENERGY NUCLEAR FUEL DISPOSAL

The Nuclear Waste Policy Act of 1982 made the DOE responsible for accepting, transporting, and disposing of spent nuclear fuel. However, it is uncertain when the DOE will begin accepting spent nuclear fuel from SONGS. This delay will lead to increased costs for spent fuel storage. SDG&E will continue to support Edison in its pursuit of claims on behalf of the SONGS co-owners against the DOE for its failure to timely accept the spent nuclear fuel. OnIn April 18, 2016, Edison executed a spent fuel settlement agreement with the DOE for $162 million covering damages incurred from January 1, 2006 through December 31, 2013. In May 2016, Edison refunded SDG&E’s&E $32 million for its respective share of the damage award paid. In applying this refund, SDG&E recorded a $23 million reduction to the SONGS regulatory asset, an $8 million reduction of its nuclear decommissioning balancing account and a $1 million reduction in its SONGS operation and maintenance cost balancing account.
In September 2016, Edison filed claims with the DOE for $56 million in spent fuel management costs incurred in 2014 and 2015 on behalf of the SONGS co-owners under the terms of the 2016 spent fuel settlement agreement. In February 2017, the DOE reduced the request to approximately $43 million primarily due to reductions to the claimed fuel canister costs. SDG&E’s respective share of the claim is approximately $32$9 million.
We expect Edison’s claim to be resolved, and to receive SDG&E’s portion of the final settlement award, net of legal costs, in the second quarter of 2017.
In October 2015, the California Coastal Commission approved Edison’s application for the proposed expansion of an Independent Spent Fuel Storage Installation (ISFSI) at SONGS. The ISFSI expansion began construction in 2016, will be fully loaded with spent fuel by 2019, and will operate until 2049, when it is assumed that the DOE will have taken custody of all the SONGS spent fuel. The ISFSI would then be decommissioned, and the site restored to its original environmental state.
We provide additional information about SONGS in Note 9 above and in Notes 13 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.


CONCENTRATION OF CREDIT RISK

We maintain credit policies and systems to manage our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition and an assignment of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. We grant credit to utility customers and counterparties, substantially all of whom are located in our service territory, which covers most of Southern California and a portion of central California for SoCalGas, and all of San Diego County and an adjacent portion of Orange County for SDG&E. We also grant credit to utility customers and counterparties of our other companies providing natural gas or electric services in Mexico, Chile Peru, southwest Alabama, and Hattiesburg, Mississippi.
Peru.
As they become operational, projects owned or partially owned by Sempra Natural Gas,LNG & Midstream, Sempra Renewables, Sempra South American Utilities and Sempra Mexico place significant reliance on the ability of their suppliers, customers and partners to perform on long-term agreements and on our ability to enforce contract terms in the event of nonperformance. We consider many factors, including the negotiation of supplier and customer agreements, when we evaluate and approve development projects.





NOTE 12. SEGMENT INFORMATION

We have six separately managed, reportable segments, as follows:
1.  
▪
SDG&E provides electric service to San Diego and southern Orange counties and natural gas service to San Diego County.
2.  
▪
SoCalGas is a natural gas distribution utility, serving customers throughout most of Southern California and part of central California.
3.  
▪
Sempra South American Utilities develops, owns and operates, or holds interests in, electric transmission, distribution and generation infrastructure in Chile and Peru.
4.  
▪
Sempra Mexico develops, owns and operates, or holds interests in, natural gas transmission pipelinessystems and propanean ethane system, a liquid petroleum gas pipeline and ethane systems,associated storage terminal, a natural gas distribution utility, electric generation facilities (including wind)wind and solar electric generation facilities and a natural gas-fired power plant), a terminal for the import of LNG, and marketing operations for the purchase of LNG and the purchase and sale of natural gas in Mexico. In February 2016, management approved a plan to market and sell the Termoeléctrica de MexicaliTdM natural gas-fired power plant located in Mexicali, Baja California, as discussedwe discuss in Note 3.
5.  
▪
Sempra Renewables develops, owns and operates, or holds interests in, wind and solar energy projects in Arizona, California, Colorado, Hawaii, Indiana, Kansas, Minnesota, Nebraska, Nevada and Pennsylvania to servegeneration facilities serving wholesale electricity markets in the United States.
6.  
▪
Sempra Natural GasLNG & Midstream develops, owns and operates, or holds interests in, natural gas pipelines and storage facilities, natural gas distribution utilities and a terminal for the import and export of LNG and sale of natural gas, and natural gas pipelines and storage facilities, all within the United States. In September 2016, Sempra NaturalLNG & Midstream sold EnergySouth Inc., the parent company of Mobile Gas also owned and operatedWillmut Gas, and in May 2016, sold its 25-percent interest in Rockies Express. We discuss these divestitures in Note 3 of the Mesquite Power plant, a natural gas-fired electric generation asset,Notes to Consolidated Financial Statements in the remaining 625-MW block of which was sold in April 2015.Annual Report.

Sempra South American Utilities and Sempra Mexico comprise our Sempra International operating unit. Sempra Renewables and Sempra Natural Gas comprise our Sempra U.S. Gas & Power operating unit.
We evaluate each segment’s performance based on its contribution to Sempra Energy’s reported earnings. The California Utilities operate in essentially separate service territories, under separate regulatory frameworks and rate structures set by the CPUC. The California Utilities’ operations are based on rates set by the CPUC and the FERC. We describe the accounting policies of all of our segments in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
Common services shared by the business segments are assigned directly or allocated based on various cost factors, depending on the nature of the service provided. Interest income and expense is recorded on intercompany loans. The loan balances and related interest are eliminated in consolidation.
The following tables show selected information by segment from our Condensed Consolidated Statements of Operations and Condensed Consolidated Balance Sheets. Amounts labeled as “All other” in the following tables consist primarily of parent organizations.


SEGMENT INFORMATIONSEGMENT INFORMATION           
(Dollars in millions)(Dollars in millions)        (Dollars in millions)  
 Three months ended March 31,Three months ended March 31,
 201620152017 2016
REVENUESREVENUES           
SDG&E SDG&E$99138%$96636%$1,057
 $991
SoCalGas SoCalGas 1,03340  1,04839 1,241
 1,033
Sempra South American Utilities Sempra South American Utilities 40015  38915 412
 400
Sempra Mexico Sempra Mexico 1385  1636 264
 138
Sempra Renewables Sempra Renewables 7―  8― 22
 7
Sempra Natural Gas 1305  1977 
Sempra LNG & Midstream132
 130
Intersegment revenues(1) Intersegment revenues(1) (77)(3)  (89)(3) (97) (77)
Total Total$2,622100%$2,682100%$3,031
 $2,622
INTEREST EXPENSEINTEREST EXPENSE           
SDG&E SDG&E$48  $52  $49
 $48
SoCalGas SoCalGas 22   19  25
 22
Sempra South American Utilities Sempra South American Utilities 9   5  9
 9
Sempra Mexico Sempra Mexico 4   5  32
 4
Sempra Renewables Sempra Renewables ―   1  4
 —
Sempra Natural Gas 12   21  
Sempra LNG & Midstream11
 12
All other All other 72   63  68
 72
Intercompany eliminations Intercompany eliminations (24)   (32)  (29) (24)
Total Total$143  $134  $169
 $143
INTEREST INCOMEINTEREST INCOME           
Sempra South American Utilities Sempra South American Utilities$5  $4  $5
 $5
Sempra Mexico Sempra Mexico 2   2  2
 2
Sempra Renewables Sempra Renewables 1   ―  1
 1
Sempra Natural Gas 16   19  
Sempra LNG & Midstream17
 16
Intercompany eliminations Intercompany eliminations (18)   (18)  (19) (18)
Total Total$6  $7  $6
 $6
DEPRECIATION AND AMORTIZATIONDEPRECIATION AND AMORTIZATION   
SDG&E SDG&E$15949%$14548%$163
 $159
SoCalGas SoCalGas 12237  11337 126
 122
Sempra South American Utilities Sempra South American Utilities 134  134 13
 13
Sempra Mexico Sempra Mexico 175  176 36
 17
Sempra Renewables Sempra Renewables 1―  21 9
 1
Sempra Natural Gas 134  124 
Sempra LNG & Midstream10
 13
All other All other 31  1― 3
 3
Total Total$328100%$303100%$360
 $328
INCOME TAX EXPENSE (BENEFIT)
INCOME TAX EXPENSE (BENEFIT)(2)   
SDG&E SDG&E$72  $88  $90
 $65
SoCalGas SoCalGas 87   95  98
 83
Sempra South American Utilities Sempra South American Utilities 14   16  19
 14
Sempra Mexico Sempra Mexico 41   8  142
 40
Sempra Renewables Sempra Renewables (12)   (17)  (11) (13)
Sempra Natural Gas (25)   2  
Sempra LNG & Midstream1
 (29)
All other All other (35)   (29)  (44) (52)
Total Total$142  $163  $295
 $108


SEGMENT INFORMATION (CONTINUED)SEGMENT INFORMATION (CONTINUED)         
(Dollars in millions)(Dollars in millions)           
Three months ended March 31,Three months ended March 31,
201620152017 2016
EQUITY EARNINGS (LOSSES)EQUITY EARNINGS (LOSSES)           
Earnings (losses) recorded before tax: Earnings (losses) recorded before tax:           
Sempra Renewables Sempra Renewables$7  $2  $2
 $7
Sempra Natural Gas (29)   17  
Sempra LNG & Midstream1
 (29)
Total Total$(22)  $19  $3
 $(22)
Earnings (losses) recorded net of tax:Earnings (losses) recorded net of tax:         
Sempra South American Utilities Sempra South American Utilities$2  $(1)  $1
 $2
Sempra Mexico Sempra Mexico 15   16  (9) 15
Total Total$17  $15  $(8) $17
EARNINGS (LOSSES)        
EARNINGS (LOSSES)(2)   
SDG&E SDG&E$12940%$14734%$155
 $136
SoCalGas(2) 19561  21449 
SoCalGas(3)203
 199
Sempra South American Utilities Sempra South American Utilities 3812  419 47
 38
Sempra Mexico Sempra Mexico 175  4711 48
 18
Sempra Renewables Sempra Renewables 134  133 11
 14
Sempra Natural Gas (36)(11)  2― 
Sempra LNG & Midstream1
 (32)
All other All other (37)(11)  (27)(6) (24) (20)
Total Total$319100%$437100%$441
 $353
EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENTEXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT  EXPENDITURES FOR PROPERTY, PLANT & EQUIPMENT
SDG&E SDG&E$32934%$35546%$418
 $329
SoCalGas SoCalGas 34035  31540 357
 340
Sempra South American Utilities Sempra South American Utilities 434  314 43
 43
Sempra Mexico Sempra Mexico 404  557 94
 40
Sempra Renewables Sempra Renewables 18119  31 69
 181
Sempra Natural Gas 354  101 
Sempra LNG & Midstream3
 35
All other All other 3―  111 8
 3
Total Total$971100%$780100%$992
 $971
March 31, 2016December 31, 2015March 31, 2017 December 31, 2016
ASSETSASSETS  ASSETS
SDG&E SDG&E$16,62540%$16,51540%$17,900
 $17,719
SoCalGas SoCalGas 12,42730  12,10429 13,602
 13,424
Sempra South American Utilities Sempra South American Utilities 3,4348  3,2358 3,729
 3,591
Sempra Mexico Sempra Mexico 3,8439  3,7839 7,702
 7,542
Sempra Renewables Sempra Renewables 1,4543  1,4414 2,282
 3,644
Sempra Natural Gas 5,39513  5,56613 
Sempra LNG & Midstream5,092
 5,564
All other All other 7412  7342 644
 475
Intersegment receivables Intersegment receivables (2,084)(5)  (2,228)(5) (2,667) (4,173)
Total Total$41,835100%$41,150100%$48,284
 $47,786
EQUITY METHOD AND OTHER INVESTMENTSEQUITY METHOD AND OTHER INVESTMENTS  EQUITY METHOD AND OTHER INVESTMENTS
Sempra South American Utilities Sempra South American Utilities$(2)  $(4)  $20
 $—
Sempra Mexico Sempra Mexico 522   519  212
 180
Sempra Renewables Sempra Renewables 823   855  812
 844
Sempra Natural Gas 1,308   1,460  
Sempra LNG & Midstream999
 997
All other All other 76   75  77
 76
Total Total$2,727  $2,905  $2,120
 $2,097
(1)Revenues for reportable segments include intersegment revenues of $3 million, $17 million, $27 million and $30 million for the three months ended March 31, 2016 and $2 million, $19 million, $25 million and $43 million for the three months ended March 31, 2015 for SDG&E, SoCalGas, Sempra Mexico and Sempra Natural Gas, respectively.
(2)After preferred dividends.  
(1)Revenues for reportable segments include intersegment revenues of $1 million, $18 million, $25 million and $53 million for the three months ended March 31, 2017 and $3 million, $17 million, $27 million and $30 million for the three months ended March 31, 2016 for SDG&E, SoCalGas, Sempra Mexico and Sempra LNG & Midstream, respectively.
(2)Amounts for the three months ended March 31, 2016 reflect the adoption of ASU 2016-09 as of January 1, 2016, as we discuss in Note 2.
(3)After preferred dividends.


NOTE 13. SUBSEQUENT EVENT



SEMPRA NATURAL GAS

In April 2016, Sempra Natural Gas signed a definitive agreement to sell the parent company of Mobile Gas and Willmut Gas. We expect to receive cash proceeds of approximately $323 million, subject to normal adjustments at closing, and the buyer will assume existing debt of approximately $67 million. In April 2016, we reclassified the assets and liabilities of Mobile Gas and Willmut Gas to held for sale. The transaction is subject to customary regulatory approvals, and we expect the sale to close in 2016.


ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion in conjunction with the Condensed Consolidated Financial Statements and the Notes thereto contained in this Form 10-Q, and the Consolidated Financial Statements and the Notes thereto, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Risk Factors” contained in our 2015 Annual Report on Form 10-K for the year ended December 31, 2016 (Annual Report).

OVERVIEW

Sempra Energy is a Fortune 500 energy-services holding company whose operating units invest in, develop and operate energy infrastructure, and provide gas and electricity services to their customers in North and South America. OurAdditional information about our operating units, are our California Utilities, which are San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas), Sempra International and Sempra U.S. Gas & Power. SDG&E and SoCalGas are separate, reportable segments. Sempra International includes two reportable segments – Sempra South American Utilities and Sempra Mexico. Sempra U.S. Gas & Power also includes two reportableInfrastructure, and their respective segments – Sempra Renewablesis provided below and Sempra Natural Gas.
in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.
This report includes information for the following separate registrants:
§  
▪Sempra Energy and its consolidated entities
§  SDG&E
▪San Diego Gas & Electric Company (SDG&E) and its consolidated variable interest entity (VIE)
§  SoCalGas
▪Southern California Gas Company (SoCalGas)
References to “we,” “our” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, collectively, unless otherwise indicated by its context. We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include our South American utilities or the utilities in our Sempra Infrastructure operating unit. All references to “Sempra International”Utilities” and “Sempra U.S. Gas & Power,Infrastructure,” and to their respective principal segments, are not intended to refer to any legal entity with the same or similar name.
Throughout this report, we refer to the following as Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements when discussed together or collectively:
▪the Condensed Consolidated Financial Statements and related Notes of Sempra Energy and its subsidiaries and VIEs;
▪the Condensed Consolidated Financial Statements and related Notes of SDG&E and its VIE; and
▪the Condensed Financial Statements and related Notes of SoCalGas.
Below are summary descriptions of our operating units and their reportable segments.


SEMPRA ENERGY OPERATING UNITS AND REPORTABLE SEGMENTS

CALIFORNIA
SEMPRA UTILITIES  
 MARKETSERVICE TERRITORY
Business summaryMarketService territory
SAN DIEGO GAS & ELECTRIC COMPANY (SDG&E)SDG&E
A regulated public utility; infrastructure supports electric generation, transmission and distribution, and natural gas distribution
§
▪
Provides electricity to a population of 3.6 million (1.4 million meters)
▪
§Provides natural gas to a population of 3.3 million (0.9 million meters)
 

Serves the county of San Diego, California (electric and natural gas) and an adjacent portion of southern Orange County (electric only) covering 4,100 square miles
SOUTHERN CALIFORNIA GAS COMPANY (SOCALGAS)SOCALGAS
A regulated public utility; infrastructure supports natural gas distribution, transmission and storage
§Residential, commercial, industrial, utility electric generation and wholesale customers
▪
§CoversProvides natural gas to a population of 21.621.7 million (5.9 million meters)


Southern California and portions of central California (excluding San Diego County, the city of Long Beach and the desert area of San Bernardino County) covering 20,000 square miles

We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include the utilities in our Sempra International or Sempra U.S. Gas & Power operating units described below.
SEMPRA INTERNATIONAL
MARKETGEOGRAPHIC REGION
SEMPRA SOUTH AMERICAN UTILITIES
Develops, owns and operates, or holds interests in electric transmission, distribution and generation infrastructure
§
▪
Provides electricity to a population of approximately 2 million (approximately 672,0000.7 million meters) in Chile and approximately 4.9 million consumers (approximately 1,053,0001.1 million meters) in Peru
§Chile
▪
Region of Valparaiso in central Chile
§
▪
Southern zone of metropolitan Lima, Peru
SDG&E
Capital Project Updates
We summarize below updates regarding certain major capital projects at SDG&E.
CAPITAL PROJECTS – SDG&E      
       
Project description
Estimated cost
(in millions)
 Status
South Orange County Reliability Enhancement      
§

December 2016 California Public Utilities Commission (CPUC) final decision granted a Certificate of Public Convenience and Necessity to replace/upgrade existing 230-kilovolt (kV) transmission lines to enhance the capacity and reliability of electric service to the south Orange County area. $381
 §Construction expected to start in the second half of 2017.
    §Rehearing requests filed by the City of San Juan Capistrano and local opposition group pending with CPUC.
Electric Vehicle Charging      
§

January 2017 application, pursuant to Senate Bill (SB) 350, to perform various activities and make investments in support of electric vehicle charging at an estimated cost of $349 million, including $51 million of operation and maintenance expense (O&M)(1). $298
 §Application pending
Energy Storage      
§

August 2016 CPUC approval to own and operate two energy storage projects totaling 37.5 megawatts (MW) to enhance electric reliability in the San Diego service territory.
Not
disclosed
§
Completed in first quarter of 2017.

§

April 2017 application to procure up to 70 MW of utility-owned energy storage to provide local capacity.
Not
disclosed
§Application pending
Utility Billing and Customer Information Systems (CIS) Software      
§

April 2017 application to replace CIS software at an estimated cost of $287 million, including $67 million of O&M(1). $220
 
§

Application pending
(1)O&M is related to implementation costs.

We discuss additional matters related to SDG&E in “Factors Influencing Future Performance.”


California Utilities–Joint Matters
Capital Project Updates
We summarize below updates regarding certain major joint capital projects at our California Utilities.
CAPITAL PROJECTS – CALIFORNIA UTILITIES      
       
Project description
Estimated cost
(in millions)
 Status
Mobile Home Park Utility Upgrade Program      
§

May 2017 application filed with the CPUC to convert an additional 20 percent of eligible units to direct utility service, for a total of 30 percent of mobile homes. $471
 
§

Application pending
 to  
 $508
  
§

Estimated cost of $204 million, including $2 million of O&M(1), at SDG&E.     
§Estimated cost of $272 million to $310 million, including $3 million to $4 million of O&M(1), at SoCalGas.     
Pipeline Safety Enhancement Plan (PSEP)   
§

March 2017 application filed with the CPUC to recover forecasted costs associated with twelve Phase 1B and Phase 2A pipeline safety projects for $255 million, including $57 million of O&M(1). $198
 §Application pending
(1)O&M is related to implementation costs.
Energy Efficiency
The CPUC has established incentive mechanisms that are based on the effectiveness of energy efficiency programs. In March 2017, the CPUC approved the settlement agreements reached with the Office of Ratepayer Advocates (ORA) and The Utility Reform Network (TURN) regarding the incentive awards for program years 2006 through 2008, wherein the parties agreed that SDG&E and SoCalGas would offset up to a total of approximately $4 million each against future incentive awards over the next three years beginning in 2017. If the total incentive awards ultimately authorized for 2017 through 2019 are less than approximately $4 million for either utility, the applicable utility is released from paying any remaining unapplied amount.
Natural Gas Procurement
In June 2016, SoCalGas filed an application for a gas cost incentive mechanism (GCIM) award of $5 million for natural gas procured for its core customers during the 12-month period ended March 31, 2016. The CPUC approved the award in January 2017.
We discuss additional joint matters related to the California Utilities in “Factors Influencing Future Performance.”



SEMPRA INFRASTRUCTURE
Business summaryMarketGeographic area
SEMPRA MEXICO
Develops, owns and operates, or holds interests in:
§
▪
natural gas transmission pipelines and propane
▪
liquid petroleum gas (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 liquefied natural gas (LNG)
▪
a terminal for the storage of LPG
§
▪
marketing operations for the purchase of LNG and the purchase and sale of natural gas
§
▪
Natural gas
▪
§Wholesale electricity
▪
§Liquefied natural gas
▪
Liquid petroleum gas
§Mexico
▪
Mexico

SEMPRA U.S. GAS & POWER 
MARKETGEOGRAPHIC REGION
SEMPRA RENEWABLES
Develops, owns and operates, or holds interests in renewable energy generation projects
§
▪
Wholesale electricity
§U.S.A.
▪
Arizona
▪
California
▪
Colorado
▪
Hawaii
▪
Indiana
▪
Kansas

▪
Michigan
▪
Minnesota
▪
Nebraska
▪
Nevada
▪
Pennsylvania

SEMPRA NATURAL GASLNG & MIDSTREAM
Develops, owns and operates, or holds interests in:
§in LNG and natural gas pipelines and storage facilitiesmidstream assets:
▪
§a terminal in the U.S. for the import and export of LNG and sale of natural gas
▪
§natural gas distribution utilitiespipelines and storage facilities
▪
§marketing operations

§Natural gas
▪
§Liquefied natural gas
▪
Natural gas
§U.S.A.
▪
Alabama
▪
Louisiana
▪
Mississippi
▪
Texas


Sempra Mexico
Capital Project Updates
We summarize below updates regarding certain major capital projects at Sempra Mexico.
CAPITAL PROJECTS – SEMPRA MEXICO
       
Project description
Estimated cost
(in millions)
 Status
San Isidro Pipeline     
§July 2015 agreement with CFE for development, construction and operation of the approximately 14-mile pipeline. $110
 §Pipeline completed in March 2017.
§Natural gas transportation services agreement for a 25-year term, denominated in U.S. dollars, for 100 percent of the transport capacity, equal to 1.1 billion cubic feet (Bcf) per day.   §Estimated completion of compression station: second half of 2017
Pima Solar     
§110-MW photovoltaic project located in Sonora, Mexico. $115
 §Construction expected to commence in the fourth quarter of 2017.
§In March 2017, entered into a 20-year, U.S. dollar denominated power purchase agreement to provide renewable energy, clean energy certificates and capacity.   §Estimated completion: fourth quarter of 2018
§Wholly owned by Infraestructura Energética Nova, S.A.B. de C.V. (IEnova).     
We discuss additional matters related to Sempra Mexico in “Factors Influencing Future Performance.”
RESULTS OF OPERATIONS

We discuss the following in Results of Operations:
§  
▪Overall results of our operations and factors affecting those
▪Segment results
§  Our segment results
▪Adjusted earnings and adjusted earnings per share
§  
▪Significant changes in revenues, costs and earnings between periods
▪Impact of foreign currency and inflation rates on our results of operations
OVERALL RESULTS OF OPERATIONS OF SEMPRA ENERGY
Our earnings decreasedincreased by $118$88 million (27%(25%) to $319$441 million in the three months ended March 31, 2016,2017, while diluted earnings per share decreased(EPS) increased by $0.47$0.35 per share (27%(25%) to $1.27$1.75 per share.
The net changes in our Our earnings and diluted earnings per share were impacted by variances discussed in “Segment Results” below and by the items included in the table “Sempra Energy Adjusted Earnings and Adjusted Earnings Per Share,” also below.


SEGMENT RESULTS
The following section presents earnings (losses) by Sempra Energy segment, as well as Parent and other, and the related discussion of the changes in segment earnings (losses). Variance amounts presented are the after-tax earnings impact (based on applicable statutory tax rates), unless otherwise noted, and before noncontrolling interests, where applicable.
SEMPRA ENERGY EARNINGS (LOSSES) BY SEGMENT
(Dollars in millions)
 Three months ended March 31,
 2017 2016(1)
Sempra Utilities:   
SDG&E$155
 $136
SoCalGas(2)203
 199
Sempra South American Utilities47
 38
Sempra Infrastructure:   
Sempra Mexico48
 18
Sempra Renewables11
 14
Sempra LNG & Midstream1
 (32)
Parent and other(3)(24) (20)
Earnings$441
 $353
(1)Reflects the adoption of ASU 2016-09, as we discuss in Note 2 of the Notes to Condensed Consolidated
Financial Statements herein.
(2)After preferred dividends.
(3)
Includes after-tax interest expense ($41 million and $43 million for the three months ended March 31, 2017
and 2016, respectively), intercompany eliminations recorded in consolidation and certain corporate costs.

Due to the delay in the issuance of the CPUC’s final decision in the California Utilities’ 2016 General Rate Case (2016 GRC FD), the California Utilities recorded revenues in the first quarter of 2016 based on levels authorized for 2015 under the 2012 GRC. The 2016 GRC FD, which was issued by the CPUC in June 2016, was effective retroactive to January 1, 2016. As a result, the California Utilities’ CPUC-authorized base revenues for the first quarter of 2017 are based on the revenues authorized for the 2016 test year plus the amount authorized for attrition for 2017. Had the 2016 GRC FD been in effect in the first quarter of 2016, SDG&E’s and SoCalGas’ earnings for the first quarter of 2016 would have been higher by $9 million and $12 million, respectively. These amounts were recorded in earnings in the second quarter of 2016. We provide additional information on the 2016 GRC FD in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.
SDG&E
The increase in earnings of $19 million (14%) in the three months ended March 31, 2017 was primarily due to the following decreases, by segment:to:
 SDG&E
§  
▪$(14)9 million higher non-refundable operating costs, including depreciation and litigation,lower earnings in 2016 with no corresponding increase in the CPUC-authorized margin due to the delay in the 2016 General Rate Case (GRC) decision; we discussissuance of the 2016 GRC in Note 10FD;
▪$6 million higher CPUC base operating margin authorized for 2017, net of the Notes to Condensed Consolidated Financial Statements hereinhigher non-refundable operating costs;
§  
▪
$(13)6 million decrease due toreimbursement of litigation costs associated with the plant closure adjustment recorded in 2015 based on the California Public Utilities Commission’s (CPUC) approval of a compliance filing related to SDG&E’s authorized recovery of its investment inarbitration ruling over the San Onofre Nuclear Generating StationStation’s (SONGS), replacement steam generators, as we discuss in Note 9 of the Notes to Condensed Consolidated Financial Statements hereinherein; and
SoCalGas
§  $(12) million higher non-refundable operating costs, including depreciation and litigation, in 2016 with no corresponding increase in the CPUC-authorized margin due to the delay in the 2016 GRC decision
§  $(8) million after-tax gas cost incentive mechanism (GCIM) award approved by the CPUC in 2015
Sempra South American Utilities
§  $(4) million lower earnings from foreign currency translation and inflation effects
Sempra Mexico
§  $(24) million deferred tax expense on our investment in the Termoeléctrica de Mexicali natural gas-fired power plant as a result of management’s decision to hold the asset for sale, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein
§  $(4) million lower earnings, primarily due to positive foreign currency and inflation effects in 2015
Sempra Natural Gas
§  $(27) million impairment charge related to Sempra Natural Gas’ investment in Rockies Express Pipeline LLC (Rockies Express)
Parent and Other
§  $(10) million higher net interest expense, due primarily to debt offerings in 2015

The following table shows our earnings (losses) by segment, which we discuss below in “Segment Results.”
SEMPRA ENERGY EARNINGS (LOSSES) BY SEGMENT
(Dollars in millions)  
  Three months ended March 31,
  20162015
California Utilities:        
    SDG&E$12940%$14734%
    SoCalGas(1) 19561  21449 
Sempra International:        
    Sempra South American Utilities 3812  419 
    Sempra Mexico 175  4711 
Sempra U.S. Gas & Power:        
    Sempra Renewables 134  133 
    Sempra Natural Gas (36)(11)  2― 
Parent and other(2) (37)(11)  (27)(6) 
Earnings$319100%$437100%
(1)After preferred dividends.        
(2)Includes after-tax interest expense ($43 million and $38 million for the three months ended March 31, 2016 and 2015, respectively), intercompany eliminations recorded in consolidation and certain corporate costs.

SEGMENT RESULTS
The following section is a discussion of earnings (losses) by Sempra Energy segment, as well as Parent and other, as presented in the table above. Variance amounts are the after-tax earnings impact (based on applicable statutory tax rates), unless otherwise noted.

EARNINGS BY SEGMENT – CALIFORNIA UTILITIES
(Dollars in millions)

[graph1.gif]



Because a final decision for the 2016 GRC has not yet been issued by the CPUC, the California Utilities have recorded revenues in the three months ended March 31, 2016 based on levels authorized for 2015.
SDG&E
Our SDG&E segment recorded earnings of:
§  $129 million in the three months ended March 31, 2016
§  $147 million in the three months ended March 31, 2015
The decrease in earnings of $18 million (12%) in the three months ended March 31, 2016 was primarily due to:
§  $14 million higher non-refundable operating costs, including depreciation and litigation, in 2016 with no corresponding increase in the CPUC-authorized margin due to the delay in the 2016 GRC decision; and
§  ▪
$13 million decrease due to the plant closure adjustment recorded in 2015 based on the CPUC approval of a compliance filing related to SDG&E’s authorized recovery of its investment in SONGS; offset by
§  $34 million increase in allowance for funds used during construction (AFUDC) related to equity;offset by
§  
▪$31 million lower generation major maintenance costs; andincome tax expense in 2017 compared to $7 million income tax benefit in 2016 associated with excess tax deficiencies/benefits related to share-based compensation.
§  $3 million lower interest expense.
SoCalGas
Our SoCalGas segment recorded earnings of:
§  $195 million in the three months ended March 31, 2016 (both before and after preferred dividends)
§  $214 million in the three months ended March 31, 2015 (both before and after preferred dividends)
The decreaseincrease in earnings of $19$4 million (9%(2%) in the three months ended March 31, 20162017 was primarily due to:
§  
▪
$12 million higher non-refundable operating costs, including depreciation and litigation,lower earnings in 2016 with no corresponding increase in the CPUC-authorized margin due to the delay in the issuance of the 2016 GRC decision;
§  $8 million after-tax GCIM award approved by the CPUC in 2015 for the 12-month period ending March 31, 2014. We include incentive awards in earnings when we receive any required CPUC approval of the award, which may cause timing differences in earnings. In December 2015, SoCalGas received approval of a $4 million after-tax GCIM award for the 12-month period ending March 31, 2015; and
§  
$2 million higher interest expense; FD; offset by
§  
▪$57 million higher returnscharge in 2017 associated with CPUC-approved capital projects both under construction andtracking the income tax benefit from certain flow-through items in service.relation to forecasted amounts in the 2016 GRC FD.
Sempra South American Utilities

EARNINGS BY SEGMENT – SEMPRA INTERNATIONAL
(Dollars in millions)

[graph2.gif]

Because our operations in South America use their local currency as their functional currency, revenues and expenses are translated into U.S. dollars at average exchange rates for the period for consolidation in Sempra Energy Consolidated’s results of operations. The year-to-year variances discussed below are as adjusted for the difference in foreign currency translation rates between periods. years. We discuss these and other foreign currency effects below in “Impact of Foreign Currency and Inflation Rates on Results of Operations.”

Earnings variances below for both Sempra South American Utilities and Sempra Mexico exclude amounts attributable to noncontrolling interests.
Sempra South American Utilities
Our Sempra South American Utilities segment recorded earnings of:
§  $38 million in the three months ended March 31, 2016
§  $41 million in the three months ended March 31, 2015

The decreaseincrease in earnings of $3$9 million (7%(24%) in the three months ended March 31, 20162017 was mainly due to higher earnings from operations at Luz del Sur S.A.A. (Luz del Sur), primarily due to:
§  $4 million lower earnings from foreign currency translation and inflation effects; and
§  
$2 million lower capitalized interest due to completion of construction of the Santa Teresa hydroelectric power plant in September 2015; offset by
§  $3 million higher earnings from operations mainly due to the start of operations of the Santa Teresa hydroelectric power plant.
driven by an increase in rates, and lower operating expenses.
Sempra Mexico
Our Sempra Mexico segment recorded earnings of:
§  $17 million in the three months ended March 31, 2016
§  $47 million in the three months ended March 31, 2015
The decreaseincrease in earnings of $30 million in the three months ended March 31, 20162017 was primarily due to:
§  
▪$245 million deferred income tax benefit in 2017 compared to $29 million deferred income tax expense in 2016 on our investment in the Termoeléctrica de Mexicali as a result of management’s decision to hold the asset(TdM) natural gas-fired power plant that is held for sale, as we discuss in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report;
▪$28 million higher earnings from the recognition of AFUDC related to equity primarily associated with the Ojinaga and San Isidro pipeline projects;
▪$22 million higher pipeline operational earnings, primarily attributable to the increase in our ownership interest in Gasoductos de Chihuahua S. de R.L. de C.V. (GdC) from 50 percent to 100 percent in September 2016; and
▪
$10 million operational earnings in 2017 from the Ventika, S.A.P.I. de C.V. and Ventika II, S.A.P.I. de C.V. (Ventika) wind power generation facilities, which we acquired in December 2016; offset by
▪
$97 million income tax expense ($65 million after noncontrolling interests) from foreign currency and inflation effects, offset by a $44 million benefit ($73 million pretax) from foreign currency derivatives, which are hedging Sempra Mexico’s foreign currency exposure from its controlling interest in IEnova, as we discuss below in “Other Income, Net;” and
▪$8 million higher interest expense, including $4 million at Ventika and $2 million at GdC related to debt assumed in their acquisitions.
Sempra Renewables
The decrease in earnings of $3 million (21%) in the three months ended March 31, 2017 was primarily due to lower earnings from our wind assets.
Sempra LNG & Midstream
The increase in earnings of $33 million in the three months ended March 31, 2017 was primarily due to:
▪$27 million impairment charge in 2016 related to the investment in Rockies Express Pipeline LLC (Rockies Express), which we discuss further in Note 3 of the Notes to Condensed Consolidated Financial Statements herein;
§  
▪$420 million higher results from natural gas marketing activities; and
▪
$6 million higher results from LNG marketing activities primarily driven by changes in natural gas prices; offset by
▪$10 million lower benefit due primarily to positive effects from foreign currency and inflation in 2015, including amounts in equity earnings resulting from the sale of our joint ventures. We discuss these effects belowinvestment in “Impact of Foreign Currency and Inflation Rates on Results of Operations;”Rockies Express in May 2016; and
§  
▪$37 million lower AFUDC related to equity primarilyearnings due to completionthe sale of EnergySouth Inc. in September 2016, as we discuss in Note 3 of the first segment of the Sonora pipeline.

EARNINGS (LOSSES) BY SEGMENT – SEMPRA U.S. GAS & POWER
(Dollars in millions)

[graph3.gif]



Sempra Renewables
Our Sempra Renewables segment recorded earnings of:
§  $13 millionNotes to Consolidated Financial Statements in the three months ended March 31, 2016Annual Report.
Parent and Other
§  $13 million in the three months ended March 31, 2015
EarningsThe increase in losses of $4 million (20%) in the three months ended March 31, 2016 included $22017 was primarily due to:
▪$8 million lower income tax benefits in 2017, including:
◦
$1 million income tax expense in 2017 compared to $17 million income tax benefit in 2016 associated with excess tax deficiencies/benefits related to share-based compensation, offset by
◦$7 million income tax benefit in 2017 related to a deferred income tax liability on an outside basis difference in a subsidiary investment, and
◦$5 million U.S. income tax expense in 2016 on planned repatriation of earnings from certain non-U.S. subsidiaries; and
▪
$5 million ($8 million pretax) of costs in 2017 associated with foreign currency derivatives, as we discuss below in “Other Income, Net;”offset by
▪$5 million higher investment gains on dedicated assets in support of our executive retirement and deferred compensation plans, net of the increase in deferred compensation liability associated with the investments; and
▪$4 million lower net interest expense.
ADJUSTED EARNINGS AND ADJUSTED EARNINGS PER SHARE
We prepare the Condensed Consolidated Financial Statements in conformity with accounting principles generally accepted in the United States of America (U.S. GAAP). However, for Sempra Energy Consolidated, management may use earnings from increased production at wind projects, offset by $2 million lower solar investment tax credits from projects placedand earnings per share adjusted to exclude certain items (referred to as adjusted earnings and adjusted earnings per share) internally for financial planning, for analysis of performance and for reporting of results to the Board of Directors. We may also use adjusted earnings and


adjusted earnings per share when communicating our financial results and earnings outlook to analysts and investors. Adjusted earnings and adjusted earnings per share are non-GAAP financial measures. Because of the significance and/or nature of the excluded items, management believes that these non-GAAP financial measures provide a meaningful comparison of the performance of Sempra Energy’s business operations to prior and future periods.
Non-GAAP financial measures are supplementary information that should be considered in serviceaddition to, but not as a substitute for, the information prepared in 2015.
accordance with U.S. GAAP. The table below reconciles adjusted earnings and adjusted earnings per share to Sempra Natural Gas
Our Sempra Natural Gas segment recorded (losses) earnings of:
§  $(36) million in the three months ended March 31, 2016
§  $2 million in the three months ended March 31, 2015
The changeEnergy Earnings and Diluted Earnings Per Common Share, which we consider to be the most directly comparable financial measures calculated in accordance with U.S. GAAP, for the three months ended March 31, 2016 was primarily due to:2017 and 2016. SDG&E and SoCalGas did not have any adjustments to earnings for the three months ended March 31, 2017 or 2016.
SEMPRA ENERGY ADJUSTED EARNINGS AND ADJUSTED EARNINGS PER SHARE
(Dollars in millions, except per share amounts)
 Pretax amount Income tax (benefit) expense(1) Non-controlling interests Earnings 
Diluted
EPS
 Three months ended March 31, 2017
Sempra Energy GAAP Earnings      $441
 $1.75
Excluded item:         
Deferred income tax benefit associated with TdM$—
 $(5) $2
 (3) (0.01)
Sempra Energy Adjusted Earnings      $438
 $1.74
Weighted-average number of shares outstanding, diluted (thousands)        252,246
 Three months ended March 31, 2016(2)
Sempra Energy GAAP Earnings      $353
 $1.40
Excluded items:         
Impairment of investment in Rockies Express$44
 $(17) $—
 27
 0.11
Deferred income tax expense associated with TdM—
 29
 (5) 24
 0.09
Sempra Energy Adjusted Earnings      $404
 $1.60
Weighted-average number of shares outstanding, diluted (thousands)        251,487
§  $27 million impairment charge related
(1)Income taxes were calculated based on applicable statutory tax rates, except for adjustments that are solely income tax. Income taxes associated with TdM were calculated based on the applicable statutory tax rate, including translation from historic to current exchange rates.
(2)Reflects the investment in Rockies Express, whichadoption of ASU 2016-09, as we discuss further in Notes 3 and 8Note 2 of the Notes to Condensed Consolidated Financial Statements herein; andherein.
§  $9 million lower results primarily from midstream marketing activities driven by changes in natural gas prices.
Parent and Other
Losses for Parent and Other were
§  $37 million in the three months ended March 31, 2016
§  $27 million in the three months ended March 31, 2015
The increase in losses of $10 million (37%) in the three months ended March 31, 2016 was primarily due to:
§  $10 million higher net interest expense, due primarily to debt offerings in 2015; and
§  
$5 million of income tax benefits in 2015 related to our former commodities-marketing businesses; offset by
§  $7 million lower U.S. income tax expense in 2016 as a result of lower planned repatriation of current year earnings from certain non-U.S. subsidiaries.
CHANGES IN REVENUES, COSTS AND EARNINGS
This section contains a discussion of the differences between periods in the specificcertain line items of the Condensed Consolidated Statements of Operations for Sempra Energy, SDG&E and SoCalGas.
Utilities Revenues
Our utilities revenues include
Natural gasElectric revenues at:
§  
▪SDG&E
§  SoCalGas
§  Sempra Mexico’s Ecogas México, S. de R.L. de C.V. (Ecogas)
§  Sempra Natural Gas’ Mobile Gas Service Corporation (Mobile Gas) and Willmut Gas Company (Willmut Gas)
Electric revenues at:
§  SDG&E
§  ▪Sempra South American Utilities’ Chilquinta Energía S.A. (Chilquinta Energía) and Luz del Sur S.A.A. (Luz del Sur)
Natural gas revenues at:
▪SDG&E
▪SoCalGas
▪Sempra Mexico’s Ecogas México, S. de R.L. de C.V. (Ecogas)
▪Sempra LNG & Midstream’s Mobile Gas Service Corporation (Mobile Gas) and Willmut Gas Company (Willmut Gas) (prior to the sale of EnergySouth Inc. on September 12, 2016)
Intercompany revenues included in the separate revenues of each utility are eliminated in the Sempra Energy Condensed Consolidated Statements of Operations.
The California Utilities
The current regulatory framework for SoCalGas and SDG&E permits the cost of natural gas purchased for core customers (primarily residential and small commercial and industrial customers) to be passed through to customers in rates substantially as incurred. However, SoCalGas’ GCIM provides SoCalGas the opportunity to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are withincurrently operate under a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between the core customers and SoCalGas. We provide further discussion in Notes 1 and 14 of the Notes to Consolidated Financial Statements in the Annual Report.
The regulatory framework also permits SDG&E to recover the actual cost incurred to generate or procure electricity based on annual estimates of the cost of electricity supplied to customers. The differences in cost between estimates and actual are recovered in subsequent periods through rates.that:
▪permits SDG&E to recover the actual cost incurred to generate or procure electricity based on annual estimates of the cost of electricity supplied to customers. The differences in cost between estimates and actual are recovered in subsequent periods through rates.

The table below summarizes revenues and cost of sales for our utilities, net of intercompany activity:
UTILITIES REVENUES AND COST OF SALES
(Dollars in millions)
  Three months ended March 31,
  20162015
Electric revenues:    
   SDG&E$843$805
   Sempra South American Utilities 378 363
   Eliminations and adjustments (2) (2)
    Total 1,219 1,166
Natural gas revenues:    
   SoCalGas 1,033 1,048
   SDG&E 148 161
   Sempra Mexico 22 25
   Sempra Natural Gas 38 42
   Eliminations and adjustments (18) (20)
    Total 1,223 1,256
     Total utilities revenues$2,442$2,422
Cost of electric fuel and purchased power:    
   SDG&E$248$228
   Sempra South American Utilities 267 253
    Total$515$481
Cost of natural gas:    
   SoCalGas$253$267
   SDG&E 39 54
   Sempra Mexico 12 15
   Sempra Natural Gas 11 15
   Eliminations and adjustments (4) (5)
    Total$311$346

Sempra Energy Consolidated
Electric Revenues
During the three months ended March 31, 2016, our electric revenues increased by $53 million (5%), remaining at $1.2 billion primarily due to:
§  $38 million increase at SDG&E, which included
□  ▪$20 million higher cost of electric fuel and purchased power, which we discuss below,
□  $18 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance, and
□  $3 million higher authorized revenues from electric transmission; and
§  $15 million increase at Sempra South American Utilities, which included
□  $53 million due to higher rates at Luz del Sur and Chilquinta Energía, and
□  
$7 million higher revenues frompermits the Santa Teresa hydroelectric power plant, which began commercial operations in September 2015, offset by
□  $33 million due to foreign currency exchange rate effects, and
□  $14 million lower volumes at Luz del Sur.
Our utilities’ cost of electric fuel and purchased power increased by $34 million (7%) to $515 million in the three months ended March 31, 2016 due to:
§  $20 million increase at SDG&E, which we discuss below; and
§  $14 million increase at Sempra South American Utilities driven primarily by higher prices, offset by lower volumes and foreign currency exchange rate effects.
We discuss the changes in electric revenues and the cost of electric fuel and purchased power for SDG&E in more detail below.
Natural Gas Revenues
During the three months ended March 31, 2016, Sempra Energy’s natural gas revenues decreased by $33 million (3%) to $1.2 billion, and the cost of natural gas decreased by $35 million (10%) to $311 million. The decrease in natural gas revenues included
§  decreases in cost of natural gas soldpurchased for core customers (primarily residential and small commercial and industrial customers) to be passed through to customers in rates substantially as incurred. However, SoCalGas’ GCIM provides SoCalGas the opportunity to share in the savings and/or costs from buying natural gas for its core customers at SoCalGas and SDG&E, as we discuss below;
§  $14 million GCIM award approved by the CPUC in February 2015 at SoCalGas; and
§  
$5 million lowerprices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs at SoCalGas associated with CPUC-authorized refundable programs, which revenuesincurred when average purchase costs are fully offset in operationwithin a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between the core customers and maintenance expenses; offset by
§  $12 million higher revenues at SoCalGas for returns associated with CPUC-approved capital projects both under construction and in service, including the Pipeline Safety Enhancement Plan (PSEP).SoCalGas. We discuss the PSEPprovide further discussion in Note 101 of the Notes to Condensed Consolidated Financial Statements herein and below“Management’s Discussion and Analysis of Financial Condition and Results of Operations – Our Business” in “Factors Influencing Future Performance –the Annual Report.
▪also permits the California Utilities.Utilities to recover certain expenses for programs authorized by the CPUC, or “refundable programs.”
We discuss theBecause changes in revenuesSDG&E’s and cost of natural gas individually for SDG&E and SoCalGas below.

SDG&E: Electric Revenues and Cost of Electric Fuel and Purchased Power

The table below shows electric revenues for SDG&E for the three months ended March 31, 2016 and 2015. Because theSoCalGas’ cost of electricity and/or natural gas is substantially recovered in rates, changes in the costthese costs are reflected in the changes in revenues.revenues, and therefore do not impact earnings. In addition to the change in cost or market prices, electric or natural gas revenues recorded during a period are impacted by customer billing cycles causing a difference between customer billings and recorded or authorized costs. These differences are required to be balanced over time, resulting in over- and undercollected regulatory balancing accounts. We discuss balancing accounts and their effects further in Note 114 of the Notes to Consolidated Financial Statements in the Annual Report.

The table below summarizes revenues and cost of sales for our utilities, net of intercompany activity:
UTILITIES REVENUES AND COST OF SALES
(Dollars in millions)
 Three months ended March 31,
 2017 2016
Electric revenues:   
SDG&E$875
 $843
Sempra South American Utilities390
 378
Eliminations and adjustments(2) (2)
Total1,263
 1,219
Natural gas revenues:   
SoCalGas1,241
 1,033
SDG&E182
 148
Sempra Mexico30
 22
Sempra LNG & Midstream—
 38
Eliminations and adjustments(18) (18)
Total1,435
 1,223
Total utilities revenues$2,698
 $2,442
Cost of electric fuel and purchased power:   
SDG&E$261
 $248
Sempra South American Utilities266
 267
Total$527
 $515
Cost of natural gas:   
SoCalGas$408
 $253
SDG&E65
 39
Sempra Mexico19
 12
Sempra LNG & Midstream—
 11
Eliminations and adjustments(7) (4)
Total$485
 $311
SDG&E
ELECTRIC DISTRIBUTION AND TRANSMISSION
(Volumes in millions of kilowatt-hours, dollars in millions)
  
Three months ended
March 31, 2016
Three months ended
March 31, 2015
Customer classVolumesRevenueVolumesRevenue
Residential1,689$3391,712$346
Commercial1,579 2851,600 302
Industrial488 73497 79
Direct access834 49867 52
Street and highway lighting17 323 4
  4,607 7494,699 783
CAISO shared transmission revenue - net(1)  68  43
Other revenues  52  52
Balancing accounts  (26)  (73)
    Total(2) $843 $805
(1)California Independent System Operator (CAISO).
(2)Includes sales to affiliates of $2 million in each of 2016 and 2015.



The table below summarizes electric and natural gas volumes billed by our utilities:
For
UTILITIES VOLUMES
(Electric volumes in millions of kilowatt-hours, natural gas volumes in billion cubic feet)
 Three months ended March 31,
 2017 2016
Electric volumes:   
SDG&E:   
Residential1,671
 1,689
Commercial1,569
 1,579
Industrial500
 488
Direct access787
 834
Street and highway lighting24
 17
Total(1)4,551
 4,607
Sempra South American Utilities:   
Luz del Sur1,894
 1,949
Chilquinta Energía811
 799
Total2,705
 2,748
Natural gas volumes(2): 
  
SoCalGas:   
Natural gas sales111
 99
Transportation148
 140
Total(1)259
 239
SDG&E:   
Natural gas sales15
 14
Transportation8
 8
Total(1)23
 22
Sempra Mexico – Ecogas8
 8
(1)Includes intercompany sales.
(2)In September 2016, Sempra LNG & Midstream completed the sale of EnergySouth Inc., the parent company of Mobile Gas and Willmut Gas. Volume information for Mobile Gas and Willmut Gas has been excluded for 2016 due to immateriality.

Electric Revenues and Cost of Electric Fuel and Purchased Power
In the three months ended March 31, 2016, SDG&E’s2017, our electric revenues increased by $38$44 million (5%(4%) to $843 million compared to the corresponding period of 2015$1.3 billion primarily due to:
§  
▪$2032 million increase at SDG&E, which included
◦$16 million increase in 2017 due to an increase in rates permitted under the attrition mechanism in the 2016 GRC FD,
◦$14 million lower CPUC-authorized revenue in 2016 due to the delay in the issuance of the 2016 GRC FD, and
◦
$13 million higher cost of electric fuel and purchased power, including:
□  
an increase from the incremental purchase of renewable energy at higher prices, which we discuss below, offset by
□  a decrease
◦$10 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in consumptionO&M expenses; and
▪$12 million increase at Sempra South American Utilities, which included
◦$22 million due to energy efficiency initiatives, including rooftop solar installations,foreign currency exchange rate effects, and
□  
◦
$10 million due to higher rates at Luz del Sur, offset by
◦$17 million lower volumes at Luz del Sur primarily due to the migration of regulated and non-regulated customers to tolling customers, who pay only a decreasetolling fee and do not contribute to customer load, and
◦$6 million lower rates at Chilquinta Energía.
Our utilities’ cost of electric fuel and purchased power increased by $12 million (2%) to $527 million in the three months ended March 31, 2017 primarily due to:
▪
$13 million increase at SDG&E primarily due to an increase in the cost of purchased power and tolling costs due to declininghigher natural gas prices; offset by
▪$1 million decrease at Sempra South American Utilities driven primarily by
◦$11 million lower volumes at Luz del Sur, and
§  
◦
$6 million lower volumes at Chilquinta Energía, offset by


◦$1815 million due to foreign currency exchange rate effects.
Natural Gas Revenues and Cost of Natural Gas
The table below summarizes average cost of natural gas sold by the California Utilities and included in Cost of Natural Gas. The average cost of natural gas sold at each utility in the table below is impacted by market prices, as well as transportation, tariff and other charges.
CALIFORNIA UTILITIES AVERAGE COST OF NATURAL GAS
(Dollars per thousand cubic feet)
 Three months ended March 31,
 2017 2016
SoCalGas$3.70
 $2.57
SDG&E4.24
 2.67

In the three months ended March 31, 2017, Sempra Energy’s natural gas revenues increased by $212 million (17%) to $1.4 billion, and the cost of natural gas increased by $174 million (56%) to $485 million. The increase in natural gas revenues was primarily due to:
▪$208 million increase at SoCalGas, which included
◦$155 million increase in cost of natural gas sold, including $125 million from higher average gas prices and $30 million from higher volumes driven mainly by cooler weather in 2017,
◦$21 million increase due to 2017 attrition,
◦$14 million higher recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses;O&M expenses,
◦$14 million lower CPUC-authorized revenue in 2016 due to the delay in the issuance of the 2016 GRC FD,
◦$14 million higher revenues primarily associated with the PSEP, and
§  $3 million higher authorized revenues from electric transmission.

SDG&E and SoCalGas: Natural Gas Revenues and Cost of Natural Gas

The tables below show natural gas revenues for SDG&E and SoCalGas for the three months ended March 31, 2016 and 2015. Because the cost of natural gas is recovered in rates, changes in the cost are reflected in the changes in revenues. In addition to the change in market prices, natural gas revenues recorded during a period are impacted by the difference between customer billings and recorded or CPUC-authorized costs. These differences are required to be balanced over time, resulting in over- and undercollected regulatory balancing accounts. We discuss balancing accounts and their effects further in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.

SDG&E
NATURAL GAS SALES AND TRANSPORTATION
(Volumes in billion cubic feet, dollars in millions)
  Natural gas salesTransportationTotal
Customer classVolumesRevenueVolumesRevenueVolumesRevenue
Three months ended March 31, 2016:         
    Residential10$125―$110$126
    Commercial and industrial4 303 57 35
    Electric generation plants― ―5 15 1
  14$1558$722 162
    Other revenues        11
    Balancing accounts        (25)
        Total(1)       $148
Three months ended March 31, 2015:         
    Residential9$111―$19$112
    Commercial and industrial4 302 46 34
    Electric generation plants― ―6 ―6 ―
  13$1418$521 146
    Other revenues        11
    Balancing accounts        4
        Total(1)       $161
(1)Includes sales to affiliates of $1 million in each of 2016 and 2015.

During the three months ended March 31, 2016, SDG&E’s natural gas revenues decreased by $13 million (8%) to $148 million, primarily due to cost of natural gas sold decreasing by $15 million (28%) to $39 million.
SDG&E’s average cost of natural gas for the three months ended March 31, 2016 was $2.67 per thousand cubic feet (Mcf) compared to $4.14 per Mcf for the corresponding period in 2015, a 36-percent decrease of $1.47 per Mcf, resulting in lower revenues and cost of $21 million. The decrease in the cost of natural gas sold was offset by higher sales volumes from a cooler winter in 2016 compared to the same period in 2015, which resulted in higher revenues and cost of $6 million.

SOCALGAS
NATURAL GAS SALES AND TRANSPORTATION
(Volumes in billion cubic feet, dollars in millions)
  Natural gas salesTransportationTotal
Customer classVolumesRevenueVolumesRevenueVolumesRevenue
Three months ended March 31, 2016:       �� 
    Residential72$6961$473$700
    Commercial and industrial27 18071 6698 246
    Electric generation plants― ―33 733 7
    Wholesale― ―35 635 6
  99$876140$83239 959
    Other revenues        54
    Balancing accounts        20
        Total(1)       $1,033
Three months ended March 31, 2015:         
    Residential61$6051$662$611
    Commercial and industrial25 17872 5997 237
    Electric generation plants― ―33 733 7
    Wholesale― ―41 841 8
  86$783147$80233 863
    Other revenues        48
    Balancing accounts        137
        Total(1)       $1,048
(1)Includes sales to affiliates of $17 million in 2016 and $19 million in 2015.

During the three months ended March 31, 2016, SoCalGas’ natural gas revenues decreased by $15 million (1%), remaining at $1 billion, and the cost of natural gas sold decreased by $14 million (5%) to $253 million. The revenue decrease included
§  ◦a decrease in the cost of natural gas sold, as we discuss below;
§  $145 million GCIM award approved by the CPUC in February 2015; and
§  
$5 million lower recovery of costs associated with CPUC-authorized refundable programs, which revenues are fully offset in operation and maintenance expenses;January 2017, offset by
§  
◦$12 million higher revenues for returnscharge in 2017 associated with CPUC-approved capital projects both under constructiontracking the income tax benefit from certain flow-through items in relation to forecasted amounts in the 2016 GRC FD; and in service, including the PSEP.
▪$34 million increase at SDG&E, which included
◦$26 million increase in cost of natural gas sold primarily from higher average gas prices, and
◦$3 million increase due to 2017 attrition.
SoCalGas’ average cost of natural gas forIn the three months ended March 31, 2016 was $2.57 per Mcf compared to $3.10 per Mcf for the corresponding period in 2015, a 17-percent decrease of $0.53 per Mcf, resulting in lower2017 natural gas revenues and cost of $52 million. The decrease in the cost of natural gas sold was offsetat Sempra LNG & Midstream decreased by higher sales volumes from a cooler winter in 2016 compared$38 million and $11 million, respectively, due to the same periodsale of EnergySouth Inc. in 2015, which resulted in higher revenues and costs of $38 million.September 2016.
Other Utilities: Revenues and Cost of Sales
Revenues generated by Chilquinta Energía and Luz del Sur are based on tariffs that are set by government agencies in their respective countries based on an efficient model distribution company defined by those agencies. The bases for the tariffs do not meet the requirements necessary for regulatory accounting treatment under applicable accounting principles generally accepted in the United States of America (U.S. GAAP). We discuss revenue recognition further for Chilquinta Energía and Luz del Sur in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
Operations of Mobile Gas, Willmut Gas and Ecogas qualify for regulatory accounting treatment under applicable U.S. GAAP, similar to the California Utilities.
The table below summarizes natural gas and electric revenue for our utilities outside of California:

OTHER UTILITIES
NATURAL GAS AND ELECTRIC REVENUES      
(Dollars in millions)
  
Three months ended
March 31, 2016
Three months ended
March 31, 2015
 VolumesRevenueVolumesRevenue
Natural Gas Sales (billion cubic feet):      
Sempra Mexico – Ecogas8$227$25
Sempra Natural Gas:      
   Mobile Gas (including transportation)13 3213 34
   Willmut Gas1 61 8
   Total22$6021$67
        
Electric Sales (million kilowatt hours):      
Sempra South American Utilities:      
   Luz del Sur1,949$2321,923$217
   Chilquinta Energía799 135792 137
  2,748 3672,715 354
   Other service revenues  11  9
   Total $378 $363

We discuss changes in electric sales for Sempra South American Utilities under “Sempra Energy Consolidated – Electric Revenues” above.



Energy-Related Businesses: Revenues and Cost of Sales

The table below shows revenues and cost of sales for our energy-related businesses:

ENERGY-RELATED BUSINESSES: REVENUES AND COST OF SALES
(Dollars in millions)
 Three months ended March 31,
 2017 2016
REVENUES   
Sempra South American Utilities$22
 $22
Sempra Mexico234
 116
Sempra Renewables22

7
Sempra LNG & Midstream132
 92
Eliminations and adjustments(1)(77) (57)
Total revenues$333
 $180
COST OF SALES(2)   
Cost of natural gas, electric fuel and purchased power:   
Sempra South American Utilities$4
 $4
Sempra Mexico51
 35
Sempra LNG & Midstream88
 74
Eliminations and adjustments(1)(76) (57)
Total$67
 $56
Other cost of sales:   
Sempra South American Utilities$15
 $15
Sempra Mexico3
 2
Sempra LNG & Midstream7
 20
Eliminations and adjustments(1)(3) (2)
Total$22
 $35
(1)Includes eliminations of intercompany activity.
(2)Excludes depreciation and amortization, which are shown separately on Sempra Energy’s Condensed Consolidated
Statements of Operations.

ENERGY-RELATED BUSINESSES: REVENUES AND COST OF SALES
(Dollars in millions)
  Three months ended March 31,
  20162015
REVENUES    
    Sempra South American Utilities$22$26
    Sempra Mexico 116 138
    Sempra Renewables 7 8
    Sempra Natural Gas 92 155
    Intersegment revenues, eliminations and adjustments(1) (57) (67)
         Total revenues$180$260
COST OF SALES(2)    
Cost of natural gas, electric fuel and purchased power:    
    Sempra South American Utilities$4$9
    Sempra Mexico 35 51
    Sempra Natural Gas 74 105
    Eliminations and adjustments(1) (57) (67)
         Total$56$98
Other cost of sales:    
    Sempra South American Utilities$15$11
    Sempra Mexico 2 5
    Sempra Natural Gas 20 20
    Eliminations and adjustments(1) (2) (1)
         Total$35$35
(1)Includes eliminations of intercompany activity.
(2)Excludes depreciation and amortization, which are shown separately on the Condensed Consolidated Statements of Operations.

DuringIn the three months ended March 31, 2016,2017, revenues from our energy-related businesses decreasedincreased by $80$153 million (31%) to $180 million. The decrease included$333 million primarily due to:
§  $63 million decrease at Sempra Natural Gas primarily due to:
□  $27 million lower power revenues due to the sale of the remaining block of Mesquite Power in April 2015,
□  $20 million primarily from lower natural gas prices and volumes on power sold to Sempra Mexico’s Mexicali power plant, and
□  $12 million losses associated with midstream marketing activities driven by changes in natural gas prices; and
§  ▪
$22118 million lower revenues increase at Sempra Mexico primarily due to:
◦$75 million due to lower power pricesthe acquisition of the remaining 50-percent interest in GdC in September 2016, and volumes
◦$26 million due to the acquisition of Ventika in its power business, including $15December 2016; and
▪$40 million decreaseincrease at the Mexicali power plant,Sempra LNG & Midstream, which included
◦$27 million primarily driven by improved results from midstream marketing activities and lowerchanges in natural gas prices, in itsand
◦
$13 million from higher natural gas business; sales to Sempra Mexico; offset by
§  
▪
$1020 million primarily from lowerhigher intercompany eliminations associated with sales between Sempra Natural GasLNG & Midstream and Sempra Mexico.
DuringIn the three months ended March 31, 2016,2017, the cost of natural gas, electric fuel and purchased power for our energy-related businesses decreasedincreased by $42$11 million (43%(20%) to $56$67 million primarily due to:
§  $31 million decrease at Sempra Natural Gas primarily due to lower natural gas costs and volumes and lower electric fuel costs due to the sale of the remaining block of Mesquite Power in April 2015; and
§  ▪
$16 million decreaseincrease at Sempra Mexico primarily due to lowerhigher natural gas costs and volumes; and
▪
$14 million increase at Sempra LNG & Midstream primarily due to higher natural gas prices; offset by
§  
▪$1019 million primarily from lowerhigher intercompany eliminations of costs primarily associated with sales between Sempra Natural GasLNG & Midstream and Sempra Mexico.
Other cost of sales decreased by $13 million to $22 million in three months ended March 31, 2017, primarily due to a $13 million decrease at Sempra LNG & Midstream related to 2016 capacity costs on the Rockies Express pipeline, which capacity has since been permanently released, as we discuss in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.


Operation and Maintenance
Sempra Energy Consolidated
ForOur O&M expenses increased by $13 million (2%) to $714 million in the three months ended March 31, 2016, our operation and maintenance expenses increased by $43 million (7%) to $701 million, primarily attributable to SDG&E and SoCalGas, as we discuss below.
SDG&E
For the three months ended March 31, 2016, SDG&E’s operation and maintenance expenses increased by $29 million (13%) to $246 million2017 primarily due to:
§  
▪$1826 million increase at SoCalGas, which included
◦$15 million higher non-refundable operating costs, including labor, contract services and administrative and support costs, and
◦$14 million higher expenses associated with CPUC-authorized refundable programs for which all costs incurred are fully recovered in revenue (refundable program expenses); and
§  $12 million higher non-refundable operating costs, including labor, contract services and administrative and support costs.
SoCalGas
For the three months ended March 31, 2016, SoCalGas’ operation and maintenance expenses increased by $13 million (4%) to $327 million primarily due to:
§  ▪
$1716 million higher non-refundable operating costs, including labor, contract servicesincrease at Sempra Mexico primarily at GdC and administrative and support costs; Ventika; offset by
§  
▪$519 million decrease at SDG&E, which included
◦
$11 million reimbursement of litigation costs associated with the arbitration ruling over the SONGS replacement steam generators, as we discuss in Note 9 of the Notes to the Condensed Consolidated Financial Statements herein, and
◦
$10 million lower expenses associated with CPUC-authorized refundable programs, for which all costs incurred are fully recovered in revenue (refundable program expenses)., offset by
Plant Closure Adjustment
During the first quarter of 2015, SDG&E recorded a $21 million pretax reduction to the loss from SONGS plant closure. We discuss SONGS further in Note 9 of the Notes to Condensed Consolidated Financial Statements herein.
◦$5 million higher non-refundable operating costs, including labor, contract services and administrative and support costs; and
▪$15 million decrease at Sempra LNG & Midstream, including $9 million lower costs due to the sale of EnergySouth Inc. in September 2016.
Equity Earnings (Losses) Earnings,, Before Income Tax
Equity losses,earnings, before income tax, for the three months ended March 31, 20162017 were $22$3 million compared to equity earnings,losses, before income tax, of $19$22 million for the same period in 2015.2016. The change was primarily due to a $44 million ($27 million after-tax) impairment charge in the first quarter of 2016 related to Sempra Natural Gas’LNG & Midstream’s investment in Rockies Express, which weoffset by $16 million lower equity earnings in 2017 as a result of the sale of our 25-percent interest in Rockies Express in May 2016. We discuss the impairment charge and sale further in NotesNote 3 and 8 of the Notes to Condensed Consolidated Financial Statements herein.in the Annual Report.
Other Income, Net
Other income, net, increased by $120 million to $169 million in 2017.
In 2017, as part of our central risk management function, we entered into foreign currency derivatives to hedge Sempra Mexico parent’s exposure to movements in the Mexican peso from its controlling interest in IEnova. These foreign currency derivatives have notional amounts totaling $850 million and expire in December 2017. At March 31, 2017, we recognized other income of $65 million from gains on these foreign currency derivatives, partially mitigating $97 million ($65 million after noncontrolling interests) of income tax expense from the transactional effects of foreign currency and inflation. We discuss policies governing our risk management in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Market Risk” in the Annual Report.
Other income, net, also included the following activity:
▪$45 million increase in equity-related AFUDC primarily at Sempra Mexico mainly from the Ojinaga and San Isidro pipeline projects; and
▪$10 million foreign currency transactional gains in 2017 compared to $2 million foreign currency transactional losses in 2016.
Interest Expense
Interest expense increased by $26 million (18%) to $169 million in 2017 primarily due to higher interest expense at Sempra Mexico mainly from the recognition of AFUDC for the Ojinaga and San Isidro pipeline projects and from interest on debt assumed in the GdC and Ventika acquisitions in the fourth quarter of 2016.
Income Taxes
The table below shows the income tax expense and effective income tax rates for Sempra Energy, SDG&E and SoCalGas.
INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
 
Income tax
expense
 
Effective
income tax rate
 Income tax
expense		 
Effective
income tax rate
 Three months ended March 31,
 2017 2016(1)
Sempra Energy Consolidated$295
 39% $108
 24%
SDG&E90
 36
 65
 32
SoCalGas98
 33
 83
 29

INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
     Effective    Effective 
   Income tax income  Income tax income 
   expense tax rate  expense tax rate 
   Three months ended March 31,
   2016 2015
Sempra Energy Consolidated$142 31%$163 27%
SDG&E 72 36  88 37 
SoCalGas 87 31  95 31 


(1)Reflects the adoption of ASU 2016-09, as we discuss in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.
Sempra Energy Consolidated
The decreaseincrease in income tax expense in the three months ended March 31, 20162017 was due to lowerhigher pretax income offset byand a higher effective income tax rate. The higher effective income tax rate was primarily due to:
§  
▪$2997 million deferred Mexican income tax expense from foreign currency and inflation effects as a result of significant appreciation of the Mexican peso in the first quarter of 2017; and
▪
$3 million income tax expense in 2017 compared to $34 million income tax benefit in 2016 associated with excess tax deficiencies/benefits related to share-based compensation; offset by
▪$5 million Mexican deferred income tax benefit in 2017 compared to $29 million Mexican deferred income tax expense in 2016 on our outside basis difference in Termoeléctrica de Mexicali as a result of management’s decision to hold the assetTdM that is held for sale. We discuss the planned sale further in Note 3 of the Notes to Condensed Consolidated Financial Statements herein; offset byand
§  lower
▪$5 million U.S. income tax expense in 2016 as a result of loweron planned repatriation of current year earnings from certain non-U.S. subsidiaries. We discuss repatriation in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.
SDG&E
The decreaseincrease in SDG&E’s income tax expense in the three months ended March 31, 20162017 was due to higher pretax income and a higher effective income tax rate. The higher effective income tax rate was primarily due to lower pretax income.
$1 million income tax expense in 2017 compared to $7 million income tax benefit in 2016 associated with excess tax deficiencies/benefits related to share-based compensation.
SoCalGas
The decreaseincrease in SoCalGas’ income tax expense in the three months ended March 31, 20162017 was due to higher pretax income and a higher effective income tax rate. The higher effective income tax rate was primarily due to lower forecasted flow-through deductions as a percentage of pretax income.
income in 2017 and an income tax benefit of $4 million in 2016 associated with excess tax benefits related to share-based compensation.
We discuss the forecasted effective tax rates anticipated for the full year, excluding the income tax effects that cannot be reliably forecasted, for Sempra Energy, SDG&E and SoCalGas in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report. We discuss the impact of foreign exchange rates and inflation on income taxes below in “Impact of Foreign Currency and Inflation Rates on Results of Operations.” See Note 5 of the Notes to Condensed Consolidated Financial Statements herein and Notes 1 and 6 of the Notes to Consolidated Financial Statements in the Annual Report for further details about our accounting for income taxes.taxes and items subject to flow-through treatment.
Equity (Losses) Earnings, Net of Income Tax
Equity losses, net of income tax, for the three months ended March 31, 2017 were $8 million compared to equity earnings, net of income tax, of $17 million for the same period in 2016. The change was primarily due to:
▪$15 million of equity earnings in 2016 from GdC, including $1 million from Ductos y Energéticos del Norte (DEN), prior to IEnova’s acquisition of the remaining 50-percent interest in GdC in September 2016, as we discuss in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report; and
▪
$10 million of equity losses in 2017 at DEN, a joint venture in which GdC holds a 50-percent interest, primarily from foreign currency and inflation effects.
Earnings Attributable to Noncontrolling Interests
Earnings attributable to noncontrolling interests were unchanged in the three months ended March 31, 2017 compared to the same period in 2016 and included the following impacts from Sempra Mexico:
▪$16 million higher earnings attributable to noncontrolling interests as a result of the increase in earnings, excluding the effects of foreign currency and inflation, as we discuss above in “Segment Results – Sempra Mexico;” and
▪
$16 million higher earnings attributable to noncontrolling interests, excluding the effects of foreign currency and inflation, from the decrease in our controlling interest from 81.1 percent to 66.4 percent following IEnova’s equity offerings in October 2016, which we discuss in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report; offset by
▪$32 million losses attributable to noncontrolling interests from foreign currency and inflation effects in 2017 without the corresponding benefit from foreign currency derivatives that are not subject to noncontrolling interests, as we discuss above in “Other Income, Net.”


Earnings
IMPACT OF FOREIGN CURRENCY AND INFLATION RATES ON RESULTS OF OPERATIONS

We discuss variations in earnings by segment above in “Segment Results.”


Impact of Foreign Currency and Inflation Rates on Results of Operations

Foreign Currency Translation
OurBecause our operations in South America and our natural gas distribution utility in Mexico use their local currency as their functional currency. The assetscurrency, revenues and liabilities of these foreign operationsexpenses are translated into U.S. dollars at current exchange rates at the end of the reporting period, and revenues and expenses are translated at average exchange rates for the reporting period. The resulting noncash translation adjustments do not enter intoperiod for consolidation in Sempra Energy Consolidated’s results of operations. Some income statement activities at our foreign operations and their joint ventures are also impacted by transactional gains and losses. We discuss the calculationimpact of earnings or retained earnings, but are reflectedforeign currency and inflation rates on results of operations, including impacts on income taxes and related hedging activity, further in Other Comprehensive Income (Loss) (OCI)“Management’s Discussion and Analysis of Financial Condition and Results of Operations – Impact of Foreign Currency and Inflation Rates on Results of Operations” in Accumulated Other Comprehensive Income (Loss) (AOCI). However, anythe Annual Report.
Foreign Currency Translation
Any difference in average exchange rates used for the translation of income statement activity from year to year can cause a variance in Sempra Energy’s comparative results of operations. Changes in foreign currency translation rates between years impacted our comparative reported results as follows:


TRANSLATION IMPACT FROM CHANGE IN AVERAGE FOREIGN CURRENCY EXCHANGE RATES
(Dollars in millions)
 
First quarter 2017
compared to first quarter 2016
Higher earnings from foreign currency translation: 
Sempra South American Utilities$2
Sempra Mexico – Ecogas
—
Total$2
TRANSLATION IMPACT FROM CHANGE IN AVERAGE FOREIGN CURRENCY EXCHANGE RATES
(Dollars in millions)
      
First quarter 2016
compared to first quarter 2015
Lower earnings from foreign currency translation:  
Sempra South American Utilities$5
Sempra Mexico 1
     Total$6

Foreign Currency Transactional Impacts
Some income statement activities at our foreign operations and their joint ventures are also impacted by transactional gains and losses, which we discuss below. A summary of these foreignForeign currency transactional gains and losses included in our reported results isare as follows:


TRANSACTIONAL GAINS (LOSSES) FROM FOREIGN CURRENCY AND INFLATION
(Dollars in millions)
 Total reported amounts 
Transactional
gains (losses) included
in reported amounts
 Three months ended March 31,
 2017 2016 2017 2016
Other income, net$169
 $49
 $75
 $1
Income tax expense(295) (108) (97) 1
Equity (losses) earnings, net of income tax(8) 17
 (13) 1
Net income452
 364
 (61) 3
Earnings441
 353
 (27) 3
TRANSACTIONAL GAINS (LOSSES) FROM FOREIGN CURRENCY AND INFLATION
(Dollars in millions)
  Transactional
  gains (losses) included
 Total reported amountin reported amounts
 Three months ended March 31,
 2016201520162015
Other income, net$49$39$1$(1)
Income tax expense 142 163 1 6
Equity earnings, net of income tax 17 15 1 1
Earnings 319 437 3 5


Foreign Currency Exchange Rate and Inflation Impacts on Income Taxes and Related Hedging Activity. Our Mexican subsidiaries have U.S. dollar denominated cash balances, receivables, payables and debt (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. They also have deferred income tax assets and liabilities denominated in the Mexican peso 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. As a result, fluctuations in both the currency exchange rate for the Mexican peso against the U.S. dollar and Mexican inflation may expose us to fluctuations in Income Tax Expense and Equity Earnings, Net of Income Tax. We utilize short-term foreign currency derivatives as a means to manage these exposures. The derivative activity impacts Other Income, Net.
The income tax expense of our South American subsidiaries is similarly impacted by these factors.
Other Transactions. Although the financial statements of our Mexican subsidiaries and joint ventures (Gasoductos de Chihuahua, or GdC, and Energía Sierra Juárez) have the U.S. dollar as the functional currency, some transactions may be denominated in the local currency; such transactions are remeasured into U.S. dollars. This remeasurement creates transactional gains and losses that are included in Other Income, Net, for our consolidated subsidiaries and Equity Earnings, Net of Income Tax, for our joint ventures.
We utilize cross-currency swaps that exchange our Mexican-peso denominated principal and interest payments into the U.S. dollar and swap Mexican variable interest rates for U.S. fixed interest rates. The impacts of these cross-currency swaps are offset in OCI and are reclassified from AOCI into earnings through Interest Expense as settlements occur.
Certain of our Mexican joint venture projects (Los Ramones I and Los Ramones Norte) generate revenue based on tariffs that are set by government agencies in Mexico, with contracts denominated in Mexican pesos that are indexed to the U.S. dollar, adjusted annually for inflation and fluctuation in the exchange rate. The resultant gains and losses from remeasuring the local currency amounts into U.S. dollars are included in Equity Earnings, Net of Income Tax. The activity of foreign currency forwards and swaps related to these contracts settle through Equity Earnings, Net of Income Tax.
Our South American joint ventures (Eletrans S.A. and Eletrans II S.A., collectively Eletrans) use the U.S. dollar as the functional currency, but have certain construction commitments that are denominated in the Chilean Unidad de Fomento (CLF). Eletrans entered into forward exchange contracts to manage the foreign currency exchange risk of the CLF relative to the U.S. dollar. The forward exchange contracts settle based on anticipated payments to vendors, generally monthly, ending in 2018, with activity recorded in Equity Earnings, Net of Income Tax.


CAPITAL RESOURCES AND LIQUIDITY
OVERVIEW

We expect our cash flows from operations to fund a substantial portion of our capital expenditures and dividends. We may also meet our cash requirements through the issuance of securities,unrestricted cash and cash equivalents, borrowings under our credit facilities, distributions from our equity method investments, issuances of securities, project financing and project financing.
equity sales, including tax equity and partnering in joint ventures.
Our lines of credit provide liquidity and support commercial paper. As we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements herein, Sempra Energy, Sempra Global (the holding company for our subsidiaries not subject to California utility regulation) and the California Utilities each have five-year revolving credit facilities expiring in 2020. The agreements are syndicated broadly among 20 different lenders. No single lender has greater than a 7-percent share in any agreement. The table below shows the


amount of available funds, including available unused credit on these three credit facilities, at March 31, 2016.2017. Our foreign operations have additional general purpose credit facilities aggregating $1.1$1.7 billion, with $1 billion available unused credit at March 31, 2016. Available unused credit on these lines totaled $876 million at March 31, 2016.2017.


AVAILABLE FUNDS AT MARCH 31, 2017
(Dollars in millions)
 
Sempra Energy
Consolidated
 SDG&E SoCalGas
Unrestricted cash and cash equivalents(1)$290
 $18
 $21
Available unused credit(2)2,730
 407
 657
AVAILABLE FUNDS AT MARCH 31, 2016
(Dollars in millions)
  Sempra Energy  
  ConsolidatedSDG&ESoCalGas
Unrestricted cash and cash equivalents(1)$376$36$14
Available unused credit(2) 3,160 584 745
(1)Amounts at Sempra Energy Consolidated include $311 million held in non-U.S. jurisdictions that are unavailable to fund U.S. operations unless repatriated, as we discuss below.
(2)Available credit is the total available on Sempra Energy’s, Sempra Global’s and the California Utilities’ credit facilities that we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements herein. At March 31, 2016, borrowings on the shared line of credit at SDG&E and SoCalGas were limited to $750 million for each utility and a combined total of $1 billion. SDG&E's and SoCalGas' available funds reflect commercial paper outstanding of $166 million and $5 million, respectively, supported by the line.
(1)Amounts at Sempra Energy Consolidated include $219 million held in non-U.S. jurisdictions that are unavailable to fund U.S. operations unless repatriated. We discuss repatriation in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.
(2)
Available unused credit is the total available on Sempra Energy’s, Sempra Global’s and the California Utilities’ credit facilities that we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements herein. Borrowings on the shared line of credit at SDG&E and SoCalGas are limited to $750 million for each utility and a combined total of $1 billion. SDG&E’s available funds reflect commercial paper outstanding of $343 million, supported by the line. SoCalGas’ availability reflects the impact of SDG&E’s use as of March 31, 2017 of the combined credit available on the line.
Sempra Energy Consolidated
We believe that these available funds, combined with cash flows from operations, distributions from our equity method investments, proceedsissuances of securities, issuances, project financing and equity sales, including tax equity and partnering in joint ventures, will be adequate to fund operations, including to:
§  
▪finance capital expenditures
§  
▪meet liquidity requirements
§  
▪fund shareholder dividends
§  
▪fund new business acquisitions or start-ups
§  
▪repay maturing long-term debt
§  
▪fund expenditures related to the natural gas leak at SoCalGas’ Aliso Canyon natural gas storage facility
In 2015, Sempra Energy, SDG&E, and SoCalGas publicly offered and sold debt securities totaling $1.25 billion, $390 million and $600 million, respectively. Sempra Energy and the California Utilities currently have ready access to the long-term debt markets and are not currently constrained in their ability to borrow at reasonable rates. However, changing economic conditions could affect the availability and cost of both short-term and long-term financing. Also, cash flows from operations may be impacted by the timing of commencement and completion of large projects at Sempra International and Sempra U.S. Gas & Power.Infrastructure. If cash flows from operations were to be significantly reduced or we were unable to borrow under acceptable terms, we would likely first reduce or postpone discretionary capital expenditures (not related to safety) and investments in new businesses. If these measures were necessary, they would primarily impact certain of our Sempra International and Sempra U.S. Gas & PowerInfrastructure businesses before we would reduce funds necessary for the ongoing needs of our utilities. We monitor our ability to finance the needs of our operating, investing and financing activities in a manner consistent with our intention to maintain strong, investment-grade credit ratings and capital structure.
In additionOur short-term debt is primarily used to meet liquidity requirements, fund shareholder dividends, and temporarily finance capital expenditures the net decrease in Sempra Energy Consolidated cash and cash equivalents at March 31, 2016 compared to December 31, 2015 of $27 million was primarily due to expenditures at SoCalGas related to the natural gas leak at the Aliso Canyon facility and common dividends paid, partially offset bynew business acquisitions or start-ups. Our corporate short-term, unsecured promissory notes, or commercial paper, borrowings on the Sempra Global credit facility. We discusswere our Insurance Receivable and our insurance coverage related to the natural gas leak at the Aliso Canyon facility in Note 11primary sources of the Notes to Condensed Consolidated Financial Statements herein.
At March 31, 2016, our cash and cash equivalents held in non-U.S. jurisdictions that are unavailable to fund U.S. operations unless repatriated are $311 million. We discuss repatriation in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations”short-term debt funding in the Annual Report.
first three months of 2017. At our California Utilities, short-term debt is used primarily to meet working capital needs.
We have significant investments in several trusts to provide for future payments of pensions and other postretirement benefits, and nuclear decommissioning. Changes in asset values, which are dependent on the activity in the equity and fixed income markets, have not affected the trust funds’ abilities to make required payments. However, changes in asset values may, along with a number of other factors such as changes to discount rates, assumed rates of return,returns, mortality tables, and regulations, impact funding requirements for pension and other postretirement benefit plans and SDG&E’s nuclear decommissioning trusts. At the California Utilities, funding requirements are generally recoverable in rates.
We discuss our principal, general purpose credit facilities more fullyemployee benefit plans and SDG&E’s nuclear decommissioning trusts, including our investment allocation strategies for assets in Note 6 of thethese trusts, in Notes to Condensed Consolidated Financial Statements herein7 and in Note 513, respectively, of the Notes to Consolidated Financial Statements in the Annual Report.
Loans to Affiliates
Our short-term debt is primarily usedAt March 31, 2017, Sempra Energy has provided loans to meet liquidity requirements, fund shareholder dividends, and temporarily finance capital expenditures and new business acquisitions or start-ups. Our corporate short-term, unsecured promissory notes, or commercial paper, were our primary sourcesunconsolidated affiliates totaling $211 million, which we discuss in Note 5 of short-term debt funding in the first three months of 2016. At our California Utilities, short-term debt is usedNotes to meet working capital needs and temporarily finance capital expenditures.Condensed Consolidated Financial Statements herein.


California Utilities

SDG&E and SoCalGas expect that available funds, cash flows from operations and debt issuances will continue to be adequate to meet their working capital and capital expenditure requirements.
SoCalGasSDG&E declared and paid common stock dividends of $50$175 million in 2015the year ended December 31, 2016 and $100 millionthe three months ended March 31, 2017. SDG&E expects to pay dividends approximating 75 percent of its earnings in 2014. 2017, subject to the discretion and approval of its board of directors.
As a result of an increase in SoCalGas’ large capital investment programs overprogram, SoCalGas has not declared or paid common stock dividends since 2015. SoCalGas does not anticipate paying common stock dividends in 2017 in order to maintain its authorized capital structure while managing its large capital program (over $1 billion in 2017).
Changes in balancing accounts for significant costs at SDG&E and SoCalGas, particularly a change in status between over- and under- collected, may have a significant impact on cash flows, as these changes generally represent the next few years,difference between when costs are incurred and when they are ultimately recovered in rates through billings to customers. SDG&E uses the Energy Resource Recovery Account (ERRA) balancing account to record the net of its actual cost incurred for electric fuel and purchased power. SDG&E’s ERRA balance was undercollected by $93 million at March 31, 2017 and $25 million at December 31, 2016. During the first three months of 2017, the increase in SoCalGas’the ERRA undercollected balance was primarily due to lower electric volume in conjunction with seasonalized electric rates. The CPUC authorized common equity weighting effective January 1, 2013 as approved byan ERRA Trigger mechanism in conjunction with California state law that allows for recovery of ERRA balances that exceed 5 percent of the prior year’s electric commodity revenues. SDG&E intends to file an ERRA Trigger application with the CPUC requesting recovery of the undercollected balance in the most recent costsecond quarter of capital proceeding,2017.
SoCalGas and SDG&E use the Core Fixed Cost Account (CFCA) balancing account to record the difference between the authorized margin and other costs allocated to core customers. Because warm weather experienced in 2016 and 2017 resulted in lower natural gas consumption compared to authorized levels, SoCalGas’ dividendsCFCA balance was undercollected by $114 million at both March 31, 2017 and December 31, 2016. SDG&E’s CFCA balance was undercollected by $35 million at March 31, 2017 and $66 million at December 31, 2016.
SoCalGas
Aliso Canyon Natural Gas Storage Facility Gas Leak
We provide information on common stock declared on an annual historical basis may not be indicative of future declarations, and may be temporarily suspended over the next few years to maintain SoCalGas’ authorized capital structure during the periods of high capital investments. We discuss the cost of capital proceeding in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report.
In connection with the natural gas leak at the Aliso Canyon storage facility asfurther in Note 11 of April 28, 2016, 138 lawsuits have been filed against SoCalGas, some of which have also named Sempra Energy,the Notes to Condensed Consolidated Financial Statements herein, and in derivative and securities law claims on behalf of Sempra Energy and/or SoCalGas, certain officers and directors of Sempra Energy and/or SoCalGas. In addition, the Los Angeles City Attorney and Los Angeles County Counsel have also filed a complaint on behalf“Factors Influencing Future Performance” below, as well as in Note 15 of the people ofNotes to Consolidated Financial Statements and “Risk Factors” in the State of California against SoCalGas for public nuisance and violation of the California Unfair Competition Law. The California Attorney General, acting in her independent capacity and on behalf of the people of the State of California and the California Air Resources Board (CARB), joined that existing lawsuit. The complaint, which as amended includes the California Attorney General, adds allegations of violations of certain California Health and Safety Code and California Government Code sections. The South Coast Air Quality Management District (SCAQMD) also filed a complaint against SoCalGas seeking civil penalties for alleged violations of several nuisance-related statutory provisions arising from the leak and delays in stopping the leak. On February 2, 2016, the Los Angeles District Attorney’s Office filed a misdemeanor criminal complaint against SoCalGas seeking penalties and other remedies for alleged failure to provide timely notice of the leak pursuant to California Health and Safety Code section 25510(a), Los Angeles County Code section 12.56.030, and Title 19 California Code of Regulations section 2703(a), and for violating California Health and Safety Code section 41700 prohibiting discharge of air contaminants that cause annoyance to the public.Annual Report. The costs of defending against thesethe related civil and criminal lawsuits and cooperating with theserelated investigations, and any damages, restitution, and civil, administrative and criminal fines, costs and other penalties, if awarded or imposed, as well as 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. Also, 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 in customer rates, which may have a material adverse effect on SoCalGas’ and Sempra Energy’s results of operations, cash flows, and financial condition.
In connection withThe total costs incurred to remediate and stop the temporary relocation support, on April 27, 2016, the California Superior Court (Superior Court) ordered an extension of the relocation support term pending the completion of the County of Los Angeles’ (County) indoor testing. The County has reported that it anticipates completing its analysisleak and releasing a final report by late May 2016. The next scheduled Superior Court hearing on this matter is June 7, 2016. While the temporary relocation support period could end before June 7, 2016, dueto mitigate local community impacts are significant and may increase, and to the fact that the temporary relocation support has been extended several times,extent not covered by insurance (including any costs in excess of applicable policy limits), or if there canwere to be no assurance that future extensions will not be granted. The cost of the temporary relocation support is significant and thedelays in receiving insurance recoveries, such costs of any further extensions of the relocation support term, which are not included in our estimate of costs related to the leak, could result inhave a material increase in our cost estimate.
We discuss the Aliso Canyon facility further in Note 11 of the Notes to Condensed Consolidated Financial Statements herein,adverse effect on SoCalGas’ and in “Factors Influencing Future Performance” below.
SDG&E declared and paid common stock dividends of $300 million in 2015 and $200 million in 2014. SDG&E expects to continue paying common dividends over the next five years, at or above the level paid in 2015. While it expects to maintain a large capital program (exceeding $1 billion per year), SDG&E expects that itsSempra Energy’s cash flows, will support these dividends to the parent.
SDG&E notified bondholders in April 2016 that it intends to redeem, prior to maturity, certain outstanding long-term debt instruments with a total principal amountfinancial condition and results of $105 million. The debt is classified as long-term at March 31, 2016 on Sempra Energy’s and SDG&E’s Condensed Consolidated Balance Sheets. The coupon rate of these instruments is 5 percent and they mature in 2027. SDG&E expects to redeem the debt in the second quarter of 2016.
SDG&E uses the Energy Resource Recovery Account (ERRA) balancing account to record the net of its actual cost incurred for electric fuel and purchased power and the amount billed to customers in rates. In December 2015, the CPUC approved SDG&E’s 2016 ERRA revenue requirement of $1.3 billion, an increase of $43 million from its 2015 revenue requirement. As the new revenue requirement was effective on January 1, 2016, management expects the ERRA balance to remain stable in 2016. SDG&E’s ERRA balance was undercollected by $38 million at March 31, 2016 and overcollected by $25 million at December 31, 2015. We discuss the revenue requirement for ERRA further in Note 14 of the Notes to Consolidated Financial Statements and other 2015 impacts on ERRA balances in “Capital Resources and Liquidity – Overview – California Utilities” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” both in the Annual Report.
SoCalGas and SDG&E use the Core Fixed Cost Account (CFCA) balancing account to record the difference between the authorized margin and other costs allocated to the core market, and the actual revenues billed to customers in rates for recovery of these costs. Because warmer weather experienced in 2014 and 2015 resulted in lower natural gas consumption compared to authorized levels, SoCalGas’ CFCA balance was undercollected by $313 million at March 31, 2016 and $328 million at December 31, 2015. SDG&E’s CFCA balance was undercollected by $76 million at March 31, 2016 and $105 million at December 31, 2015.
Under its current ratemaking treatment, SoCalGas and SDG&E have the authority through an Annual Regulatory Account Balance Update filing to recover undercollections accumulated in the prior year, consisting of actual recorded activity through August and an estimate for the remainder of the year. SoCalGas and SDG&E are currently amortizing $417 million and $99 million, respectively, of the December 31, 2015 CFCA balance in 2016 rates.

operations.
Sempra South American Utilities

We expect working capital and capital expenditure requirements, projects, joint venture investments, and loans to affiliates at Chilquinta Energía and Luz del Sur and dividends at Luz del Sur to be funded by available funds, funds internally generated by those businesses, issuances of corporate bonds and byother external borrowings. At March 31, 2016 and December 31, 2015, Sempra South American Utilities had outstanding loans of $76 million and $72 million, respectively, to an affiliate to finance development projects. We discuss these transactions in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.


Sempra Mexico

We expect working capital and capital expenditure requirements, projects, joint venture investments and dividends in Mexico to be funded through a combination ofby available funds, including credit facilities, and funds internally generated by the Mexico businesses, securities issuances, project financing, interim funding from the parent or affiliates, and partnering in joint ventures. In 2015 and 2014, Sempra Mexico paid dividends of $32 million and $31 million, respectively, to its minority shareholders.
We discuss IEnova’s potential acquisition of Petróleos Mexicanos’ (or PEMEX, the Mexican state-owned oil company) 50-percent interest in GdC in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.
At March 31, 2016 and December 31, 2015, Sempra Mexico had outstanding loans of $104 million and $111 million, respectively, to affiliates to finance development projects. We discuss these transactions in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.
Sempra Mexico may also expects to generate cash from the sale of its 625-megawatt (MW)625-MW natural gas-fired TdM power plant located in Mexicali, Baja California, Mexico.Mexico in the second half of 2017. As we discuss in Note 3 of the Notes to Condensed Consolidated Financial


Statements herein, in February 2016, management approved a plan to market and sell the TdM plant, whichand we continue to actively pursue its sale. TdM had a net book value of $260$156 million (including associated assets and liabilities) at March 31, 2016.2017.


In 2016, Sempra Mexico paid dividends of $26 million to its minority shareholders.
Sempra Renewables

We expect Sempra Renewables to require funds for the development of and investment in electric renewable energy projects. Projects at Sempra Renewables may be financed through a combination of operating cash flow, project financing, funds from the parent, partnering in joint ventures, and other forms of equity sales.sales, including tax equity. The Sempra Renewables projects have planned in-service dates through 2016.


varying costs and structure of these alternative financing sources impact the projects’ returns and their earnings profile.
Sempra Natural GasLNG & Midstream

We expect Sempra Natural GasLNG & Midstream to require funding for the development and expansion of its portfolio of projects, which may be financed through a combination of operating cash flow, funding from the parent, project financing and project financing. Sempra Natural Gas also expects to receive approximately $440 millionpartnering in proceeds from the pending sale of its investment in Rockies Express, and approximately $323 million from the pending sale of Mobile Gas and Willmut Gas, as we discuss is Notes 3 and 13, respectively, of the Notes to Condensed Consolidated Financial Statements herein. Proceeds from both transactions are subject to adjustment at closing. In the short-term, we plan to use the sale proceeds from these transactions to pay down commercial paper at Sempra Energy, pending redeployment for other growth opportunities.
joint ventures.
Sempra Natural Gas,LNG & Midstream, through its interest in Cameron LNG JV,Holdings, LLC (Cameron LNG JV), is developing a natural gas liquefaction export facility at the Cameron LNG JV terminal. The majority of the current three-train liquefaction project is project-financed, with most or all of the remainder of the capital requirements to be provided by the project partners, including Sempra Energy, through equity contributions under a joint venture agreement. We expect that our remaining equity requirements to complete the project will be met by a combination of our share of cash generated from each liquefaction train as it comes on line and additional cash contributions. Under the financing agreements, Sempra Energy signed completion guarantees for 50.2 percent of the debt, which corresponds to $3.7 billion of the total $7.4 billion principal amount of the debt committedCameron LNG JV’s obligations under the financing agreements.agreements, for a maximum amount of $3.9 billion. The project financing and completion guarantees became effective on October 1, 2014, the effective date of the joint venture formation. The completion guarantees will terminate upon satisfaction of certain conditions, including all three trains achieving commercial operation and meeting certain operational performance tests. The completion guarantees are anticipated to be terminated in the second half of 2019.approximately nine months after all three trains achieve commercial operation.
We discuss Cameron LNG JV and the joint venture financing further in Notes 3 and 4 of the Notes to Consolidated Financial Statements, in “Risk Factors,” and in “Factors Influencing Future Performance” in the Annual Report. We also discuss Cameron LNG JV in “Factors Influencing Future Performance” below.


CASH FLOWS FROM OPERATING ACTIVITIES


CASH PROVIDED BY OPERATING ACTIVITIES
(Dollars in millions)
 Three months ended
March 31, 2017

2017 change

Three months ended
March 31, 2016(1)
Sempra Energy Consolidated$1,004
  $378
 60%  $626
SDG&E386
  17
 5
  369
SoCalGas463
  222
 92
  241
CASH PROVIDED BY OPERATING ACTIVITIES
(Dollars in millions)
 
Three months ended
March 31, 2016
2016 change
Three months ended
March 31, 2015
Sempra Energy Consolidated$592$(219)(27)%$811
SDG&E 369 7023  299
SoCalGas 241 (134)(36)  375
(1) Reflects the adoption of ASU 2016-09, as we discuss in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.
Sempra Energy Consolidated
Cash provided by operating activities at Sempra Energy decreasedincreased in 20162017 primarily due to:
§  
▪$335288 million net increase in receivable at SoCalGas for expected insurance recovery of certain expenditures related to the natural gas leak at the Aliso Canyon storage facility, andcomprised of:
◦
$15 million net increase in receivable for expected insurance recovery in 2017 compared to $335 million net increase in 2016. The $15 million net increase includes $19 million of additional accruals, offset by $4 million in insurance proceeds, offset by
◦$4 million net decrease in reserve for accrued expenditures in 2017 compared to a $28 million net increase in reserve for accrued expenditures related to the leak.2016. The $28$4 million net increasedecrease includes $335$29 million of cash expenditures, offset primarily by $19 million of additional accruals, offset by $307accruals;
▪$142 million of cash expenditures;
§  $40 million decrease in inventories in 2016 compared to a $132 million decrease in 2015, primarily due to lower gas inventory at SoCalGas as a result of the current moratorium on natural gas injections at its Aliso Canyon natural gas storage facility;
§  $40 million lowerhigher net income, adjusted for noncash items included in earnings, in 20162017 compared to 2015;2016;
▪$53 million lower purchases of greenhouse gas allowances in 2017 ($25 million at SDG&E and $28 million at SoCalGas);
▪$32 million payment of capital gains tax assessment in 2016 related to our 2011 acquisition of interest in Luz del Sur;
▪$31 million increase due to timing of franchise fee payments at SDG&E; and
§  
▪
$2830 million higher decreaseincrease in compensation and benefit accrualsseasonal liability related to temporary last-in first-out (LIFO) liquidation in 2016 compared2017 at SoCalGas, primarily due to 2015; changes in natural gas inventory value; offset by
§  
▪$7137 million increasedecrease in accounts payable in 20162017 compared to a $152$7 million increase in 2016. The 2017 decrease in 2015,was primarily due to the current moratorium on natural gas injections at the Aliso Canyon storage facility as well as lower average costvolumes and prices of natural gas purchased;purchased at SoCalGas; and


§  
▪$18994 million decrease in accounts receivable in 20162017 compared to a $129$189 million decrease in 2015,2016. The 2016 decrease was primarily due to lower natural gas prices at SoCalGasSoCalGas.
SDG&E
Cash provided by operating activities at SDG&E increased in 2017 primarily due to:
▪$43 million higher net income, adjusted for noncash items included in earnings, in 2017 compared to 2016;
▪$31 million increase due to timing of franchise fee payments; and
▪
$25 million lower purchases of greenhouse gas allowances in 2017; offset by
▪$13 million increase in accounts receivable in 2017 compared to a $26 million decrease in 2016; and
§  
▪$8427 million net decrease in net undercollected regulatory balancing accounts (including long-term amounts included in regulatory assets) in 2016 at the California Utilities2017 compared to a $27 million net decrease in 2015. Over- and undercollected regulatory balancing accounts reflect the difference between customer billings and recorded or CPUC-authorized costs. These differences are required to be balanced over time. See further discussion of changes in regulatory balances at both SDG&E and SoCalGas below.
SDG&E
Cash provided by operating activities at SDG&E increased in 2016 primarily due to:
§  $26$64 million decrease in accounts receivable in 2016 compared to a $15 million increase in 2015;2016.
§  $27 million increase in greenhouse gas allowances in 2016 compared to a $67 million increase in 2015; and
§  
$8 million net income tax refunds in 2016 compared to $31 million net income tax payments in 2015; offset by
§  $30 million lower net income, adjusted for noncash items included in earnings, in 2016 compared to 2015.
SoCalGas
Cash provided by operating activities at SoCalGas decreasedincreased in 20162017 primarily due to:
§  
▪$335288 million net increase in receivable for expected insurance recovery of certain expenditures related to the natural gas leak at the Aliso Canyon storage facility, andcomprised of:
◦
$15 million net increase in receivable for expected insurance recovery in 2017 compared to $335 million net increase in 2016. The $15 million net increase includes $19 million of additional accruals, offset by $4 million in insurance proceeds, offset by
◦$4 million net decrease in reserve for accrued expenditures in 2017 compared to a $28 million net increase in reserve for accrued expenditures related to the leak.2016. The $28$4 million net increasedecrease includes $335$29 million of cash expenditures, offset primarily by $19 million of additional accruals, offset by $307accruals;
▪$35 million of cash expenditures;
§  $23 million increasehigher net income, adjusted for noncash items included in income taxes payableearnings, in 20162017 compared to a $107 million increase in 2015; and2016;
§  
$46 million decrease in inventories in 2016 compared to a $72 million decrease in 2015, primarily due to lower gas inventory as a result of the current moratorium on natural gas injections at the Aliso Canyon storage facility; offset by
§  ▪$29 million decrease in accounts payable in 2016 compared to a $160 million decrease in 2015, primarily due to the current moratorium on natural gas injections at the Aliso Canyon storage facility, as well as lower average cost of natural gas purchased;
§  $2051 million increase in net overcollected regulatory balancing accounts (including long-term amounts included in regulatory assets) in 20162017 compared to a $49$20 million increase in net undercollected balances2016;
▪$30 million increase in 2015,seasonal liability related to temporary LIFO liquidation in 2017, primarily due to changes in fixed cost balancing accounts;
§  $57 million higher net income, adjusted for noncash items included in earnings, in 2016 compared to 2015;natural gas inventory value; and
§  
▪
$28 million lower purchases of greenhouse gas allowances in 2017; offset by
▪$18681 million decrease in accounts receivable in 20162017 compared to a $136$186 million decrease in 2015,2016. The large decrease in 2016 was primarily due to lower average natural gas prices;
▪$93 million decrease in accounts payable in 2017 compared to a $29 million decrease in 2016. The 2017 decrease was primarily due to lower volumes and prices of natural gas purchased; and
▪$15 million decrease in inventory in 2017 compared to a $46 million decrease in 2016.
The table below shows the contributions to pension and other postretirement benefit plans.

CONTRIBUTIONS TO PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
(Dollars in millions)
 Three months ended March 31, 2016
   Other
 Pensionpostretirement
 benefitsbenefits
Sempra Energy Consolidated$15$1
SDG&E 2 ―


CASH FLOWS FROM INVESTING ACTIVITIES


CASH USED IN INVESTING ACTIVITIES
(Dollars in millions)
 Three months ended Three months ended
 March 31, 20162016 changeMarch 31, 2015
Sempra Energy Consolidated$(989)$21928%$(770)
SDG&E (330) (91)(22)  (421)
SoCalGas (290) (99)(25)  (389)
CASH USED IN INVESTING ACTIVITIES
(Dollars in millions)
 Three months ended
March 31, 2017

2017 change

Three months ended
March 31, 2016
Sempra Energy Consolidated$(1,026)  $37
 4%  $(989)
SDG&E(381)  51
 15
  (330)
SoCalGas(392)  102
 35
  (290)
Sempra Energy Consolidated
Cash used in investing activities at Sempra Energy increased in 20162017 primarily due to:
§  
▪$19129 million increase in expenditures for investments; and
▪
$21 million increase in capital expenditures; andoffset by
§  
▪$248 million lower repayments of advances to unconsolidated affiliates.higher distributions from our equity method investments.
SDG&E
Cash used in investing activities at SDG&E decreasedincreased in 20162017 primarily due to:
§  
▪
$89 million increase in capital expenditures; offset by
▪$6631 million repayment of advances to Sempra Energy in 2015; and2017.

§  $26 million decrease in capital expenditures in 2016.

SoCalGas
Cash used in investing activities at SoCalGas decreasedincreased in 20162017 primarily due to:
§  
▪$5035 million decreaseincrease in advances to Sempra Energy in 20162017 compared to a $74$50 million increasedecrease in 2015; offset by2016; and
§  
▪$2517 million increase in capital expenditures in 2016.expenditures.
Capital Expenditures
Sempra Energy Consolidated Expenditures for Property, Plant and Equipment
ANNUAL CONSTRUCTION EXPENDITURES AND INVESTMENTSThe following table summarizes capital expenditures in 2017 compared to 2016.
EXPENDITURES FOR PROPERTY, PLANT AND EQUIPMENT
(Dollars in millions)

Three months ended March 31,
 2017
2016
SDG&E:


Improvements to natural gas, including certain pipeline safety, and electric and generation




distribution systems$308

$223
Pipeline Safety Enhancement Plan (PSEP)10

26
Improvements to electric transmission systems92

80
Electric generation plants and equipment8

—
SoCalGas:




Improvements to distribution, transmission and storage systems, and for certain pipeline safety307

224
PSEP36

83
Advanced metering infrastructure14

33
Sempra South American Utilities:




Improvements to electric transmission and distribution systems and generation




projects in Peru29

32
Improvements to electric transmission and distribution infrastructure in Chile14

11
Sempra Mexico:




Construction of the Sonora, Ojinaga and San Isidro pipeline projects85

34
Construction of other natural gas pipeline and wind projects, and capital expenditures at Ecogas9

6
Sempra Renewables:

 
Construction costs for wind projects28

20
Construction costs for solar projects/facilities41

161
Sempra LNG & Midstream:


 
Cameron Interstate Pipeline and other LNG liquefaction development costs3

29
Other—

6
Parent and other8

3
Total$992

$971

The amounts and timing of capital expenditures are generally subject to approvals by various regulatory and other governmental and environmental bodies, including the CPUC and the Federal Energy Regulatory Commission (FERC). However, in 2016,FERC. In 2017, we expect to make capital expenditures and investments of approximately $5.5 billion. These expenditures include
§  $2.7 billion at the California Utilities for capital projects and plant improvements ($1.3 billion at SDG&E and $1.4 billion at SoCalGas), excluding incremental amounts that may result from the natural gas leak at the Aliso Canyon facility or related increased requirements for all natural gas storage facilities
§  $2.8 billion at our other subsidiaries for acquisition of our joint venture partner’s 50-percent interest in GdC, capital projects in Mexico and South America, and development of LNG, natural gas and renewable generation projects
The California Utilities’ 2016 planned capital expenditures$3.4 billion, as summarized in “Capital Resources and investments include
SDG&E
§  $800 million for improvements to natural gas, including pipeline safety, and electric generation and distribution systems
§  $500 million for improvements to electric transmission systems
SoCalGas
§  $1.2 billion for improvements to distribution, transmission and storage systems, and for pipeline safety, including $350 million for the PSEP
§  $100 million for advanced metering infrastructure
§  $100 million for other natural gas projects
The California Utilities expect to finance these expenditures and investments with cash flows from operations and debt issuances.
In 2016, the expected capital expenditures and investments of approximately $2.8 billion at our other subsidiaries include
Sempra South American Utilities
§  approximately $220 million for capital projects in South America (approximately $160 million and $60 million in Peru and Chile, respectively), primarily related to improvements to electric transmission and distribution systems
Sempra Mexico
§  approximately $450 million to $500 million for capital projects, including approximately $400 million for the development of the Sonora, Ojinaga and San Isidro – Samalayuca pipeline projects, all developed solely by Sempra Mexico
§  funds for the potential acquisition of our joint venture partner’s 50-percent interest in GdC, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein
Sempra Renewables
§  approximately $900 million for the development of wind and solar renewable projects, including Black Oak Getty Wind, Mesquite Solar 2, Mesquite Solar 3 and Copper Mountain Solar 4
Sempra Natural Gas
§  approximately $170 million for development of LNG and natural gas transportation projects, including approximately $50 million capitalized interest on our investment in the Cameron LNG JV, and $80 million for development of the Cameron Interstate Pipeline
Capital expenditure amounts include capitalized interest. At the California Utilities, the amounts also include the portion of AFUDC related to debt, but exclude the portion of AFUDC related to equity. At Sempra Mexico and Sempra Natural Gas, the amounts also exclude AFUDC related to equity. We provide further details about AFUDC in Note 1 of the Notes to Consolidated Financial StatementsLiquidity” in the Annual Report.

CASH FLOWS FROM FINANCING ACTIVITIES

CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
 Three months ended
March 31, 2017		  2017 change  Three months ended
March 31, 2016(1)
Sempra Energy Consolidated$(46)  $(376)  $330
SDG&E5
  28
  (23)
SoCalGas(62)  (67)  5
(1) Reflects the adoption of ASU 2016-09, as we discuss in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.

CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
 Three months ended Three months ended
 March 31, 20162016 changeMarch 31, 2015
Sempra Energy Consolidated$364$595 $(231)
SDG&E (23) (160)  137
SoCalGas 5 55  (50)

Sempra Energy Consolidated
At Sempra Energy, financing activities were a netuse of cash in 2017 compared to a source of cash in 2016, compared to a net use of cash in 2015, primarily due to:
§  
▪$53197 million increasedecrease in short-term debt in 20162017 compared to a $363$531 million decreaseincrease in 2015;2016; and
§  
▪$600259 million lowerhigher payments on debt including lower payments ofwith maturities greater than 90 days, including:
◦$167 million for long-term debt of $8 million ($22189 million in 20162017 compared to $30$22 million in 2015)2016), and lower payments of
◦
$92 million for commercial paper and other short-term debt with maturities greater than 90 days of $592 million ($32124 million in 20162017 compared to $624$32 million in 2015)2016); offset by
§  
▪$883487 million lowerhigher issuances of debt primarily from issuances ofwith maturities greater than 90 days, including:
◦$437 million for commercial paper and other short-term debt with maturities greater than 90 days ($492 million in 2017 compared to $55 million in 2016), and
◦$50 million for long-term debt in 2015.2017.
SDG&E
At SDG&E, financing activities were a netsource of cash in 2017 compared to a use of cash in 2016, compared to a net source of cash in 2015, primarily due to:
§  
▪
$343 million increase in short-term debt in 2017 compared to a $2 million decrease in 2016; offset by
▪$388175 million net proceeds from issuancescommon dividends paid in 2017; and
▪$140 million higher payments of long-term debt in 2015; and2017.
§  
$17 million higher payments on long-term debt in 2016; offset by
§  $2 million decrease in short-term debt in 2016 compared to a $246 million decrease in 2015.
SoCalGas
At SoCalGas, financing activities were a netuse of cash in 2017 compared to a source of cash in 2016 compareddue to a net use of cash$62 million decrease in 2015 dueshort-term debt in 2017 compared to a $5 million increase in short-term debt in 2016 compared to a $50 million decrease in 2015.

2016.
COMMITMENTS

We discuss significant changes to contractual commitments since December 31, 20152016 at Sempra Energy, SDG&E and SoCalGas in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.


CREDIT RATINGS

The credit ratings of Sempra Energy, SDG&E and SoCalGas remained at investment grade levels during the first three months of 2016.2017. Our credit ratings may affect the rates at which borrowings bear interest and ofthe commitment fees on available unused credit. We provide additional information about our credit ratings at Sempra Energy, SDG&E and SoCalGas in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Credit Ratings” in the Annual Report.


FACTORS INFLUENCING FUTURE PERFORMANCE


CALIFORNIA UTILITIES


Overview

The California Utilities’ operations have historically provided relatively stable earnings and liquidity.
The California Utilities’ performance will depend primarily on the ratemaking and regulatory process, environmental regulations, economic conditions, actions by the California legislature and the changing energy marketplace. Their performance will also depend on the successful completion of capital projectsWe discuss various factors that we discuss below andhave identified that could influence our future performance in various sections of this report and“Factors Influencing Future Performance” in the Annual Report. In addition, SoCalGas’ performance will dependWe discuss below significant, new developments to those factors that have occurred in 2017, as well as any new factors that we have identified in 2017. You should read the information below together with “Factors Influencing Future Performance” and “Risk Factors” contained in the Annual Report.
SDG&E
Potential Impacts of Community Choice Aggregation (CCA) and Direct Access (DA)
SDG&E provides electric services, including the commodity of electricity, to the majority of its customers (“bundled customers”).  SDG&E procures electricity, typically on the resolutiona long-term basis, on behalf of these bundled customers. However, SDG&E’s earnings are “decoupled” from electric sales volumes, one aspect of which is that commodity costs for electricity are directly passed through to bundled customers (see discussion in “Revenues – California Utilities” in Note 1 of the legal, regulatoryNotes to Consolidated Financial Statements in the Annual Report). SDG&E’s bundled customers have the option to purchase the commodity of electricity from alternate suppliers under defined programs, including CCA and other matters concerningDA. In such cases, California law (SB 350) prohibits remaining bundled customers from experiencing any cost increase as a result of electric commodity no longer being consumed by the natural gas leakdeparting customers. Existing rate mechanisms may not be sufficient to ensure that remaining bundled customers do not experience any cost increase as a result of

departing customers. SDG&E, Pacific Gas and Electric Company (PG&E) and Southern California Edison Company (Edison) filed a joint application with the CPUC in April 2017 to replace these existing mechanisms and ensure compliance with state law.
Currently, DA in SDG&E’s service area is limited by state law and is approximately 17 percent of SDG&E’s annual demand, and there are no CCA providers in SDG&E’s service area. However, several local political jurisdictions, including the city of San Diego and county of San Diego, 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. If mechanisms to ensure compliance with state law were not in place at Aliso Canyon. We discuss certain regulatory matters below andthe time of these potentially significant reductions in SDG&E’s served load, remaining bundled customers could experience potentially large changes in rates for their service. 

SONGS
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. In Notes 9 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein, and in Notes 13 14 and 15 of the Notes to Consolidated Financial Statements and in “Risk Factors” in the Annual Report, we discuss regulatory and other matters related to SONGS, including:
▪a reopened CPUC proceeding that is considering whether a SONGS-related amended settlement agreement approved in 2014 is reasonable and in the public interest;
▪matters concerning the ability to timely withdraw funds from trust accounts for the payment of decommissioning costs; and
▪the arbitration decision finding Mitsubishi Heavy Industries, Ltd., Mitsubishi Nuclear Energy Systems, Inc., and Mitsubishi Heavy Industries America, Inc. (collectively MHI) liable for breach of contract in connection with the replacement steam generators at the SONGS nuclear power plant, subject to a contractual limitation of liability, and awarding MHI 95 percent of its arbitration costs.
Wildfire Claims Cost Recovery
In September 2015, SDG&E filed an application with the CPUC requesting rate recovery of an estimated $379 million in costs related to the October 2007 wildfires that have been recorded to the Wildfire Expense Memorandum Account (WEMA), as we discuss in Note 11 of the Notes to Condensed Consolidated Financial Statements herein and Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.
In April 2016, the CPUC issued a ruling establishing the scope and schedule for the proceeding, which will be managed in two phases. Phase 1 addresses SDG&E’s operational and management prudence surrounding the 2007 wildfires, with a final CPUC decision expected by late 2017. Phase 2 will address whether SDG&E’s actions and decision-making in connection with settling legal claims in relation to the wildfires were reasonable, with a final CPUC decision expected by early 2019. In October 2016, intervening parties submitted Phase 1 testimony raising various concerns with SDG&E’s operations and management prior to and during the 2007 wildfires, and SDG&E responded to that testimony in December 2016. Participating parties asked that the CPUC reject SDG&E’s request for cost recovery.
Recovery of these costs in rates will require future regulatory approval. SDG&E will continue to assess the likelihood, amount and timing of such recoveries in rates. Should SDG&E conclude that recovery of excess wildfire costs in rates is no longer probable, at that time SDG&E would record a charge against earnings. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated, at March 31, 2017, the resulting after-tax charge against earnings would have been up to approximately $207 million. A failure to obtain substantial or full recovery of the requested amount of these costs from customers, or any negative assessment of the likelihood of recovery, would likely have a material adverse effect on SDG&E’s and Sempra Energy’s financial condition, cash flows and results of operations. We discuss the October 2007 wildfires and how we assess the probability of recovery of our regulatory assets in Notes 15 and 1, respectively, of the Notes to Consolidated Financial Statements in the Annual Report.
Other SDG&E Matters
See “Factors Influencing Future Performance” in the Annual Report for a discussion about:
▪Electric Rate Reform – California Assembly Bill 327
▪Distributed Energy Storage – California Assembly Bill 2868
▪Renewable Energy Procurement
▪Clean Energy and Pollution Reduction Act – California SB 350


SOCALGAS
Aliso Canyon Natural Gas Storage Facility Gas Leak
In October 2015, SoCalGas discovered a leak at one of its injection-and-withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility located in Los Angeles County, which SoCalGas has operated as a gas storage facility since 1972. SoCalGas worked closely with several of the world’s leading experts to stop the leak. On February 18, 2016, the California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources (DOGGR) confirmed that the well was permanently sealed.
Local Community Mitigation Efforts
Pursuant to a stipulation and order by the Los Angeles County Superior Court (Superior Court), SoCalGas provided temporary relocation support to residents in the nearby community who requested it before the well was permanently sealed. Following the permanent sealing of the well, the Los Angeles County Department of Public Health (DPH) conducted indoor testing of certain homes in the Porter Ranch community, and concluded that indoor conditions did not present a long-term health risk and that it was safe for residents to return home. In May 2016, the Superior Court ordered SoCalGas to offer to clean residents’ homes at SoCalGas’ expense as a condition to ending the relocation program. SoCalGas completed the residential cleaning program and the relocation program ended in July 2016.
Apart from the Superior Court order, 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 natural gas 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 total costs incurred to remediate and stop the leak and to mitigate local community impacts are significant and may increase, and we may be subject to civil or administrative fines, costs and other penalties, if awarded or imposed. To the extent any of these costs are 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.
Litigation
In connection with the natural gas leak at the Aliso Canyon storage facility, as of May 8, 2017, 266 lawsuits, including over 22,000 plaintiffs, are pending against SoCalGas, some of which have also named Sempra Energy. Derivative and securities claims have also been filed on behalf of Sempra Energy and/or SoCalGas or their shareholders against certain officers and directors of Sempra Energy and/or SoCalGas. We provide further detail on these cases, as well as on complaints filed by the California Attorney General, acting in an independent capacity and on behalf of the people of the State of California and the California Air Resources Board (CARB), together with the Los Angeles City Attorney; the South Coast Air Quality Management District (SCAQMD); and the County of Los Angeles, on behalf of itself and the people of the State of California; and on a misdemeanor criminal complaint filed by the Los Angeles County District Attorney’s Office; in Note 11 of the Notes to Condensed Consolidated Financial Statements herein. Additional litigation may be filed against us in the future related to the Aliso Canyon incident or our responses thereto.
The costs of defending against these civil and criminal lawsuits, cooperating with these investigations, and any damages, restitution, and civil, administrative and criminal fines, costs and other penalties, if awarded or imposed, as well as 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.
Governmental Investigations
Various governmental agencies have investigated or are investigating this incident.
▪
In January 2016, the Governor of the State of California issued an Order proclaiming a state of emergency to exist in Los Angeles County due to the natural gas leak at the Aliso Canyon facility. The Governor’s Order imposes various orders with respect to: stopping the leak; protecting public health and safety; ensuring accountability; and strengthening oversight. We provide further detail regarding the Governor’s Order and CARB’s Aliso Canyon Methane Leak Climate Impacts Mitigation Program, issued pursuant to the Governor’s Order, in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.
▪In January 2016, SoCalGas entered into a Stipulated Order for Abatement with the SCAQMD and agreed to take various actions in connection with injecting and withdrawing natural gas at Aliso Canyon, sealing the well, monitoring, reporting, safety and funding a health impact study, among other things. In February 2017, SoCalGas entered into a settlement agreement with the SCAQMD, and in March 2017, the Hearing Board terminated the Abatement Order. We provide further detail regarding the SCAQMD stipulated Abatement Order in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.


▪In January 2016, DOGGR and the CPUC selected Blade Energy Partners (Blade) to conduct an independent analysis under the direction and supervision of DOGGR and the CPUC to be funded by SoCalGas to investigate the technical root cause of the Aliso Canyon natural gas leak. The timing of the root cause analysis is under the control of Blade, DOGGR and the CPUC.
▪In February 2017, the CPUC opened a proceeding to determine the feasibility of minimizing or eliminating use of the Aliso Canyon natural gas storage facility, while still maintaining energy and electric reliability for the region, as we discuss below in “SB 380.”
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. Aliso Canyon, 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. SoCalGas has not injected natural gas into Aliso Canyon since October 25, 2015, pursuant to orders by DOGGR and the Governor, and in accordance with SB 380. Limited withdrawals of natural gas from Aliso Canyon have been made in 2017 to augment natural gas supplies during critical demand periods.
If the Aliso Canyon facility were to be taken out of service for any meaningful period of time, it could result in an impairment of the facility and significantly higher than expected operating costs and/or additional capital expenditures, and natural gas reliability and electric generation could be jeopardized. At March 31, 2017, the Aliso Canyon facility has a net book value of $550 million, including $225 million of construction work in progress for the project to construct a new compression 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.
Regulatory Proceedings
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 facility or any portion of that facility has been out of service for nine consecutive months, SoCalGas provided notification for transparency, and because the process for obtaining authorization to resume injection operations at the facility is taking longer to complete than initially contemplated. In response, and as required by Section 455.5, the CPUC issued a draft Order Instituting Investigation to address whether the Aliso Canyon facility or any portion of that facility has been out of service for nine consecutive months pursuant to Section 455.5, and if it is determined to have been out of service, whether the CPUC should adjust SoCalGas’ rates to reflect the period the facility is deemed to have been out of service. If the CPUC adopts the order as drafted and as required under Section 455.5, hearings on the investigation will be consolidated with SoCalGas’ next GRC proceeding. In the event that the CPUC determines that all or any portion of the facility has been 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 and results of operations.
In March 2016, the CPUC ordered SoCalGas to establish a memorandum account to prospectively track its authorized revenue requirement and all revenues that it receives for its normal, business-as-usual costs to own and operate the Aliso Canyon natural gas storage field and, in September 2016, approved SoCalGas’ request to begin tracking these revenues as of March 17, 2016. The CPUC will determine at a later time whether, and to what extent, the authorized revenues tracked in the memorandum account may be refunded to ratepayers.
Insurance
Excluding directors and officers liability insurance, we have four kinds of insurance policies that together provide between $1.2 billion to $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 have been communicating with our insurance carriers and intend to pursue the full extent of our insurance coverage. Through March 31, 2017, we have received $173 million of insurance proceeds for a portion of control-of-well expenses and for a portion of temporary relocation costs. There can be no assurance that we will be successful in obtaining insurance coverage for costs related to the leak under the applicable policies, and to the extent we are not successful in obtaining coverage, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.
Our recorded estimate as of March 31, 2017 of $799 million of certain costs in connection with the Aliso Canyon storage facility leak may rise significantly as more information becomes available, and any costs not included in the $799 million estimate could be material. 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 Sempra Energy’s and SoCalGas’ cash flows, financial condition and results of operations.



Regulation
Joint Matters

CPUC General Rate Case (GRC)
The Pipeline and Hazardous Materials Safety Administration (PHMSA), DOGGR, SCAQMD, U.S. Environmental Protection Agency and CARB have each commenced separate rulemaking proceedings to adopt further regulations covering natural gas storage facilities and injection wells. As we discuss in “Factors Influencing Future Performance” in the Annual Report, DOGGR 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, have been or may be scheduled, additional legislation has been proposed in the California Legislature, and additional laws, orders, rules and regulations may be adopted. The Los Angeles County Board of Supervisors formed a task force to review and potentially implement new, more stringent land use (zoning) requirements and associated regulations and enforcement protocols for oil and gas activities, including natural gas storage field operations, which could materially affect new or modified uses of the Aliso Canyon and other natural gas storage fields located in the County.
We discuss these matters further in Note 1011 of the Notes to Condensed Consolidated Financial Statements herein and in Note 15 of the Notes to Consolidated Financial Statements, “Factors Influencing Future Performance” and “Risk Factors” in the Annual Report.
PIPES Act of 2016
In June 2016, the “Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016” or the “PIPES Act of 2016” was enacted. Among other things, the PIPES Act of 2016:
▪requires PHMSA to issue, within two years of passage, “minimum safety standards for underground natural gas storage facilities;”
▪imposes a “user fee” on underground storage facilities as needed to implement the safety standards;
▪
grants PHMSA authority to issue emergency orders and impose emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for hearing, if the Secretary of Energy determines that an unsafe condition or practice, or a combination of unsafe conditions and practices, constitutes or is causing an imminent hazard; and
▪directs the Secretary of Energy to establish an Interagency Task Force comprised of representatives from various federal agencies and representatives of state and local governments.
In December 2016, PHMSA published an interim final rule pursuant to the PIPES Act of 2016 that revises the federal pipeline safety regulations relating to underground natural gas storage facilities. The interim final rule incorporates consensus safety measures for the construction, maintenance, risk-management, and integrity-management procedures for natural gas storage. SoCalGas began the process of implementing such safety measures prior to formal adoption by PHMSA and is developing the associated documents and procedures required to demonstrate compliance with the standards.
SB 380
In May 2016, SB 380 became law and requires, among other things:
▪the continued prohibition against SoCalGas injecting any natural gas into the Aliso Canyon facility until a comprehensive review of the safety of the gas storage wells at the facility is completed in accordance with regulations adopted by DOGGR, the State Oil & Gas Supervisor has made a safety determination and other required findings, at least one public hearing has been held in the affected community, and the Executive Director of the CPUC has issued a concurring letter regarding the Supervisor’s determination of safety;
▪that all gas storage wells returning to service at the Aliso Canyon storage field inject or produce gas only through the interior metal tubing and not through the annulus between the tubing and the well casing, which allows SoCalGas wells to operate with two complete barriers to mitigate the potential for an uncontrolled release of natural gas; and
▪a CPUC proceeding (which was opened in February 2017) to determine the feasibility of minimizing or eliminating use of the Aliso Canyon natural gas storage facility, while still maintaining energy and electric reliability for the region, and to consult with various governmental agencies and other entities in making its determination. The scope of the proceeding does not include issues with respect to air quality, public health, causation, culpability, or cost responsibility regarding the Aliso Canyon natural gas leak.
SB 888
In September 2016, SB 888 became law, which requires that a penalty assessed against a gas corporation by the CPUC with regard to a natural gas storage facility leak must at least equal the amount necessary to fully offset the impact on the climate from the greenhouse gases emitted by the leak, as determined by CARB. The CPUC also must consider the extent to which the gas corporation has mitigated or is in the process of mitigating the impact on the climate from greenhouse gas emissions resulting from the leak.
Proposed Legislation – SB 57
SB 57 would extend the moratorium on natural gas injections at the Aliso Canyon storage facility until the root cause analysis of the leak that started in October 2015 has been completed. It would also require the CPUC to “act in a manner that will maximize


transparency” in the course of completing its analysis regarding the feasibility of minimizing or eliminating the use of the Aliso Canyon storage facility. In addition, the bill would enable the Governor to authorize reinjection, production and withdrawal at Aliso Canyon as necessary to respond to or avoid emergencies. The bill continues to be debated in the California Utilities filed settlement agreements withSenate.
Additional Safety Enhancements
In February 2017, SoCalGas notified the CPUC that resolve all material matters related to their 2016 GRC proceeding, except forit is accelerating its well integrity assessments on the revenue requirement implications of certain income tax benefits associated with flow-through repair allowance tax deductions, discussed below. The California Utilities also filed a separate agreement, reachednatural gas storage wells at its La Goleta, Honor Rancho and Playa del Rey natural gas storage fields consistent with the testing prescribed by SB 380 for Aliso Canyon, proposed new DOGGR regulations, and SoCalGas’ Storage Risk Management Plan. In addition, SoCalGas indicated its plan to reconfigure its operating natural gas storage wells such that natural gas will be injected or produced only through the interior metal tubing and not through the annulus between the tubing and the well casing to maintain a double barrier and additional layer of safety, which is consistent with the direction of federal and state regulations. SoCalGas anticipates that this work will reduce the injection and withdrawal capacity of each of these other storage fields. Depending on the volume of natural gas in storage in each field at the time natural gas is injected or withdrawn, the reduction could be significant and could impact natural gas reliability and electric generation. In March 2017, SoCalGas revised its plan, as directed by the CPUC, Officefor converting all wells to tubing-only operation to maintain a prescribed withdrawal capacity.
Higher operating costs and additional capital expenditures incurred by SoCalGas as a result of Ratepayer Advocates (ORA), proposing thatnew laws, orders, rules and regulations arising out of the Aliso Canyon incident or our responses thereto could be significant and may not be recoverable 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.
SoCalGas Billing Practices
The CPUC issued an Order Instituting Investigation (OII) on May 4, 2017 as a fourth year (2019) be addedresult of a closed CPUC meeting session held on April 27, 2017 to determine whether SoCalGas violated any provisions of the Public Utilities Code, General Orders, CPUC decisions, or other requirements pertaining to billing practices from 2014 through 2016. In particular, the CPUC is examining the timeliness of monthly bills, extending the billing period for customers, and issuing estimated bills. The OII will also examine SoCalGas’ gas tariff rules and whether to impose penalties or other remedies. Responses to the GRC period, withOII and its preliminary scope are due in early June 2017, and a revenue requirement increase of 4.3 percent over 2018. On April 29, 2016,prehearing conference to determine the CPUC issued a proposed decision in a separate proceeding denyingscope and schedule will be scheduled by the potential of four-year GRC cycles citing that an extension to the GRC period would delay the implementation of the risk-based decision making framework.Administrative Law Judge.
The settlement agreements noted above exclude a proposal, for both SoCalGas and SDG&E, regarding certain intra-rate case income tax benefits. The proposal recommends that the CPUC adjust SoCalGas’ rate base by $92 million and SDG&E’s rate base by $93 million, and additionally reduce both utilities’ revenue requirements by amounts tracked in tax memorandum accounts for the year 2015, which total $74 million for SoCalGas and $39 million for SDG&E. We believe the proposed treatment would violate and contradict long standing rate making and income tax policy, and would represent a material departure from historical practice. If this proposal is adopted, the outcome would reduce the revenue requirement amounts agreed to in the respective settlement agreements noted above. SDG&E and SoCalGas do not expect that the prospective reduction to rate base described above would result in an immediate earnings impact if this proposal is adopted. However, if this proposal is adopted, SDG&E and SoCalGas may record a material charge against earnings for the amounts in the tax memorandum accounts when the proposed decision is received.CALIFORNIA UTILITIES – JOINT MATTERS
We anticipate all matters to be resolved in the CPUC’s final decision on the 2016 GRC proceeding. We expect the CPUC to issue a final decision in the proceeding in the second quarter of 2016.


Natural Gas Pipeline Operations Safety Assessments
Pending the outcome of the 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. In August 2011, the California Utilities filed implementation plans with the CPUC to implement the CPUC’s significant and urgent safety directive to test or replace natural gas transmission pipelines located in populated areas that have not been pressure tested as we discussand to reduce the time for valves to stop the flow of gas if a break in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report. The California Utilities’ total estimated cost for Phase 1 (the 10-year period of 2012 to 2022) of a two-phase plan was $2.1 billion ($1.6 billion for SoCalGas and $500 million for SDG&E)pipeline occurs (Pipeline Safety Enhancement Plan or PSEP). We anticipate that these cost estimates may be updated to reflect the development of more detailed estimates, actual cost experience as portions of the work are completed and changes in scope. The California Utilities requested that the incremental capital investment required as a result of any approved plan be included in rate base and that cost recovery be allowed for any other incremental cost not eligible for rate-base recovery. The costs that are the subject of these plans were outside the scope of the 2012 GRC proceedings concluded in 2013. Similarly, these costs are not included in our 2016 GRC filings.
In June 2014, the CPUC issued a final decision addressing SDG&E’s and SoCalGas’ Pipeline Safety Enhancement Plan (PSEP) that approvedapproving the utilities’ model for implementing PSEP, and established the 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. AsIn 2016, the CPUC issued a resultfinal decision authorizing SoCalGas and SDG&E to recover, subject to refund pending reasonableness review, 50 percent of thisthe revenue requirements associated with completed Phase 1 projects. The decision SoCalGas recorded an after-tax earnings charge of $5 million in 2014also incorporates a forward looking schedule to (1) file two reasonableness review applications for Phase 1 projects completed through 2017, (2) file one forecast application for Phase 2 project costs to be incurred in prior periods that were no longer subject to recovery. After taking the amounts disallowed for recovery into consideration, as of March 31, 2016, SDG&E2017 and SoCalGas have recorded2018, and (3) include all other PSEP costs in future GRCs.
In September 2016, SoCalGas and SDG&E filed a joint application with the CPUC for its second PSEP reasonableness review and rate recovery of $12costs of certain pipeline safety projects completed by June 30, 2015 and recorded in their authorized regulatory accounts. The total costs submitted for review are $195 million ($180 million for SoCalGas and $177$15 million respectively,for SDG&E). SoCalGas and SDG&E expect a decision from the CPUC in 2018. This proceeding has been challenged by consumer advocacy groups. However, we believe these costs were prudent, were incurred in accordance with the CPUC-authorized regulatory account.
program, and should be substantially approved for recovery.
In October 2014,March 2017, SoCalGas and SDG&E and SoCalGas filed a petition for modificationan application with the CPUC requesting authorityapproval of the forecasted revenue requirement necessary to recover PSEPthe costs from customers as incurred, subjectassociated with twelve Phase 1B and Phase 2A pipeline safety projects. The California Utilities expect to refund pendingincur total costs for the resultstwelve projects of approximately $255 million ($198 million in capital and $57 million in O&M) to be effective in rates on January 1, 2019. SoCalGas and SDG&E expect a reasonableness review by the CPUC instead ofdecision in 2018.
As shown in the subsequent year. This request is pending at the CPUC.table below, SoCalGas and SDG&E have made significant pipeline safety investments under this program, and SoCalGas have filedexpects to continue making significant investments as approved through various regulatory proceedings. SDG&E’s PSEP


program is expected to be substantially complete in 2017, with the CPUC for recovery of certain PSEP costs incurred through June 11, 2014 of $0.1 million and $26.8 million, respectively. The ORA, The Utility Reform Network (TURN), and the Southern California Generation Coalition (SCGC) have recommended disallowances of certain of these costs. We expect a decision on this application in the first half of 2016.
In July 2014, the ORA and TURN filed a joint application for rehearingexception of the CPUC’s June 2014 final decision. InPipeline Safety & Reliability Project that is currently under regulatory review.
PIPELINE SAFETY ENHANCEMENT PLAN – REASONABLENESS REVIEW SUMMARY
  
(Dollars in millions)  
 2011 through March 31, 2017
 
Total
 invested(1)
 
CPUC review
completed(2)
 
CPUC review
pending(3)
 2018 recovery filing(4)(5)
Sempra Energy Consolidated:��      
Capital$1,282
 $8
 $142
 $1,132
Operation and maintenance179
 25
 62
 92
Total$1,461
 $33
 $204
 $1,224
SoCalGas:       
Capital$977
 $8
 $128
 $841
Operation and maintenance170
 25
 61
 84
Total$1,147
 $33
 $189
 $925
SDG&E:       
Capital$305
 $—
 $14
 $291
Operation and maintenance9
 —
 1
 8
Total$314
 $—
 $15
 $299
(1) Excludes disallowed costs through March 2015, the CPUC issued a decision denying the ORA’s31, 2017 of $6 million at SoCalGas and TURN’s second request$1 million at SDG&E for rehearing, but keeping the record open to admit additional evidence on the limited issue of pressure testing or replacing pipelines installed between January 1, 1956 and July 1, 1961. The ORA and TURN allege that the CPUC made a legal error
(2) Approved in directing that ratepayers, not shareholders, be responsible for theDecember 2016; excludes $2 million of PSEP-specific insurance costs associated with testing or replacing transmission pipelines that were installed between January 1, 1956 and July 1, 1961 for which the California Utilities do not have a record of a pressure test. In December 2015, the CPUC issued a final decision finding that ratepayers should not bear the costs associated with pressure testing subject pipelines, or, if replaced, ratepayers should bear neither the average cost of pressure testing nor the undepreciated balance of abandoned pipelines. Through March 31, 2016, the after-tax disallowed costs for SoCalGas and SDG&E are $2.6 million and $0.5 million, respectively. In January 2016, SoCalGas and SDG&E jointly filed a request with the CPUC seeking rehearing of its December 2015 decision. A CPUC decision on the rehearing request is expected in 2016.
We provide additional information regarding these rulemaking proceedings and the California Utilities’ PSEP in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report and in Note 10 of the Notes to Condensed Consolidated Financial Statements herein.
Safety Enforcement
California Senate Bill (SB) 291 requires the CPUC to develop and implement a safety enforcement program that includes procedures for monitoring, data tracking and analysis, and investigations, as well as delegating citation authority to CPUC staff personnel under the direction of the CPUC Executive Director. In exercising the citation authority, the CPUC staff will 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 also has implemented both electric and gas safety enforcement programs whereby electric and gas utilitiesrecovery may be cited by CPUC staff for violationsrequested in a future filing.
(3) Reasonableness Review Application filed in September 2016. Also includes approximately $9 million of the CPUC’s safety requirements or 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. Citations under either program may be appealed to the CPUC. The CPUC plans to make further refinements to the electric and gas safety enforcement programs.
SDG&E Matters

2007 Wildfire Litigation
In regard to the 2007 wildfire litigation, SDG&E’s payments for claims settlements plus funds estimated to be required for settlement of outstanding claims and legal fees have exceeded its liability insurance coverage and amounts recovered from third parties. However, SDG&E has concluded that it is probable that it will be permitted to recover in rates a substantial portion of the reasonably incurred costs of resolving wildfire claims in excess of its liability insurance coverage and amounts recovered from third parties. Consequently, Sempra Energy and SDG&E expect no significant earnings impact from the resolution of the remaining wildfire claims. At March 31, 2016, Sempra Energy’s and SDG&E’s Condensed Consolidated Balance Sheets include assets of $363 million in Other Regulatory Assets (long-term), of which $360 million is related to CPUC-regulated operations and $3 million is related to FERC-regulated operations, forpre-engineering costs incurred and submitted in the estimated resolution of pending claims. In September 2015, SDG&EForecast Application filed an application with the CPUC requesting rate recoveryin March 2017. Both decisions expected in 2018.
(4) Reasonableness Review Application to be filed in late 2018 and expected to include substantially all of these costs, as we discuss in Note 10 of the Notes to Condensed Consolidated Financial Statements herein. SDG&E requested a CPUC decision by the end of 2016 and is proposing to recover the costs in rates over a six- to ten-year period. In April 2016, a ruling was issued establishing the scope and schedule for the proceeding, which will be managed in two phases. Phase 1 will address SDG&E’s operational and management prudence surrounding the 2007 wildfires. Phase 2 will address whether SDG&E’s actions and decision-making in connection with settling legal claims in relation to the wildfires were reasonable. Evidentiary hearings in Phase 1 are scheduled to be held in January 2017, with a final decision scheduled to be issued in the second half of 2017. The procedural schedule for Phase 2 will be determined after Phase 1 is concluded.
Recovery of these costs in rates will require future regulatory approval. SDG&E will continue to assess the likelihood, amount and timing of such recoveries in rates. Should SDG&E conclude that recovery of excess wildfire costs in rates is no longer probable, at that time SDG&E would record a charge against earnings. If SDG&E had concluded that the recovery of regulatory assets related to CPUC-regulated operations was no longer probable or was less than currently estimated, at March 31, 2016, the resulting after-tax charge against earnings would have been up to approximately $213 million. A failure to obtain substantial or full recovery of these costs from customers, or any negative assessment of the likelihood of recovery, would likely have a material adverse effect on Sempra Energy’s and SDG&E’s financial condition, cash flows and results of operations. We discuss how we assess the probability of recovery of our regulatory assets in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report.
We provide additional information concerning these matters in Notes 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report.
SONGS
We discuss regulatory and other matters related to SONGS in Notes 9 and 11 of the Notes to Condensed Consolidated Financial Statements herein, in Notes 13 and 15 of the Notes to Consolidated Financial Statements in the Annual Report, and in “Risk Factors” in the Annual Report.

Investment in Wind Farm
In 2011, the CPUC and FERC approved SDG&E’s estimated $285 million tax equity investment in the Rim Rock wind farm project. SDG&E and the project developer were in dispute regarding whether all conditions precedent in the contribution agreement had been achieved by the developer of the project. As a result, SDG&E had not made the investment. On February 11, 2016, SDG&E, the project developer and several of the project developer’s parent and affiliated entities entered into a conditional settlement agreement. Under the conditional settlement agreement, among other things, the parties agreed to terminate the tax equity investment arrangement, continue the power purchase agreement for the wind farm generation, and release all claims against each other. The conditional settlement agreement will not result in rate increases to SDG&E customers or a material impact on Sempra Energy’s or SDG&E’s financial condition, results of operations or cash flows. On February 16, 2016, SDG&E and the project developer filed a petition for approval of the settlement agreement with the CPUC. The conditional settlement agreement is not fully effective until approved by the CPUC; SDG&E expects a decision in 2016. We discuss this matter further in Note 11 of the Notes to Condensed Consolidated Financial Statements herein and in Note 15 of the Notes to Consolidated Financial Statements in the Annual Report.
Electric Rate Reform – State of California Assembly Bill 327
In October 2013, the Governor of California signed Assembly Bill (AB) 327. This bill became law on January 1, 2014. This law restores the authority to establish electric residential rates for electric utility companies in California to the CPUC and removes the rate caps established in AB 1X adopted in early 2001 during California’s energy crisis, as well as SB 695 adopted in 2009. Additionally, the bill provides the CPUC the authority to adopt up to a $10.00 monthly fixed charge for all non-CARE (California Alternate Rates for Energy) residential customers and up to a $5.00 monthly fixed charge for CARE customers. Beginning January 1, 2016, the maximum allowable fixed charge may be adjusted by no more than the annual percentage increase in the Consumer Price Index for the prior calendar year. 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 directs changes beginning in summer 2015 and provides a path for continued reforms through 2020, including a minimum monthly bill of $10 ($5 for CARE customers). The changes also include fewer rate tiers and a gradual reduction in the difference between the tiered rates, similar to the tier differential that existed prior to the 2000-2001 Energy Crisis. The number of tiers was reduced from four to three in 2015 and will be reduced to two in 2016. The rate differential between the highest and lowest tiers was reduced from approximately 2.4 times to 2.18 times in 2015, and will reduce to 1.25 times by as early as 2019. The decision also directs the utilities to pursue expanded time of use rates and implements a super user electric (SUE) surcharge in 2017 for usage that exceeds average customer usage by approximately 400 percent. The decision still allows the utilities to seek a fixed charge, but sets certain conditions for its implementation, which would be no sooner than 2020. The changes implemented should result in significant rate relief for higher-use SDG&E customers who do not exceed the SUE threshold and will result in a rate structure that better aligns rates with the actual cost to serve customers.
In July 2014, the CPUC initiated a rulemaking proceeding to develop a successor tariff to the state’s existing net energy metering (NEM) program pursuant to the provisions of AB 327, which required the CPUC to establish a revised NEM tariff or similar program by December 31, 2015. The NEM program is an electric billing tariff mechanism designed to promote the installation of on-site renewable generation. It was originally established in California in 1995 with the adoption of SB 656, as codified in Section 2827 of the Public Utilities Code. Currently, customers who install and operate eligible renewable generation facilities of one megawatt or less may choose to participate in the NEM program. Under NEM, 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 their annual consumption, they receive compensation at a rate equal to a wholesale energy price.
In August 2015, SDG&E proposed a successor NEM tariff that is intended to ensure that all NEM customers pay for the grid and other services they receive, supports the continued growth and adoption of distributed energy resources and helps California meet its energy policy goals. In January 2016, SDG&E, Pacific Gas and Electric Company (PG&E) and Southern California Edison Company (Edison) filed a joint recommendation to continue the pursuit of a fair and equitable rate structure for all customers. Subsequently in January 2016, the CPUC adopted a final decision in the case that makes modest changes now to require NEM customers to pay some costs that would otherwise be borne by non-NEM customers and moves new NEM customers to time-of-use rates. Together with a reduction in tiered rate differentials and the potential implementation of a fixed charge discussed under electric rate reform, the NEM successor tariff begins a process of reducing the cost burden on non-NEM customers. In March 2016, SDG&E, Edison, PG&E, TURN and the California Coalition of Utility Employees filed applications with the CPUC requesting rehearing of its January 2016 decision. A CPUC decision on the rehearing requests is expected in 2016.
Appropriate NEM reform is necessary to 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 2019 when more significant reforms are to take effect, 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. For additional discussion, see “Risk Factors” in the Annual Report.
California Senate Bill 350
SB 350, signed into law in October 2015, creates new requirements for the utilities in the areas of renewable procurements, energy efficiency, resource planning, and electric vehicle (EV) infrastructure. Specifically, the state mandated renewable portfolio standard will be raised to 50 percent by 2030 and 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. SB 350 also clearly specifies that the utilities will be asked to file applications with the CPUC that highlight how they can help with the development and expansion of the electric charging infrastructure necessary to support the growth of the EV market expected due to the state’s alternative fuel vehicle policy initiative. SB 350 also enhances focus on improving efficiency in older buildings. We expect to meet the higher renewable portfolio standard and greenhouse gas emissions reductions requirement and are supportive of greater infrastructure development to support electric vehicle charging. Our Electric Vehicle Charging Program, which we discuss in Note 14 of the Notes to Consolidated Financial Statements in the Annual Report, does not include potential additional opportunities associated with SB 350.
SoCalGas Matters
Aliso Canyon Natural Gas Storage Facility Gas Leak
In October 2015, SoCalGas discovered a leak at one of its injection and withdrawal wells, SS25, at its Aliso Canyon natural gas storage facility, located in Los Angeles County, which has been operated by SoCalGas since 1972. SoCalGas worked closely with several of the world's leading experts to stop the leak, including planning and obtaining all necessary approvals for drilling relief wells. On February 18, 2016, the California Department of Conservation’s Division of Oil, Gas, and Geothermal Resources (DOGGR) confirmed that the well was permanently sealed.
Pursuant to a stipulation and court order and in response to claims made pursuant to lawsuits described below, SoCalGas provided temporary relocation support to residents in the nearby community who requested it before the well was permanently sealed. In connection with the temporary relocation support, on April 27, 2016, the California Superior Court (Superior Court) ordered an extension of the relocation support term pending the completion of the County of Los Angeles’ (County) indoor testing. The County has reported that it anticipates completing its analysis and releasing a final report by late May 2016. The next scheduled Superior Court hearing on this matter is June 7, 2016. While the temporary relocation support period could end before June 7, 2016, due to the fact that the temporary relocation support has been extended several times, there can be no assurance that future extensions will not be granted. The cost of the temporary relocation support is significant, and the costs of any further extensions of the relocation support term, which are not included in our estimate of costs related to the leak, could result in a material increase in our cost estimate.
The total costs incurred to remediate and stop the leak and to mitigate local community impacts will be significant, and to the extent not covered by insurance, 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.
Various governmental agencies including the DOGGR, Los Angeles County Department of Public Health, SCAQMD, CARB, California Division of Occupational Safety and Health (DOSH), CPUC, Pipeline and Hazardous Materials Safety Administration (PHMSA), U.S. Environmental Protection Agency (EPA), Los Angeles District Attorney’s Office, and California Attorney General’s Office, are investigating this incident.
As of April 28, 2016, 138 lawsuits have been filed (134 in Los Angeles County Superior Court, 2 in San Diego County Superior Court, and 2 in the United States District Court for the Southern District of California) against SoCalGas, some of which have also named Sempra Energy, and, in derivative and securities law claims on behalf of Sempra Energy and/or SoCalGas, certain officers and directors of Sempra Energy and/or SoCalGas. These various lawsuits assert causes of action for negligence, strict liability, property damage, fraud, nuisance, trespass, breach of fiduciary duties and violation of federal securities laws, among other things, and additional litigation may be filed against us in the future related to this incident. Many of these complaints seek class action status, compensatory and punitive damages, injunctive relief and attorneys’ fees. The Los Angeles City Attorney and Los Angeles County Counsel have also filed a complaint on behalf of the people of the State of California against SoCalGas for public nuisance and violation of the California Unfair Competition Law. The California Attorney General, acting in her independent capacity and on behalf of the people of the State of California and the CARB, joined this lawsuit. The complaint, which as amended includes the California Attorney General, adds allegations of violations of California Health and Safety Code sections 41700, prohibiting discharge of air contaminants that cause annoyance to the public, and 25510, requiring reporting of the release of hazardous material, as well as California Government Code section 12607 for equitable relief for the protection of natural resources. The complaint seeks an order for injunctive relief, to abate the public nuisance, and to impose civil penalties. The SCAQMD also filed a complaint against SoCalGas seeking civil penalties for alleged violations of several nuisance-related statutory provisions arising from the leak and delays in stopping the leak. That suit seeks up to $250,000 in civil penalties for each day the violations occurred.
On February 2, 2016, the Los Angeles District Attorney’s Office filed a misdemeanor criminal complaint against SoCalGas seeking penalties and other remedies for alleged failure to provide timely notice of the leak pursuant to California Health and Safety Code section 25510(a), Los Angeles County Code section 12.56.030, and Title 19 California Code of Regulations section 2703(a), and for violating California Health and Safety Code section 41700 prohibiting discharge of air contaminants that cause annoyance to the public.
The costs of defending against these civil and criminal lawsuits and cooperating with these investigations, and any damages, restitution, and civil and criminal fines, costs and other penalties, if awarded or imposed, could be significant and to the extent not covered by insurance, or if there were to be significant delays in receiving insurance recoveries, could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.
On January 6, 2016, the Governor of the State of California issued the Governor’s Order proclaiming a state of emergency to exist in Los Angeles County due to the natural gas leak at the Aliso Canyon facility. The Governor’s Order implements various orders with respect to:
§  stopping the leak;
§  protecting public health and safety;
§  ensuring accountability; and
§  strengthening oversight.
We provide further detail regarding the Governor’s Order and CARB’s Aliso Canyon Methane Leak Climate Impacts Mitigation Program, issued pursuant to the Governor’s Order, in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.
On January 23, 2016, the Hearing Board of the SCAQMD ordered SoCalGas to, among other things, stop the leak, control the release of natural gas into the air, and conduct air monitoring and public health studies. We provide further detail regarding the SCAQMD’s order in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.
On January 25, 2016, the DOGGR and CPUC selected Blade Energy Partners to conduct an independent analysis under their supervision and to be funded by SoCalGas to investigate the technical root cause of the Aliso Canyon leak. We expect the root cause analysis to be completed in late 2016 or early 2017, but the timing is dependent on the DOGGR and the CPUC. In addition, effective February 5, 2016, the DOGGR amended the California Code of Regulations to require all underground natural gas storage facility operators, including SoCalGas, to take further steps to help ensure the safety of their gas storage operations.
On April 1, 2016, the Secretary of the U.S. Department of Energy (DOE) and PHMSA jointly announced the formation of an Interagency Task Force on Natural Gas Storage Safety in response to the leak at Aliso Canyon to assess and make recommendations on best practices, response plans and safe operation of gas storage facilities. PHMSA has indicated plans to initiate additional regulatory actions on natural gas storage nationally. Each of the DOGGR, SCAQMD, EPA and CARB has commenced separate rulemaking proceedings to adopt further regulations covering natural gas storage facilities and injection wells. The U.S. Senate also passed two pieces of legislation, which include a provision requiring the establishment of an Aliso Canyon Task Force. This generally mirrors the focus and structure of the Task Force on Natural Gas Storage Safety. The legislation requires the Task Force to examine a specific set of issues related to the leak, including impacts on health and electricity prices.
Additional hearings in the state legislature, as well as with various other federal and state regulatory agencies, have been or are expected to be scheduled, additional legislation has been proposed in the state legislature, 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 could be significant and to the extent not covered by insurance or in customer rates, such costs could have a material adverse effect on SoCalGas’ and Sempra Energy’s cash flows, financial condition and results of operations.
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. Aliso Canyon, with a storage capacity of 86 billion cubic feet (Bcf), is the largest storage facility and an important element of SoCalGas’ delivery system. Aliso Canyon represents 63 percent of SoCalGas’ owned natural gas storage capacity. SoCalGas has not injected natural gas into Aliso Canyon since October 25, 2015, in accordance with the Governor’s Order and subject to contrary CPUC reliability-based direction. On March 4, 2016, the DOGGR issued Order 1109, Order to Take Specific Actions Regarding Aliso Canyon Gas Storage Facility (Safety Review Testing Regime). On April 7, 2016, SoCalGas announced its safety framework to comply with the DOGGR Order 1109, which consists of phased testing for each of the active injection wells in the Aliso Canyon storage facility. SoCalGas will continue this moratorium on further injections until the completion of this review and any necessary approvals have been obtained.
If the Aliso Canyon 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 March 31, 2016, the Aliso Canyon facility has a net book value of $415 million, including $180 million of construction work in progress for the project to construct a new compression 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.
On March 17, 2016, the CPUC issued a decision directing SoCalGas to establish a memorandum account to prospectively track its authorized revenue requirement and all revenues that it receives for its normal, business-as-usual costs to own and operate the Aliso Canyon gas storage field. The CPUC will determine at a later time whether, and to what extent, the tracked revenues may be refunded to ratepayers. Pursuant to the CPUC’s decision, on March 24, 2016, SoCalGas filed an advice letter requesting to establish a memorandum account to track all business-as-usual costs to own and operate the Aliso Canyon storage field, which has been protested by TURN and SCGC. On April 22, 2016, the CPUC’s Energy Division issued a suspension notice for SoCalGas’ advice letter citing the need for additional time for staff review. This suspension period could last up to 120 days.
We have at least four kinds of insurance policies that provide in excess of $1 billion in insurance coverage. We have been communicating with our insurance carriers and intend to pursue the full extent of our insurance coverage. These policies are subject to various policy limits, exclusions and conditions. There can be no assurance that we will be successful in obtaining insurance coverage for costs related to the leak under the applicable policies, and to the extent we are not successful, it could result in a material charge against the earnings of SoCalGas and Sempra Energy.
Our estimate at March 31, 2016 of $665 million of certain costs in connection with the Aliso Canyon storage facility leak may rise significantly as more information becomes available, and to the extent not covered by insurance, or if there were to be significant delays in receiving insurance recoveries, such costs could have a material adverse effect on Sempra Energy’s and SoCalGas’ cash flows, financial condition and results of operations. In addition, thecosts. Remaining costs not included in the $665 million estimate could2018 application are expected to be material,filed in a future GRC.
(5) Authorized to recover 50 percent of the revenue requirement when the projects are completed, subject to refund.
Regulatory Compliance and Safety Enforcement
In October 2016, SoCalGas was fined $699,500 for alleged violations of certain environmental mitigation measures related to the Aliso Canyon Turbine Replacement Project. SoCalGas appealed the citation and, in March 2017, SoCalGas and the CPUC’s Consumer Protection and Enforcement Division filed a joint settlement agreement with the CPUC, resolving all matters related to the October 2016 citation. In the settlement, SoCalGas agrees to pay $250,000 to the state’s general fund and to retain an independent firm to conduct two compliance training seminars at a cost not to exceed $25,000. In April 2017, the extent not covered by insurance, could haveCPUC issued a material adverse effect on Sempra Energy’sdraft decision approving the settlement as filed. We expect a final resolution in the second quarter of 2017.
Other California Utilities – Joint Matters
For a discussion about the “Cost of Capital Update” and SoCalGas’ cash flows, financial condition and results of operations.
We discuss this matter further in Note 11 of the Notes to Condensed Consolidated Financial Statements herein and “Risk Factors”“Future Risk-Based GRC,” see “Factors Influencing Future Performance” in the Annual Report.
SEMPRA SOUTH AMERICAN UTILITIES
Industry DevelopmentsChilquinta Energía’s most recent review process for distribution rates was completed in November 2016, covering the period from November 2016 through October 2020. We expect a final decree to be released during the second quarter of 2017 and Capital Projectsto be retroactive from November 2016, which we do not expect to have a material impact on our results.
Other Sempra South American Utilities Matters
We describe capital projects, electric and natural gas regulation and rates, andFor a discussion about other pending proceedings and investigations that affect the CaliforniaSempra South American Utilities in Note 10 of the Notes to Condensed Consolidated Financial Statements herein and in Note 14 of the Notes to Consolidated Financial Statementsmatters, see “Factors Influencing Future Performance” in the Annual Report.



SEMPRA INTERNATIONAL

As we discuss in “Cash Flows from Investing Activities,” our investments will significantly impact our future performance. In addition to the discussion below, we provide information about these investments in “Capital Resources and Liquidity” herein and in our Annual Report.


Sempra South American Utilities

Overview
Sempra South American Utilities has historically provided relatively stable earnings and liquidity, and its performance will depend primarily on the ratemaking and regulatory process, environmental regulations, foreign currency rate fluctuations and economic conditions. Sempra South American Utilities is also expected to provide earnings from construction projects when completed and from other investments, but will require substantial funding for these investments.
Revenues at Chilquinta Energía are based on rates set by the National Energy Commission (Comisión Nacional de Energía). The next rate reviews for sub-transmission are expected to be completed in the second quarter of 2016, with tariff adjustments going into effect retroactively from January 2016. The next rate reviews for distribution are scheduled to be completed, with tariff adjustments also going into effect, in November 2016. Sub-transmission will cover the period from January 2016 to December 2019 and distribution will cover the period from November 2016 to October 2020.
Luz del Sur serves primarily regulated customers, and revenues are based on rates set by the Energy and Mining Investment Supervisory Body (Organismo Supervisor de la Inversión en Energía y Minería). The next rate reviews are scheduled to be completed in 2017 and will cover the period from November 2017 to October 2021.
We discuss revenues at Sempra South American Utilities in Note 1 of the Notes to Consolidated Financial Statements in our Annual Report. We discuss the impact of tax reform in Chile and Peru in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Annual Report.
Sempra Energy has a combined $752 million in goodwill recorded at March 31, 2016 related to Chilquinta Energía and Luz del Sur. Goodwill is subject to impairment testing annually, as we discuss in Note 1 of the Notes to Consolidated Financial Statements in our Annual Report.
Transmission Projects
Chilquinta Energía. Chilquinta Energía has 50-percent ownership in two joint ventures, Eletrans S.A. and Eletrans II S.A., with Sociedad Austral de Electricidad Sociedad Anónima (SAESA) to construct transmission lines in Chile.
In May 2012, Eletrans S.A. was awarded two 220-kilovolt (kV) transmission lines in Chile. The approximately 100-mile, $80 million transmission line extending from Cardones to Diego de Almagro was completed in November 2015. The remaining 50-mile, $85 million transmission line extending from Ciruelos to Pichirropulli is expected to be completed in 2017.
In June 2013, Eletrans II S.A. was awarded two 220-kV transmission lines in Chile. The transmission lines will extend approximately 60 miles, and we estimate the projects will cost approximately $80 million in total and be completed in 2018.
Once the transmission lines are in operation, they will earn a return in U.S. dollars, indexed to the Consumer Price Index, for twenty years and a regulated return thereafter.
Sempra South American Utilities has a U.S. dollar-denominated loan to Eletrans S.A., its affiliate, totaling $76 million outstanding at March 31, 2016 to provide project financing for the construction of transmission lines.
The projects will be financed by the joint venture partners during construction. Other financing may be pursued upon completion of the projects.
Luz del Sur. Luz del Sur has received regulatory approval for an amended transmission investment plan that includes the development and operation of four substations and their related transmission lines in Lima. We estimate that the project will cost approximately $150 million and be in service in 2016 and 2017 as portions are completed. Once in operation, the capitalized cost will earn the regulated return for 30 years. The project will be financed through Luz del Sur’s existing debt program in Peru’s capital markets.


Sempra Mexico

Overview
Sempra Mexico is expected to provide earnings from construction projects when completed and from joint venture investments. We expect projects, joint venture investments and dividends in Mexico to be funded through a combination of available funds, including credit facilities, funds internally generated by the Mexico businesses, securities issuances, project financing, interim funding from the parent, partnering in joint ventures and proceeds from the planned sale of its Termoeléctrica de Mexicali natural gas-fired power plant.
IEnova and PEMEX are 50-50 partners in the joint venture Gasoductos de Chihuahua (GdC). IEnova currently accounts for its 50-percent interest in GdC as an equity method investment. In July 2015, IEnova entered into an agreement to purchase PEMEX’s 50-percent interest in GdC, which at closing would increase its interest from 50 percent to 100 percent. As we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein, the parties are in the process of restructuring the transaction in response to issues raised in the review of the transaction by Mexico’s antitrust commission. The terms and conditions of the revised transaction are still under negotiation, and there can be no assurance that a new agreement will be reached. Any restructured transaction remains subject to satisfactory completion of the Mexican antitrust review and may require further approvals from other Mexican authorities.
The sharp decline in crude oil prices beginning in late 2014 and continuing into 2016, as well as low natural gas prices, have had a negative impact on PEMEX’s revenues, income and cash flows. Certain rating agencies have expressed several concerns regarding PEMEX’s financial condition, including the total amount of PEMEX’s debt and the significant increase in PEMEX’s indebtedness over the last several years, as well as its substantial unfunded reserve for retirement pensions and seniority premiums. In November 2015, a major U.S. credit rating agency revised PEMEX’s global foreign currency and local currency credit ratings from A3 to Baa1 and changed the outlook for its credit ratings to negative. In March 2016, based on its view that the company’s current weak credit metrics will worsen as it continues to fund capital expenditures from external sources, the same major credit rating agency further downgraded PEMEX’s global foreign currency and local currency credit ratings from Baa1 to Baa3 and affirmed that the outlook on its credit ratings remains negative. PEMEX is also subject to the control of the Mexican government, which could limit its ability to satisfy its external debt obligations. Although PEMEX is a State Productive Enterprise of Mexico, its financing obligations are not guaranteed by the Mexican government. As both a partner in the GDC joint venture and a customer with capacity contracts for transportation services on Sempra Mexico’s ethane and propane pipelines, if PEMEX were unable to meet any or all of its obligations to Sempra Mexico, it could have a material adverse effect on Sempra Energy’s financial condition, results of operations and cash flows.
In February 2016, management approved a plan to market and sell Sempra Mexico’s Termoeléctrica de Mexicali, a 625-MW natural gas-fired power plant located in Mexicali, Baja California, Mexico. As a result, we stopped depreciating the plant and classified the plant as an asset held for sale, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein. We expect to complete the sale in the second half of 2016.
Pipeline Projects
In October 2012, IEnova was awarded two contracts by the Federal Electricity Commission (Comisión Federal de Electricidad, or CFE) to build and operate an approximately 500-mile pipeline network (Sonora pipeline) to transport natural gas from the U.S.-Mexico border south of Tucson, Arizona through the Mexican state of Sonora to the northern part of the Mexican state of Sinaloa along the Gulf of California. The network will be comprised of two segments that will interconnect to the U.S. interstate pipeline system. We estimate it will cost approximately $1 billion. The first segment was completed in stages, with a section completed in the fourth quarter of 2014 and the final section completed in August 2015. We expect to complete the second segment in 2016. The capacity is fully contracted by the CFE under two 25-year contracts denominated in U.S. dollars.
In 2014, the GdC joint venture and affiliates of PEMEX executed agreements for the development of Los Ramones Norte, a natural gas pipeline of approximately 280 miles and two compression stations, which connects with the first phase of Los Ramones and runs to the vicinity of San Luis Potosi, with an estimated cost of $1.45 billion. The GdC joint venture has a 50-percent interest in the project. The pipeline began commercial operation in February 2016. We expect the two compression stations to begin operation in the second quarter of 2016. The pipeline’s capacity is fully contracted under a 25-year transportation services agreement with the National Center of Natural Gas Control (Centro Nacional de Control de Gas Natural, or CENAGAS), denominated in Mexican pesos, indexed to the U.S. dollar and adjusted annually for inflation and fluctuation of the exchange rate. The transportation services agreement was transferred from PEMEX to CENAGAS in January 2016.
Sempra Mexico has loans to an affiliate of its joint venture with PEMEX totaling $87 million outstanding at March 31, 2016 to finance a portion of its investment in the Los Ramones Norte pipeline project.
In December 2014, Sempra Mexico entered into a natural gas transportation services agreement with CFE for a 25-year term, denominated in U.S. dollars, for 100 percent of the transport capacity of the Ojinaga pipeline, equal to 1.4 Bcf per day. Sempra Mexico will be responsible for the development, construction and operation of the approximately 137-mile, 42-inch pipeline, with an estimated cost of $300 million. We expect the pipeline to begin operations in the first half of 2017.
In July 2015, Sempra Mexico entered into a natural gas transportation services agreement with CFE for a 25-year term, denominated in U.S. dollars, for 100 percent of the transport capacity of the San Isidro pipeline, equal to 1.1 Bcf per day. Sempra Mexico will be responsible for the development, construction and operation of the approximately 14-mile pipeline, with an estimated cost of $110 million. We expect the pipeline to begin operations in the first half of 2017.
IEnova continues to monitor CFE project opportunities and carefully analyze CFE bids in order to participate in those that fit its overall growth strategy. Competition for recent pipeline projects has been intense with numerous bidders competing aggressively for these projects. There can be no assurance that IEnova will be successful in bidding for new CFE projects.
The ability to successfully complete pipeline projects, like other major construction projects, is subject to a number of risks and uncertainties. For a discussion of these risks and uncertainties, see “Risk Factors” in our Annual Report.
Energía Sierra Juárez
In 2014, we consummated the sale of a 50-percent equity interest in the first phase of Energía Sierra Juárez to a wholly owned subsidiary of InterGen N.V. The project is designed to provide up to 1,200 MW of capacity if fully developed. The 155-MW first phase of the Energía Sierra Juárez wind generation project is fully contracted by SDG&E and began commercial operations in June 2015. Future expansion of Energía Sierra Juárez will depend, among other factors, on the ability to obtain additional power purchase contracts.
Sempra Mexico has a U.S. dollar-denominated loan to Energía Sierra Juárez, its affiliate, totaling $17 million outstanding at March 31, 2016 to finance the first phase of the project.
MEXICO
Energía Costa Azul LNG Terminal
In FebruaryMay 2015, Sempra Natural Gas,LNG & Midstream, IEnova, and a subsidiary of Petróleos Mexicanos (or PEMEX, the Mexican state-owned oil company) entered into a Memorandum of Understanding (MOU) to collaborate inproject development agreement for the joint development of athe proposed natural gas liquefaction project at IEnova’s existing regasification terminal at Energía Costa Azul. The MOU definesagreement specifies how the basisparties will share costs, and establishes a framework for the parties to explore PEMEX’s participation in this potentialwork jointly on permitting, design, engineering and commercial activities associated with exploring the development of the liquefaction project, including joining efforts on its development and structuring agreements that would allow opportunities for PEMEX to become a customer, natural gas supplier and investor; we have also started to share developmentproject. We are sharing costs with PEMEX.PEMEX on the development efforts pursuant to the agreement, and have applied for the primary governmental authorizations for the liquefaction project. Energía Costa Azul has profitable long-term regasification contracts for 100 percent of the facility,regasification facility’s capacity, 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 financially than continuing to supply regasification services under our existing contracts. In addition,
Development of this project requiresis subject to numerous risks and uncertainties, including the receipt of a number of permits and regulatory approvals,approvals; finding suitable partners and customers,customers; obtaining financing,financing; negotiating and completing suitable commercial agreements, including joint venture agreements, tolling capacityLNG sales agreements, gas supply agreements and construction contracts, andcontracts; reaching a final investment decision.decision; and other factors associated with this potential investment. For a discussion of these risks, see “Risk Factors” in ourthe Annual Report.
Termoeléctrica de Mexicali

Our TdM power plant is currently held for sale, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.
Other Sempra Mexico Matters
For a discussion about other Sempra Mexico matters, see “Factors Influencing Future Performance” in the Annual Report.
SEMPRA U.S. GAS & POWER
RENEWABLES
Sempra Renewables
Overview
Renewables’ performance is primarily a function of the solar and wind power generated by its assets. Power generation from these assets depends on solar and wind resource levels, weather conditions, and Sempra Renewables is developing and investing in renewable energy generation projects that have long-term contracts with electric load serving entities, which provide electric serviceRenewables’ ability to end-users and wholesale customers. The renewable energy projects have planned in-service dates through 2016. These projects require construction financing which may come from a variety of sources including operating cash flow, project financing, funds from the parent, partnering in joint ventures, and other forms of equity sales, including tax equity. The varying costs of these alternative financing sources impact the projects’ returns.
maintain equipment performance.
Sempra Renewables’ future performance and the demand for renewable energy is impacted by various market factors, most notably state mandated requirements for utilities to deliver a portion of total energy load from renewable energy sources. The rules governing these requirements are generally known as the Renewables Portfolio Standard (RPS). Additionally, the phase out or extension of U.S. federal income tax incentives, primarily investment tax credits and production tax credits, and grant programs could significantly impact future renewable energy resource availability and investment decisions.
Black Oak Getty Wind ProjectSEMPRA LNG & MIDSTREAM
In March 2015, Sempra Renewables acquired the Black Oak Getty Wind project, a 78-MW wind farm under development in Stearns County, Minnesota. Sempra Renewables is completing the development of the wind farm, and we expect the project to be fully operational by the end of 2016. Minnesota Municipal Power Agency has contracted for the energy generated from the project for 20 years upon project completion.

Copper Mountain Solar
Copper Mountain Solar is a photovoltaic generation facility operated and under development by Sempra Renewables in Boulder City, Nevada. When fully developed, the project will be capable of producing up to approximately 550 MW of solar power, with 458 MW currently in operation, of which Sempra Renewables has 50-percent ownership of 400 MW through joint venture partnerships, and 100-percent ownership of the 58-MW facility. It is being developed in multiple phases as power sales become contracted.
In July 2014, Sempra Renewables signed a 20-year power purchase agreement (PPA) with Edison for all of the solar power from Copper Mountain Solar 4 beginning in 2020. The CPUC approved the PPA in March 2015. We expect Copper Mountain Solar 4 to be in service in 2016. Sempra U.S. Gas & Power will market the output from Copper Mountain Solar 4 before the start of the Edison contract term. Copper Mountain Solar 4 will total 94 MW when completed.
Mesquite Solar
Mesquite Solar is a photovoltaic generation facility under development by Sempra Renewables in Maricopa County, Arizona. If fully developed, the project will be capable of producing up to approximately 700 MW of solar power, with 150 MW currently in operation in a joint venture with Consolidated Edison Development (Mesquite Solar 1). In June 2015, Sempra Renewables signed a 20-year power sale agreement with Edison for 100 MW of solar power from the second phase of Mesquite Solar (Mesquite Solar 2). The CPUC approved the PPA in December 2015. In July 2015, Sempra Renewables signed a 25-year PPA with the Western Area Power Administration on behalf of the U.S. Department of the Navy for 150 MW of solar power from the third phase of Mesquite Solar (Mesquite Solar 3). We expect Mesquite Solar 2 and 3 to be in service by the end of 2016.
Sempra Natural Gas
Rockies Express and Pipeline Capacity
Sempra Natural Gas owns a 25-percent interest in Rockies Express, a partnership that operates the Rockies Express natural gas pipeline (REX), which links the Rocky Mountains region to the upper Midwest and the eastern United States. Sempra Natural Gas has an agreement for certain capacity on REX through November 2019. The capacity costs have been partially offset by revenues from releases of the capacity contracted to third parties.
In March 2016, Sempra Natural Gas entered into an agreement with a subsidiary of Tallgrass Development, LP to sell Sempra Natural Gas’ 25-percent interest in Rockies Express for approximately $440 million in cash, subject to adjustment at closing. The transaction is subject to customary closing conditions. Sempra Natural Gas expects the transaction to close in the second quarter of 2016. We discuss this transaction and the investment in Rockies Express further in Notes 3 and 8 of the Notes to Condensed Consolidated Financial Statements herein.
Additionally, Sempra Natural Gas intends to permanently release uncontracted capacity that it had been releasing on an interim basis. The effect of the permanent capacity release is expected to result in a charge to earnings of approximately $100 million to $120 million during the second quarter of 2016, representing an acceleration of losses that would otherwise be realized over the contract term, which extends through November 2019.
Natural Gas Storage
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, LLC (LA Storage) in Louisiana. LA Storage could be positioned to support LNG export from the Cameron LNG JV terminal (discussed below in “Cameron Liquefaction”) 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. In addition, our LA Storage development project may be unable to attract cash flow commitments sufficient to support further investment or to extend its FERC construction permit beyond the current expiration date of June 2017. The LA Storage project also includes an existing 23.3-mile pipeline header system, the LA Storage pipeline, that is not contracted.
We perform recovery testing of our recorded asset values when market conditions indicate that such values may not be recoverable. In the event such values are not recoverable, we would consider the fair value of these assets relative to their recorded value. To the extent the recorded (carrying) value is in excess of the fair value, we would record a noncash impairment charge. The recorded value of our long-lived natural gas storage assets at March 31, 2016 is $1.5 billion. A significant impairment charge related to our gas storage assets would have a material adverse effect on our results of operations in the period in which it is recorded.
Sempra Natural Gas has 42 Bcf of operational working natural gas storage capacity (20 Bcf at Bay Gas and 22 Bcf at Mississippi Hub). Sempra Natural Gas’ natural gas storage facilities and projects include
§  Bay Gas, a facility located 40 miles north of Mobile, Alabama, that provides underground storage and delivery of natural gas. Sempra Natural Gas owns 91 percent of the project. 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, located 45 miles southeast of Jackson, Mississippi, an underground salt dome natural gas storage project with access to shale basins of East Texas and Louisiana, traditional gulf supplies and LNG, with multiple interconnections to serve the Southeast and Northeast regions.
§  LA Storage, a salt cavern development project in Cameron Parish, Louisiana. Sempra Natural Gas owns 77 percent of the project and ProLiance Transportation LLC owns the remaining 23 percent. The project’s location provides access to several LNG facilities in the area.
Natural Gas Distribution Utilities
In April 2016, Sempra Natural Gas entered into a definitive agreement to sell the parent company of Mobile Gas and Willmut Gas. We expect to receive cash proceeds of approximately $323 million, subject to normal adjustments at closing, and the buyer will assume existing debt of approximately $67 million. In April 2016, we reclassified the assets and liabilities of Mobile Gas and Willmut Gas to held for sale. We expect to recognize a gain on the sale of approximately $70 million after-tax. The transaction is subject to customary regulatory approvals, and we expect the sale to close in 2016.
Cameron Liquefaction
Cameron LNG JV Three-Train Liquefaction Project. We discuss the 2014 formation of the Cameron LNG JV, including the contribution of our share of equity to the joint venture through the contribution of the Cameron LNG, LLC regasification terminal in Hackberry, Louisiana, in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report. The existing regasification terminal is capable of processing 1.5 Bcf of natural gas per day and it currently generates revenue under a terminal services agreement for approximately 3.75 Bcf of natural gas storage and associated send-out rights of approximately 600 million cubic feet (MMcf) of natural gas per day through 2029. The agreement allows the customer to pay capacity reservation and usage fees to use the facilities to receive, store and regasify the customer’s LNG. As described below, we expect this agreement to be terminated during the first half of 2017 due to progress on the construction of the three-train liquefaction project. Sempra Natural Gas 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.Project
The current liquefaction project under construction, which will utilize Cameron LNG JV’s existing facilities, is comprised of three liquefaction trains designed to a nameplate capacity of 13.9 million tonnes per annum (Mtpa) of LNG with an expected export capability of 12 Mtpa of LNG, or approximately 1.7 Bcf per day. We expect the project to achieve commercial operation of all three trains in 2018, and have the first year of full operations in 2019. The anticipated incremental investment in the three-train liquefaction project is estimated to be approximately $7 billion, including the cost of the lump-sum, turnkey construction contract, development engineering costs and permitting costs, but excluding capitalized interest and other financing costs. The majority of the incremental investment will be project-financed and the balance provided by the project partners. We expect that our remaining equity requirements to complete the project will be met by a combination of our share of cash generated from each liquefaction train as it comes on line and additional cash contributions. If construction, financing or other project costs are higher than we currently expect, we may have to contribute additional cash exceeding our current expectations. The total cost of the facility, including the cost of our original facility plus interest during construction, financing costs and required reserves, is estimated to be approximately $10 billion.
The joint venture has authorization to export LNG to both Free Trade Agreement (FTA) countries and to countries that do not have an FTA with the United States. Cameron LNG JV has 20-year liquefaction and regasification tolling capacity agreements in place with ENGIE S.A. (formerly GDF SUEZ S.A.) and affiliates of Mitsubishi Corporation and Mitsui & Co, Ltd., that subscribe the full nameplate capacity of the facility.
Sempra Natural Gas has agreements totaling 1.45 Bcf per day of firm natural gas transportation service to the Cameron LNG JV facilities on the Cameron Interstate Pipeline with ENGIE S.A. and affiliates of Mitsubishi Corporation and Mitsui & Co., Ltd. The terms of these agreements are concurrent with the liquefaction and regasification tolling capacity agreements.
Construction on the current project began in the second half of 2014 under an engineering, procurement and construction (EPC) contract with a joint venture between CB&I Shaw Constructors, Inc., a wholly owned subsidiary of Chicago Bridge & Iron Company N.V., and Chiyoda International Corporation, a wholly owned subsidiary of Chiyoda Corporation.
In August 2014, Sempra Energy and the project partners executed project financing documents for senior secured debt in an initial aggregate principal amount up to $7.4 billion for the purpose of financing the cost of development and construction of the Cameron LNG JV liquefaction project. Concurrently, Sempra Energy entered into completion guarantees under which it has severally guaranteed 50.2 percent of the debt, or a maximum principal amount of $3.7 billion. The project financing and completion guarantees became effective on October 1, 2014, and will terminate upon financial completion of the project, which will occur upon satisfaction of certain conditions, including all three trains achieving commercial operation and meeting certain operational performance tests. We expect the project to achieve financial completion and the completion guarantees to be terminated in the second half of 2019.
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 problems,challenges, substantial construction delays and increased costs. As noted above, Cameron LNG JV has a turnkey EPCengineering, procurement and construction (EPC) contract, with a joint venture between CB&I Shaw Constructors, Inc. and Chiyoda International Corporation. Ifif the contractor becomes unwilling or unable to perform according to the terms and timetable of the EPC contract, Cameron LNG JV wouldcould be required to engage a substitute contractor, which would result in further project delays and potentially significantly increased costs,costs. In late October 2016, the EPC contractor indicated that the project is facing delays, which could be significant.will delay earnings and associated cash flows anticipated in 2018 and 2019. For a 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Our Business – Sempra LNG & Midstream” and “Risk Factors” in the Annual Report.
Proposed Additional Cameron Liquefaction Expansion
Cameron LNG JV has a terminal services agreement with one customer that requiresreceived the customer to pay capacity reservation and usage fees to use its facilities to receive, store and regasify the customer’s LNG. There is a termination agreement in place that will result in the termination of this services agreement at the point during construction of the new liquefaction facilities where piping tie-ins to the existing regasification terminal become necessary. Based on the full notice to proceed that was issued to Cameron LNG JV’s EPC contractor in October 2014, we expect this termination date to occur during the first half of 2017.
In December 2014, Cameron LNG JV filed with the U.S. Department of Energy (DOE) for authorization to match the total export volumes allowed to be exported to FTA countries under the FERC permit. This would allow for increased export from the three-train facility of up to 2.95 Mtpa. In April 2015, Cameron LNG JV filed the corresponding DOE Non-FTA permit application.
Proposed Additional Cameron Liquefaction Expansion. Cameron LNG JV is also pursuing the permittingmajor permits necessary to expand the current configuration of the Cameron LNG JV liquefaction project from the current three liquefaction trains under construction. The proposed expansion project is expected to includeincludes up to two additional liquefaction trains, capable of increasing LNG production capacity by approximately 9 Mtpamillion tonnes per annum (Mtpa) to 10 Mtpa,


and up to two additional full containment LNG storage tanks (one of which was permitted with the original three-train project). In February 2015, Cameron LNG JV filed the DOE FTA application and the pre-filing application at FERC for the two additional trains and the one containment tank. In May 2015, the joint venture filed a corresponding DOE Non-FTA permit application. In July 2015, Cameron LNG JV received approvalAdvancement of the DOE FTA application. In September 2015, Cameron LNG JV submitted the FERC application and was formally noticed by FERC in October 2015. On February 12, 2016, Cameron LNG JV received the FERC environmental assessment, and expects to receive the FERC permit in the second quarter of 2016.project includes
▪DOE Free Trade Agreement (FTA) approval received in July 2015
▪Non-FTA approval received in July 2016
▪FERC permit received in May 2016
Under the Cameron LNG JV financing agreements, expansion of the Cameron LNG JV facilities beyond the first three trains is subject to certain restrictions and conditions, including among others, timing restrictions on expansion of the project unless appropriate prior consent is obtained from lenders. Under the Cameron LNG JV equity agreements, the expansion of the project requires the unanimous consent of all the partners, including with respect to the equity investment obligation of each partner. Recently, oneOne of the partners indicated to Sempra Energy and the other partners that although it plans to consent to the expansion, it currently does not planintend to invest additional equitycapital in the expansion. Under those circumstances, the proposed amendment of the Cameron LNG JV agreement would allocatewith respect to the equity investment obligations forexpansion. As a result, discussions among the expansionpartners are taking place, and we are considering a variety of options to one attempt to move this project forward. These activities have contributed to delays in developing firm pricing information and securing customer commitments. In light of these developments, we are unable to predict when we and/or more ofCameron LNG JV might receive the other partners.
consents and approvals required to move forward on this project.
The expansion of the Cameron LNG JV facilities beyond the first three trains is subject to a number of risks and uncertainties, including completing the required commercial agreements, amending the Cameron LNG JV agreement among the partners, obtaining customer commitments, completing the required commercial agreements, securing and maintaining all necessary permits, approvals and approvals,consents, obtaining financing, reaching a final investment decision among the Cameron LNG JV partners, and other factors associated with the potential investment. See “Risk Factors” in the Annual Report.
We discuss the deconsolidation of Cameron LNG, LLC, the Cameron LNG JV project financing obligations and Sempra Energy’s completion guarantee further in Notes 3 and 4 of the Notes to Consolidated Financial Statements in the Annual Report.
Other LNG Liquefaction Development
Design, regulatory and commercial activities are ongoing for potential LNG liquefaction developments at our Port Arthur, Texas site and at Sempra Mexico’s Energía Costa Azul facility and at our Port Arthur, Texas site.facility. For these development projects, we have met with potential customers and determined there is an interest in long-term contracts for LNG supplies beginning in the 20202022 to 20232025 time frame.
Port Arthur
Port Arthur. In March 2015,November 2016, Sempra Natural GasLNG & Midstream submitted a request to the FERC seeking authorization to initiate the pre-filing review forsite, construct and operate the proposed Port Arthur LNG natural gas liquefaction and export facility in Port Arthur, Texas. The proposed project is designed to include two natural gas liquefaction trains with total export capability of approximately 10 Mtpa, or 1.4 Bcf per day; two 160,000-cubic-meter storage tanks; marine facilities for vessel berthing and loading; natural gas liquids and refrigerant storage; feed gas pre-treatment; truck loading and unloading areas; and combustion turbine generators for self-generation of electrical power.
In March 2015, Sempra Natural Gas also submitted a request to the FERC to initiate the pre-filing review for the proposed Port Arthur pipeline project. The proposed project consists of two 42-inch-diameter feed gas pipelines (7 and 27 miles long), two compressor stations, receipt meter stations, and other appurtenant facilities in Orange and Jefferson Counties, Texas, and Cameron Parish, Louisiana. The pipelines would provide up to 1.6 Bcf per day of capacity to the Port Arthur LNG facilities.
In March and June 2015, Sempra Natural Gas filed permit applications with the DOE for authorization to export the LNG produced from the proposed project to all current and future FTA and Non-FTA countries, respectively. In August 2015, Sempra Natural Gas received authorization from the DOE to export the LNG produced from the proposed project to all current and future FTA countries.
In February 2016, Sempra Natural Gas
▪The proposed project is designed to include
◦two natural gas liquefaction trains with production capability of approximately 13.5 Mtpa, or 698 Bcf per year;
◦three LNG storage tanks;
◦natural gas liquids and refrigerant storage;
◦feed gas pre-treatment facilities; and
◦two berths and associated marine and loading facilities.
▪In June 2015, Sempra LNG & Midstream filed permit applications with the DOE for authorization to export the LNG produced from the proposed project to all current and future non-FTA countries.
▪In August 2015, Sempra LNG & Midstream received authorization from the DOE to export the LNG produced from the proposed project to all current and future FTA countries.
▪In February 2016, Sempra LNG & Midstream and Woodside Petroleum Ltd. (Woodside) entered into a project development agreement for the joint development of the proposed Port Arthur LNG liquefaction project. The agreement specifies how the parties will share costs, and establishes 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.
Also, in November 2016, Sempra LNG & Midstream filed a permit application with the FERC for a pipeline project that will provide natural gas transportation service for the Port Arthur LNG liquefaction project. The agreement specifies howIn February 2017, Sempra LNG & Midstream initiated the parties will share costs, and establishesFERC pre-filing review process for a frameworkpotential permit application for the parties to work jointly on permitting, design, engineering, commercial and marketing activities associated with developingan additional pipeline project that would also provide natural gas transportation service for the Port Arthur LNG liquefaction project.
Development of the Port Arthur LNG liquefaction project is subject to a number of risks and uncertainties, including completing the required commercial agreements, such as joint venture agreements, tolling capacityLNG sales agreements orand gas supply and LNG sales agreements; completing construction contracts; securing all necessary permits and approvals; obtaining financing and incentives; reaching a final investment decision; and other factors associated with the potential investment. See “Risk Factors” in the Annual Report.


Energía Costa Azul.
We further discuss Sempra Natural Gas’LNG & Midstream’s participation in potential LNG liquefaction development at Sempra Mexico’s Energía Costa Azul facility above underin “Sempra Mexico − – Energía Costa Azul LNG Terminal.”
Natural Gas Storage Assets
LNG Liquefaction Development CostsThe future performance of our natural gas storage assets could be impacted by changes in the U.S. natural gas market, which could lead to sustained diminished natural gas storage values.
Total expenditures on LNG liquefaction development for the three months endedThe recorded value of our long-lived natural gas storage assets at March 31, 2016 were $14 million, including capitalized costs2017 is $1.5 billion. Historically, the value of $8 million (pretax). After-tax LNGnatural 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 Storage Company, Ltd. 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 further depressed asset values. In addition, our LA Storage development costs expensed for the three months ended March 31, 2016 were $4 million. Weproject may be unable to attract cash flow commitments sufficient to support further investment and we do not currently expect to expense approximately $20 millionrequest extension of its FERC construction permit beyond the current expiration date of June 2017. The LA Storage project also includes an existing 23.3-mile pipeline header system, the LA Storage pipeline, that is not currently contracted.
We perform recovery testing of our recorded asset values when market conditions indicate that such values may not be recoverable. In the event such values are not recoverable, we would consider the fair value of these assets relative to $25 million, after-tax,their recorded value. To the extent the recorded (carrying) value is in 2016 for liquefaction and LNG integrated midstream development costs.
excess of the fair value, we would record a noncash impairment charge. 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.
RBS SEMPRA COMMODITIES
In three separate transactions in 2010 and one in early 2011, we and The Royal Bank of Scotland plc (RBS), our partner in theFor a discussion about RBS Sempra Commodities, joint venture, sold substantially all ofsee “Factors Influencing Future Performance” in the businessesAnnual Report and assets of our commodities-marketing partnership. The investment balance of $67 million at March 31, 2016 reflects remaining distributions expected to be received from the partnership as it is dissolved. The amount of distributions, if any, may be impacted by the matters we discuss related to RBS Sempra Commodities under “Other Litigation” in Note 11 of the Notes to Condensed Consolidated Financial Statements herein. In addition, amounts may be retained by the partnership for an extended period of time to help offset unanticipated future general and administrative costs necessary to complete the dissolution of the partnership.

OTHER SEMPRA ENERGY MATTERS

We may be further impacted by depressed and rapidly changing economic conditions. These conditions may also affect our counterparties. Moreover, the dollar may fluctuate significantly compared to some foreign currencies, especially in Mexico and South America where we have significant operations. We discuss “Concentration of Credit Risk” in Note 11 of the Notes to Condensed Consolidated Financial Statements herein and “Credit Risk,” “Foreign Currency Rate Risk” and “Foreign Inflation Risk” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report. North American natural gas prices, when in decline, negatively affect profitability at Sempra Natural Gas. Also, a reduction in projected global demand for LNG 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. For a discussion of these risks and other risks involving changing commodity prices,about Other Sempra Energy Matters, see “Risk Factors”“Factors Influencing Future Performance” in the Annual Report.
In July 2010, federal legislation to reform financial markets was enacted that significantly alters how over-the-counter (OTC) derivatives are regulated, which may impact all of our businesses. The law increased regulatory oversight and transparency requirements of OTC energy derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the U.S. Commodity Futures Trading Commission (CFTC), (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits, the latter of which is pending final approval. The law gives the CFTC authority to exempt end users of energy commodities which could reduce, but not eliminate, the applicability of these measures to us and other end users. These requirements could cause our OTC transactions to be more costly and have a material adverse effect on our liquidity due to additional capital requirements. In addition, as these reforms aim to standardize OTC products, they could limit the effectiveness and extent of our hedging programs, because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to mitigate and may be restricted on the size of our hedging program.
Our future performance depends substantially on the timing and success of our business development efforts and our construction, maintenance and capital projects. We discuss this and additional matters that could affect our future performance in Notes 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein, in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report, and in “Risk Factors” in the Annual Report.


LITIGATION

We describe legal proceedings whichthat could adversely affect our future performance in Note 11 of the Notes to Condensed Consolidated Financial Statements herein.


CRITICAL ACCOUNTING POLICIES AND ESTIMATES

We view certain accounting policies as critical because their application is the most relevant, judgmental, and/or material to our financial position and results of operations, and/or because they require the use of material judgments and estimates. We discuss these accounting policies in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Annual Report.
We describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements in the Annual Report. We follow the same accounting policies for interim reporting purposes.


NEW ACCOUNTING STANDARDS

We discuss the relevant pronouncements that have recently been issued or become effective and have had or may have an impact on our financial statements and/or disclosures in Note 2 of the Notes to Condensed Consolidated Financial Statements herein.




ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We provide disclosure regarding derivative activity in Note 7 of the Notes to Condensed Consolidated Financial Statements herein. We discuss our market risk and risk policies in detail in "Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations"Operations” herein and in the Annual Report, and in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.Report.


INTEREST RATE RISK

The table below shows the nominal amount of long-term debt at March 31, 20162017 and December 31, 2015:2016:


NOMINAL AMOUNT OF LONG-TERM DEBT(1)
(Dollars in millions)
 March 31, 2017  December 31, 2016
 
Sempra Energy
Consolidated
 SDG&E SoCalGas  
Sempra Energy
Consolidated
 SDG&E SoCalGas
Utility fixed-rate$7,200
 $4,191
 $3,009
  $7,218
 $4,209
 $3,009
Utility variable-rate302
 302
 —
  445
 445
 —
Non-utility fixed-rate6,746
 —
 —
  6,703
 —
 —
Non-utility variable-rate738
 —
 —
  719
 —
 —
(1)Before the effects of interest rate swaps, reductions/increases for unamortized discount/premium and reduction for debt issuance costs, and excluding capital lease obligations and build-to-suit lease.
NOMINAL AMOUNT OF LONG-TERM DEBT(1)
(Dollars in millions)
  March 31, 2016December 31, 2015
  Sempra Energy  Sempra Energy  
  ConsolidatedSDG&ESoCalGasConsolidatedSDG&ESoCalGas
    Utility fixed-rate$6,344$3,832$2,512$6,362$3,849$2,513
    Utility variable-rate 452 452 ― 455 455 ―
    Non-utility fixed-rate 6,801 ― ― 6,780 ― ―
    Non-utility variable-rate 166 ― ― 166 ― ―
(1)Excluding capital lease obligations, build-to-suit lease and interest rate swaps, and before reductions/increases for unamortized discount/premium and reductions for debt issuance costs.


Interest rate risk sensitivity analysis measures interest rate risk by calculating the estimated changes in earnings that would result from a hypothetical change in market interest rates. If interest rates changed by oneten percent on all of Sempra Energy’s effective variable-rate, long-term debt at March 31, 2016,2017, the change in earnings over the next 12-month period ending March 31, 20172018 would be $5$4 million (after-tax), including $3 million (after-tax) at SDG&E.(after tax). These hypothetical changes in earnings are based on our long-term debt position after the effect of interest rate swaps.
We provide additional information about interest rate swap transactions in Note 7 of the Notes to Condensed Consolidated Financial Statements herein.


FOREIGN CURRENCY AND INFLATION RATE RISK

We discuss our foreign currency and inflation exposure above in “Results of Operations – Changes in Revenues, Costs and Earnings – Impact of Foreign Currency and Inflation Rates on Results of Operations” herein. We also discuss our foreign currency exposure at our Mexican and South American subsidiaries in “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Impact of Foreign Currency Rate Risk”and Inflation Rates on Results of Operations” herein and in the Annual Report. At March 31, 2016,2017, there were no significant changes to our exposure to foreign currency rate risk since December 31, 2015. If IEnova’s potential acquisition of the remaining 50-percent interest in GdC is completed, Sempra Mexico will be subject to additional foreign currency rate risk. However, similar to our current Mexican operations, GdC’s functional currency is the U.S. dollar and its assets are covered by long-term, U.S. dollar-based contracts.2016.

ITEM 4. CONTROLS AND PROCEDURES


EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Sempra Energy, SDG&E and SoCalGas have designed and maintain disclosure controls and procedures to ensure that information required to be disclosed in their respective reports is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and is accumulated and communicated to the management of each company, including each respective Chief Executive Officerprincipal executive officer and Chief Financial Officer,principal financial officer, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, the management of each company recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives; therefore, the management of each company applies judgment in evaluating the cost-benefit relationship of other possible controls and procedures.
Under the supervision and with the participation of management, including the Chief Executive Officersprincipal executive officers and Chief Financial Officersprincipal financial officers of Sempra Energy, SDG&E and SoCalGas, each company evaluated the effectiveness of the design and operation of its disclosure controls and procedures as of March 31, 2016,2017, the end of the period covered by this report. As discussed below, we excluded Ventika, S.A.P.I. de C.V. and Ventika II, S.A.P.I. de C.V. (collectively, Ventika), and Gasoductos de Chihuahua S. de R.L. de C.V. (GdC) from our evaluation of changes in Sempra Energy’s disclosure controls and procedures, to the extent subsumed by


Ventika’s and GdC’s internal control over financial reporting. Based on these evaluations, the Chief Executive Officersprincipal executive officers and Chief Financial Officersprincipal financial officers of Sempra Energy, SDG&E and SoCalGas concluded that their respective company’s disclosure controls and procedures were effective at the reasonable assurance level.


INTERNAL CONTROL OVER FINANCIAL REPORTING

ThereOther than the changes which may be associated with the 2016 acquisitions described below (which did not impact SDG&E or SoCalGas), there have been no changes in the companies’ internal control over financial reporting during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the companies’ internal control over financial reporting.
As we discuss in Note 3 of the Notes to Consolidated Financial Statements in the Annual Report, we acquired Ventika, S.A.P.I. de C.V. and Ventika II, S.A.P.I. de C.V. (collectively, Ventika) in December 2016 and the remaining 50-percent interest in Gasoductos de Chihuahua S. de R.L. de C.V. (GdC) in September 2016. The carrying value of Ventika’s net assets was $293 million or 1.9 percent of Sempra Energy’s net assets at March 31, 2017. Ventika’s losses for the three months ended March 31, 2017 were $13 million or 3 percent of total Sempra Energy earnings for the three months ended March 31, 2017. The carrying value of GdC’s net assets was $2.4 billion or 15.2 percent of Sempra Energy’s net assets at March 31, 2017. GdC’s earnings for the three months ended March 31, 2017 were $3 million or 0.7 percent of total Sempra Energy earnings for the three months ended March 31, 2017. We are in the process of integrating Ventika and GdC. Our management is analyzing, evaluating and, where necessary, will implement changes in, Ventika’s and GdC’s controls and procedures. Due to the limited period of time since the acquisition dates, we have not had sufficient time to assess the internal controls of Ventika and GdC. Therefore, we excluded Ventika and GdC from our evaluation of disclosure controls and procedures above, to the extent subsumed by Ventika’s and GdC’s internal control over financial reporting. We intend to include Ventika and GdC in the overall assessment of, and report on, internal control over financial reporting as soon as practicable, but in no event later than one year from the respective acquisition dates.



PART II – OTHER INFORMATION



ITEM 1. LEGAL PROCEEDINGS

We are not party to, and our property is not the subject of, any material pending legal proceedings (other than ordinary routine litigation incidental to our businesses) except for the matters 1) described in Notes 9 10 and 11 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 13 14 and 15 of the Notes to Consolidated Financial Statements in the Annual Report, or 2) referred to in “Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations” herein and in the Annual Report.


ITEM 1A. RISK FACTORS

There have not been any material changes from the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2015.2016.

ITEM 6. EXHIBITS

The following exhibits relate to each registrant as indicated.

EXHIBIT 3 -- BYLAWS AND ARTICLES OF INCORPORATION
Southern California Gas Company
3.1 Bylaws of Southern California Gas Company (as amended through January 30, 2017) (incorporated herein by reference to Exhibit 3.1 of the SoCalGas Current Report on Form 8-K filed on January 31, 2017).
EXHIBIT 10 -- MATERIAL CONTRACTS
 
Compensation
 
Sempra Energy
10.1 Severance Pay Agreement between Sempra Energy and Debra L. Reed, dated March 1, 2017.
 
10.2 Severance Pay Agreement between Sempra Energy and Joseph A. Householder, dated March 1, 2017.
10.3 Severance Pay Agreement between Sempra Energy and Martha B. Wyrsch, dated March 1, 2017.
10.4 Severance Pay Agreement between Sempra Energy and G. Joyce Rowland, dated March 1, 2017.
San Diego Gas & Electric Company
10.5 Severance Pay Agreement between Sempra Energy and Scott D. Drury, dated March 1, 2017.
10.6 Severance Pay Agreement between Sempra Energy and Caroline A. Winn, dated March 1, 2017.
10.7 Severance Pay Agreement between Sempra Energy and Erbin Keith, dated March 1, 2017.


10.8 Severance Pay Agreement between Sempra Energy and Randall L. Clark, dated March 1, 2017.
Southern California Gas Company
10.9 Severance Pay Agreement between Sempra Energy and Patricia K. Wagner, dated March 1, 2017.
10.10 Severance Pay Agreement between Sempra Energy and J. Bret Lane, dated March 1, 2017.
10.11 Severance Pay Agreement between Sempra Energy and Sharon L. Tomkins, dated March 1, 2017.
10.12 Severance Pay Agreement between Sempra Energy and Hal D. Snyder, dated March 1, 2017.
San Diego Gas & Electric Company / Southern California Gas Company
10.13 Severance Pay Agreement between Sempra Energy and John C. Baker, dated March 1, 2017.
10.14 Severance Pay Agreement between Sempra Energy and Lee Schavrien, dated March 1, 2017.
10.15 Severance Pay Agreement between Sempra Energy and Bruce A. Folkmann, dated March 1, 2017.
EXHIBIT 12 -- STATEMENTS RE: COMPUTATION OF RATIOS
Sempra Energy
12.1 Sempra Energy Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
San Diego Gas & Electric Company
12.2 San Diego Gas & Electric Company Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
Southern California Gas Company
12.3 Southern California Gas Company Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.
EXHIBIT 31 -- SECTION 302 CERTIFICATIONS
Sempra Energy
31.1 Certification of Sempra Energy’s Principal Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.2 Certification of Sempra Energy’s Principal Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
San Diego Gas & Electric Company
31.3 Certification of San Diego Gas & Electric Company’s Principal Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.4 Certification of San Diego Gas & Electric Company’s Principal Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
Southern California Gas Company
31.5 Certification of Southern California Gas Company’s Principal Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.


31.6 Certification of Southern California Gas Company’s Principal Financial Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
EXHIBIT 32 -- SECTION 906 CERTIFICATIONS
Sempra Energy
32.1 Certification of Sempra Energy’s Principal Executive Officer pursuant to 18 U.S.C. Sec. 1350.
32.2 Certification of Sempra Energy’s Principal Financial Officer pursuant to 18 U.S.C. Sec. 1350.
San Diego Gas & Electric Company
32.3 Certification of San Diego Gas & Electric Company’s Principal Executive Officer pursuant to 18 U.S.C. Sec. 1350.
32.4 Certification of San Diego Gas & Electric Company’s Principal Financial Officer pursuant to 18 U.S.C. Sec. 1350.
Southern California Gas Company
32.5 Certification of Southern California Gas Company’s Principal Executive Officer pursuant to 18 U.S.C. Sec. 1350.
32.6 Certification of Southern California Gas Company’s Principal Financial Officer pursuant to 18 U.S.C. Sec. 1350.
EXHIBIT 101 -- INTERACTIVE DATA FILE
Sempra Energy / San Diego Gas & Electric Company / Southern California Gas Company
101.INS XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
 10.1Form of Indemnification Agreement with Directors and Executive Officers (executed
 after January 2011).
EXHIBIT 12 -- STATEMENTS RE: COMPUTATION OF RATIOS
Sempra Energy
12.1Sempra Energy Computation of Ratio of Earnings to Combined Fixed Charges and Preferred
Stock Dividends.
San Diego Gas & Electric Company
12.2San Diego Gas & Electric Company Computation of Ratio of Earnings to Combined
Fixed Charges and Preferred Stock Dividends.
Southern California Gas Company
12.3Southern California Gas Company Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends.
EXHIBIT 31 -- SECTION 302 CERTIFICATIONS
Sempra Energy
31.1Statement of Sempra Energy’s Chief Executive Officer pursuant to Rules 13a-14 and 15d-14
of the Securities Exchange Act of 1934.
31.2Statement of Sempra Energy’s Chief Financial Officer pursuant to Rules 13a-14 and 15d-14
of the Securities Exchange Act of 1934.
San Diego Gas & Electric Company
31.3Statement of San Diego Gas & Electric Company’s Chief Executive Officer pursuant to Rules
13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.4Statement of San Diego Gas & Electric Company’s Chief Financial Officer pursuant to Rules
13a-14 and 15d-14 of the Securities Exchange Act of 1934.
Southern California Gas Company
31.5Statement of Southern California Gas Company’s Chief Executive Officer pursuant to Rules
13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.6Statement of Southern California Gas Company’s Chief Financial Officer pursuant to Rules
13a-14 and 15d-14 of the Securities Exchange Act of 1934.
EXHIBIT 32 -- SECTION 906 CERTIFICATIONS
Sempra Energy
32.1Statement of Sempra Energy’s Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.
32.2Statement of Sempra Energy’s Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
San Diego Gas & Electric Company
32.3Statement of San Diego Gas & Electric Company’s Chief Executive Officer pursuant to 18
U.S.C. Sec. 1350.
32.4Statement of San Diego Gas & Electric Company’s Chief Financial Officer pursuant to 18
U.S.C. Sec. 1350.
Southern California Gas Company
32.5Statement of Southern California Gas Company’s Chief Executive Officer pursuant to 18
U.S.C. Sec. 1350.
32.6Statement of Southern California Gas Company’s Chief Financial Officer pursuant to 18
U.S.C. Sec. 1350.
EXHIBIT 101 -- INTERACTIVE DATA FILE
Sempra Energy / San Diego Gas & Electric Company / Southern California Gas Company
  101.INSXBRL Instance Document
101.SCHXBRL Taxonomy Extension Schema Document
 
101.CALXBRL Taxonomy Extension Calculation Linkbase Document
 
101.DEFXBRL Taxonomy Extension Definition Linkbase Document
 
101.LABXBRL Taxonomy Extension Label Linkbase Document
 
101.PREXBRL Taxonomy Extension Presentation Linkbase Document



SIGNATURES
SIGNATURES
Sempra Energy:
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
SEMPRA ENERGY,
(Registrant)
  
Date: May 4, 20169, 2017By:  /s/ Trevor I. Mihalik
 
Trevor I. Mihalik
Senior Vice President, Controller and
Chief Accounting Officer

San Diego Gas & Electric Company:
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
SAN DIEGO GAS & ELECTRIC COMPANY,
(Registrant)
  
Date: May 4, 20169, 2017By:  /s/ Bruce A. Folkmann
 
Bruce A. Folkmann
Vice President, Controller, Chief Financial Officer and Chief Accounting Officer

Southern California Gas Company:
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
SOUTHERN CALIFORNIA GAS COMPANY,
(Registrant)
  
Date: May 4, 20169, 2017By:  /s/ Bruce A. Folkmann
 
Bruce A. Folkmann
Vice President, Controller, Chief Financial Officer and Chief Accounting Officer



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