Sempra Energy/SDG&E/SoCalGas 9/30/2012 10-Q


  
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 ended
September 30, 2012
   
 
or
   
[   ]
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from
   
to
 
     
 
Commission File No.
Exact Name of Registrants as Specified in their Charters, Address and Telephone Number
States of Incorporation
I.R.S. Employer
Identification Nos.
Former name, former address and former fiscal year, if changed since last report
1-14201
SEMPRA ENERGY
California
33-0732627
No change
 
101 Ash Street
     
 
San Diego, California 92101
     
 
(619)696-2000
     
         
1-03779
SAN DIEGO GAS & ELECTRIC COMPANY
California
95-1184800
No change
 
8326 Century Park Court
     
 
San Diego, California 92123
     
 
(619)696-2000
     
         
1-01402
SOUTHERN CALIFORNIA GAS COMPANY
California
95-1240705
No 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.
           
 
Yes
X
 
No
 

 
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 Energy
Yes
X
 
No
 
San Diego Gas & Electric Company
Yes
X
 
No
 
Southern California Gas Company
Yes
X
 
No
 
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
 
 
Large
accelerated filer
Accelerated filer
Non-accelerated filer
Smaller reporting company
Sempra Energy
[  X  ]
[      ]
[       ]
[      ]
San Diego Gas & Electric Company
[       ]
[      ]
[  X  ]
[      ]
Southern California Gas Company
[       ]
[      ]
[  X  ]
[      ]
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
           
Sempra Energy
Yes
   
No
X
San Diego Gas & Electric Company
Yes
   
No
X
Southern California Gas Company
Yes
   
No
X
           
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 November 1, 2012:
         
           
Sempra Energy
241,851,686 shares
San Diego Gas & Electric Company
Wholly owned by Enova Corporation, which is wholly owned by Sempra Energy
Southern California Gas Company
Wholly owned by Pacific Enterprises, which is wholly owned by Sempra Energy
 
 
 
 
 
 
 

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 Statements
4
   
PART I – FINANCIAL INFORMATION
 
Item 1.
Financial Statements
5
Item 2.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
73
Item 3.
Quantitative and Qualitative Disclosures About Market Risk
111
Item 4.
Controls and Procedures
112
     
PART II – OTHER INFORMATION
 
Item 1.
Legal Proceedings
113
Item 1A.
Risk Factors
113
Item 6.
Exhibits
115
     
Signatures
117
     

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.
 
In this report, when we use words such as “believes,” “expects,” “anticipates,” “plans,” “estimates,” “projects,” “contemplates,” “intends,” “depends,” “should,” “could,” “would,” “will,” “may,” “potential,” “target,” “pursue,” “goals,” or similar expressions, or when we discuss our guidance, strategy, plans, goals, 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 and regulatory conditions and developments;
 
§  
actions and the timing of actions by the California Public Utilities Commission, California State Legislature, Federal Energy Regulatory Commission, U.S. Department of Energy, Nuclear Regulatory Commission, California Energy Commission, California Air Resources Board, and other regulatory, governmental and environmental bodies in the United States and other countries in which we operate;
 
§  
capital markets conditions, including the availability of credit and the liquidity of our investments;
 
§  
inflation, interest and exchange rates;
 
§  
the impact of benchmark interest rates, generally U.S. Treasury bond and Moody’s A-rated utility bond yields, on our California Utilities’ cost of capital;
 
§  
the timing and success of business development efforts and construction, maintenance and capital projects, including risks inherent in the ability to obtain, and the timing of granting of, permits, licenses, certificates and other authorizations;
 
§  
energy markets, including the timing and extent of changes and volatility in commodity prices;
 
§  
the availability of electric power, natural gas and liquefied natural gas, including disruptions caused by failures in the North American transmission grid, pipeline explosions and equipment failures;
 
§  
weather conditions, natural disasters, catastrophic accidents, and conservation efforts;
 
§  
risks inherent in nuclear power generation and radioactive materials storage, including the catastrophic release of such materials, the disallowance of the recovery of the investment in or operating costs of the generation facility due to an extended outage, and increased regulatory oversight;
 
§  
risks posed by decisions and actions of third parties who control the operations of investments in which we do not have a controlling interest;
 
§  
wars, terrorist attacks and cybersecurity threats;
 
§  
business, regulatory, environmental and legal decisions and requirements;
 
§  
expropriation of assets by foreign governments and title and other property disputes;
 
§  
the status of deregulation of retail natural gas and electricity delivery;
 
§  
the inability or determination not to enter into long-term supply and sales agreements or long-term firm capacity agreements;
 
§  
the resolution of litigation; and
 
§  
other uncertainties, all of which are 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 in this report and in our 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 September 30,
Nine months ended September 30,
   
2012 
2011(1)
2012 
2011(1)
   
(unaudited)
REVENUES
               
Utilities
$
 2,170 
$
 2,065 
$
 6,099 
$
 5,933 
Energy-related businesses
 
 337 
 
 511 
 
 880 
 
 1,499 
    Total revenues
 
 2,507 
 
 2,576 
 
 6,979 
 
 7,432 
EXPENSES AND OTHER INCOME
               
Utilities:
               
    Cost of natural gas
 
 (212)
 
 (322)
 
 (864)
 
 (1,367)
    Cost of electric fuel and purchased power
 
 (515)
 
 (408)
 
 (1,252)
 
 (976)
Energy-related businesses:
               
    Cost of natural gas, electric fuel and purchased power
 
 (136)
 
 (252)
 
 (346)
 
 (694)
    Other cost of sales
 
 (43)
 
 (68)
 
 (117)
 
 (123)
Operation and maintenance
 
 (732)
 
 (691)
 
 (2,123)
 
 (2,003)
Depreciation and amortization
 
 (280)
 
 (251)
 
 (803)
 
 (729)
Franchise fees and other taxes
 
 (89)
 
 (84)
 
 (264)
 
 (259)
Equity (losses) earnings, before income tax:
               
    Rockies Express Pipeline LLC
 
 (87)
 
 10 
 
 (366)
 
 29 
    Other
 
 (7)
 
 (22)
 
 (9)
 
 (33)
Remeasurement of equity method investments
 
 ― 
 
 ― 
 
 ― 
 
 277 
Other income, net
 
 44 
 
 12 
 
 137 
 
 86 
Interest income
 
 5 
 
 6 
 
 14 
 
 21 
Interest expense
 
 (126)
 
 (118)
 
 (352)
 
 (344)
Income before income taxes and equity earnings
               
    of certain unconsolidated subsidiaries
 
 329 
 
 388 
 
 634 
 
 1,317 
Income tax expense
 
 (49)
 
 (75)
 
 (48)
 
 (289)
Equity earnings, net of income tax
 
 10 
 
 6 
 
 29 
 
 45 
Net income
 
 290 
 
 319 
 
 615 
 
 1,073 
Earnings attributable to noncontrolling interests
 
 (20)
 
 (29)
 
 (44)
 
 (21)
Preferred dividends of subsidiaries
 
 (2)
 
 (1)
 
 (5)
 
 (6)
Earnings
$
 268 
$
 289 
$
 566 
$
 1,046 
                   
Basic earnings per common share
$
 1.11 
$
 1.21 
$
 2.35 
$
 4.36 
Weighted-average number of shares outstanding, basic (thousands)
 
 241,689 
 
 239,545 
 
 241,133 
 
 239,693 
                   
Diluted earnings per common share
$
 1.09 
$
 1.20 
$
 2.31 
$
 4.32 
Weighted-average number of shares outstanding, diluted (thousands)
 
 245,802 
 
 241,880 
 
 245,013 
 
 241,955 
Dividends declared per share of common stock
$
 0.60 
$
 0.48 
$
 1.80 
$
 1.44 
(1)
As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
See Notes to Condensed Consolidated Financial Statements.
               
 
 

 
SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
   
Three months ended September 30,
   
2012
 
2011(1)
   
(unaudited)
     
Non-
     
Non-
 
   
Sempra
controlling
   
Sempra
controlling
 
   
Energy
Interests
Total
 
Energy
Interests
Total
Net income
$
 270 
$
 20 
$
 290 
 
$
 290 
$
 29 
$
 319 
Other comprehensive income (loss), net of tax:
                         
    Foreign currency translation adjustments
 
 80 
 
 8 
 
 88 
   
 (132)
 
 (7)
 
 (139)
    Net actuarial (loss) gain
 
 (10)
 
 ― 
 
 (10)
   
 1 
 
 ― 
 
 1 
    Financial instruments
 
 (3)
 
 (4)
 
 (7)
   
 (14)
 
 (25)
 
 (39)
Total other comprehensive income (loss)
 
 67 
 
 4 
 
 71 
   
 (145)
 
 (32)
 
 (177)
Total comprehensive income (loss)
 
 337 
 
 24 
 
 361 
   
 145 
 
 (3)
 
 142 
Preferred dividends of subsidiaries
 
 (2)
 
 ― 
 
 (2)
   
 (1)
 
 ― 
 
 (1)
Total comprehensive income (loss), after preferred
                         
    dividends of subsidiaries
$
 335 
$
 24 
$
 359 
 
$
 144 
$
 (3)
$
 141 
   
Nine months ended September 30,
   
2012
 
2011(1)
   
(unaudited)
     
Non-
     
Non-
 
   
Sempra
controlling
   
Sempra
controlling
 
   
Energy
Interests
Total
 
Energy
Interests
Total
Net income
$
 571 
$
 44 
$
 615 
 
$
 1,052 
$
 21 
$
 1,073 
Other comprehensive income (loss), net of tax:
                         
    Foreign currency translation adjustments
 
 114 
 
 11 
 
 125 
   
 (109)
 
 (1)
 
 (110)
    Reclassification to net income of foreign currency
                         
        translation adjustments related to equity
                         
        method investments(2)
 
 ― 
 
 ― 
 
 ― 
   
 (54)
 
 ― 
 
 (54)
    Net actuarial (loss) gain
 
 (5)
 
 ― 
 
 (5)
   
 8 
 
 ― 
 
 8 
    Financial instruments
 
 (9)
 
 (13)
 
 (22)
   
 (18)
 
 (34)
 
 (52)
Total other comprehensive income (loss)
 
 100 
 
 (2)
 
 98 
   
 (173)
 
 (35)
 
 (208)
Total comprehensive income (loss)
 
 671 
 
 42 
 
 713 
   
 879 
 
 (14)
 
 865 
Preferred dividends of subsidiaries
 
 (5)
 
 ― 
 
 (5)
   
 (6)
 
 ― 
 
 (6)
Total comprehensive income (loss), after preferred
                         
    dividends of subsidiaries
$
 666 
$
 42 
$
 708 
 
$
 873 
$
 (14)
$
 859 
(1)
As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
(2)
Related to the acquisition of Chilquinta Energía and Luz del Sur.
See Notes to Condensed Consolidated Financial Statements.
 
 
 
 
 

SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
   
September 30,
December 31,
 
2012 
2011(1)(2)
   
(unaudited)
   
ASSETS
       
Current assets:
       
    Cash and cash equivalents
$
 530 
$
 252 
    Restricted cash
 
 42 
 
 24 
    Trade accounts receivable, net
 
 922 
 
 1,198 
    Other accounts and notes receivable, net
 
 152 
 
 147 
    Income taxes receivable
 
 18 
 
 ― 
    Inventories
 
 398 
 
 346 
    Regulatory balancing accounts — undercollected
 
 301 
 
 38 
    Regulatory assets
 
 88 
 
 89 
    Fixed-price contracts and other derivatives
 
 74 
 
 85 
    U.S. Treasury grants receivable
 
 181 
 
 ― 
    Settlements receivable related to wildfire litigation
 
 180 
 
 10 
    Other
 
 192 
 
 143 
        Total current assets
 
 3,078 
 
 2,332 
           
Investments and other assets:
       
    Restricted cash
 
 20 
 
 22 
    Regulatory assets arising from pension and other postretirement
       
        benefit obligations
 
 1,027 
 
 1,126 
    Regulatory assets arising from wildfire litigation costs
 
 326 
 
 594 
    Other regulatory assets
 
 1,155 
 
 1,060 
    Nuclear decommissioning trusts
 
 892 
 
 804 
    Investments
 
 1,585 
 
 1,671 
    Goodwill
 
 1,109 
 
 1,036 
    Other intangible assets
 
 441 
 
 448 
    Sundry
 
 767 
 
 691 
        Total investments and other assets
 
 7,322 
 
 7,452 
           
Property, plant and equipment:
       
    Property, plant and equipment
 
 33,251 
 
 31,192 
    Less accumulated depreciation and amortization
 
 (8,261)
 
 (7,727)
        Property, plant and equipment, net ($473 and $494 at September 30, 2012 and
            December 31, 2011, respectively, related to VIE)
 
 24,990 
 
 23,465 
Total assets
$
 35,390 
$
 33,249 
(1)
As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
(2)
Derived from audited financial statements.
       
See Notes to Condensed Consolidated Financial Statements.
       
         
         
         
         

SEMPRA ENERGY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
   
September 30,
December 31,
 
2012 
2011(1)(2)
   
(unaudited)
   
LIABILITIES AND EQUITY
       
Current liabilities:
       
    Short-term debt
$
 584 
$
 449 
    Accounts payable — trade
 
 970 
 
 983 
    Accounts payable — other
 
 126 
 
 124 
    Income taxes payable
 
 ― 
 
 5 
    Deferred income taxes
 
 155 
 
 173 
    Dividends and interest payable
 
 309 
 
 219 
    Accrued compensation and benefits
 
 273 
 
 323 
    Regulatory balancing accounts — overcollected
 
 117 
 
 105 
    Current portion of long-term debt
 
 709 
 
 336 
    Fixed-price contracts and other derivatives
 
 82 
 
 92 
    Customer deposits
 
 150 
 
 142 
    Reserve for wildfire litigation
 
 284 
 
 586 
    Other
 
 590 
 
 615 
        Total current liabilities
 
 4,349 
 
 4,152 
Long-term debt ($337 and $345 at September 30, 2012 and December 31, 2011, respectively,
        related to VIE)
 
 11,193 
 
 10,078 
           
Deferred credits and other liabilities:
       
    Customer advances for construction
 
 146 
 
 142 
    Pension and other postretirement benefit obligations, net of plan assets
 
 1,337 
 
 1,423 
    Deferred income taxes
 
 1,609 
 
 1,520 
    Deferred investment tax credits
 
 47 
 
 49 
    Regulatory liabilities arising from removal obligations
 
 2,673 
 
 2,551 
    Asset retirement obligations
 
 1,981 
 
 1,905 
    Other regulatory liabilities
 
 55 
 
 87 
    Fixed-price contracts and other derivatives
 
 270 
 
 301 
    Reserve for wildfire litigation
 
 127 
 
 10 
    Deferred credits and other
 
 1,028 
 
 774 
        Total deferred credits and other liabilities
 
 9,273 
 
 8,762 
Contingently redeemable preferred stock of subsidiary
 
 79 
 
 79 
           
Commitments and contingencies (Note 10)
       
           
Equity:
       
    Preferred stock (50 million shares authorized; none issued)
 
 ― 
 
 ― 
    Common stock (750 million shares authorized; 242 million and 240 million shares
       
        outstanding at September 30, 2012 and December 31, 2011, respectively; no par value)
 
 2,178 
 
 2,104 
    Retained earnings
 
 8,293 
 
 8,162 
    Deferred compensation
 
 ― 
 
 (2)
    Accumulated other comprehensive income (loss)
 
 (389)
 
 (489)
        Total Sempra Energy shareholders’ equity
 
 10,082 
 
 9,775 
    Preferred stock of subsidiary
 
 20 
 
 20 
    Other noncontrolling interests
 
 394 
 
 383 
        Total equity
 
 10,496 
 
 10,178 
Total liabilities and equity
$
 35,390 
$
 33,249 
(1)
As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
(2)
Derived from audited financial statements.
       
See Notes to Condensed Consolidated Financial Statements.
       
         
         
         
         

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
   
Nine months ended September 30,
   
2012 
2011(1)
   
(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
       
    Net income
$
 615 
$
 1,073 
    Adjustments to reconcile net income to net cash provided
       
        by operating activities:
       
            Depreciation and amortization
 
 803 
 
 729 
            Deferred income taxes and investment tax credits
 
 (45)
 
 211 
            Equity losses (earnings)
 
 346 
 
 (41)
            Remeasurement of equity method investments
 
 ― 
 
 (277)
            Fixed-price contracts and other derivatives
 
 1 
 
 (7)
            Other
 
 (8)
 
 (43)
    Net change in other working capital components
 
 (373)
 
 (75)
    Distributions from RBS Sempra Commodities LLP
 
 ― 
 
 53 
    Changes in other assets
 
 202 
 
 31 
    Changes in other liabilities
 
 147 
 
 (11)
        Net cash provided by operating activities
 
 1,688 
 
 1,643 
           
CASH FLOWS FROM INVESTING ACTIVITIES
       
    Expenditures for property, plant and equipment
 
 (2,241)
 
 (2,031)
    Expenditures for investments and acquisition of businesses, net of cash acquired
 
 (359)
 
 (696)
    Proceeds from sale of joint venture interest
 
 9 
 
 ― 
    Distributions from RBS Sempra Commodities LLP
 
 ― 
 
 374 
    Distributions from other investments
 
 43 
 
 47 
    Purchases of nuclear decommissioning and other trust assets
 
 (534)
 
 (399)
    Proceeds from sales by nuclear decommissioning and other trusts
 
 534 
 
 398 
    Decrease in restricted cash
 
 89 
 
 473 
    Increase in restricted cash
 
 (105)
 
 (450)
    Other
 
 (12)
 
 (20)
        Net cash used in investing activities
 
 (2,576)
 
 (2,304)
           
CASH FLOWS FROM FINANCING ACTIVITIES
       
    Common dividends paid
 
 (405)
 
 (325)
    Redemption of subsidiary preferred stock
 
 ― 
 
 (80)
    Preferred dividends paid by subsidiaries
 
 (5)
 
 (6)
    Issuances of common stock
 
 50 
 
 22 
    Repurchases of common stock
 
 (16)
 
 (18)
    Issuances of debt (maturities greater than 90 days)
 
 2,294 
 
 1,525 
    Payments on debt (maturities greater than 90 days)
 
 (563)
 
 (366)
    Decrease in short-term debt, net
 
 (142)
 
 (300)
    Purchase of noncontrolling interests
 
 ― 
 
 (43)
    Distributions to noncontrolling interests
 
 (36)
 
 (10)
    Other
 
 (20)
 
 5 
        Net cash provided by financing activities
 
 1,157 
 
 404 
           
Effect of exchange rate changes on cash and cash equivalents
 
 9 
 
 2 
           
Increase (decrease) in cash and cash equivalents
 
 278 
 
 (255)
Cash and cash equivalents, January 1
 
 252 
 
 912 
Cash and cash equivalents, September 30
$
 530 
$
 657 
(1)
As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
See Notes to Condensed Consolidated Financial Statements.
 
   
   
   
   

SEMPRA ENERGY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
   
Nine months ended September 30,
 
2012 
2011 
 
(unaudited)
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
       
    Interest payments, net of amounts capitalized
$
 278 
$
 281 
    Income tax payments, net of refunds
 
 99 
 
 106 
           
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
       
  Acquisition of businesses:
       
       Assets acquired
$
 29 
$
 2,831 
       Cash paid, net of cash acquired
 
 (19)
 
 (611)
       Fair value of equity method investments immediately prior to the acquisition
 
 ― 
 
 (882)
       Fair value of noncontrolling interests
 
 ― 
 
 (279)
       Additional consideration accrued
 
 ― 
 
 (32)
       Liabilities assumed
$
 10 
$
 1,027 
         
    Accrued capital expenditures
$
 315 
$
 306 
    U.S. Treasury grants receivable(1)
 
 136 
 
 ― 
           
SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES
       
    Dividends declared but not paid
$
 149 
$
 119 
(1)
Cash grants, excluding $45 million previously recorded in 2011 as investment tax credits.
See Notes to Condensed Consolidated Financial Statements.
 
 
 
 
SAN DIEGO GAS & ELECTRIC COMPANY
       
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
       
(Dollars in millions)
       
     
 
Three months ended September 30,
Nine months ended September 30,
 
2012 
2011 
2012 
2011 
 
(unaudited)
Operating revenues
               
    Electric
$
 998 
$
 763 
$
 2,349 
$
 2,011 
    Natural gas
 
 94 
 
 105 
 
 357 
 
 394 
        Total operating revenues
 
 1,092 
 
 868 
 
 2,706 
 
 2,405 
Operating expenses
               
    Cost of electric fuel and purchased power
 
 301 
 
 207 
 
 604 
 
 534 
    Cost of natural gas
 
 29 
 
 40 
 
 130 
 
 175 
    Operation and maintenance
 
 309 
 
 255 
 
 852 
 
 756 
    Depreciation and amortization
 
 128 
 
 108 
 
 359 
 
 316 
    Franchise fees and other taxes
 
 55 
 
 48 
 
 144 
 
 138 
        Total operating expenses
 
 822 
 
 658 
 
 2,089 
 
 1,919 
Operating income
 
 270 
 
 210 
 
 617 
 
 486 
Other income, net
 
 5 
 
 26 
 
 59 
 
 55 
Interest expense
 
 (49)
 
 (37)
 
 (124)
 
 (104)
Income before income taxes
 
 226 
 
 199 
 
 552 
 
 437 
Income tax expense
 
 (38)
 
 (63)
 
 (151)
 
 (154)
Net income
 
 188 
 
 136 
 
 401 
 
 283 
Earnings attributable to noncontrolling interest
 
 (12)
 
 (21)
 
 (23)
 
 (6)
Earnings
 
 176 
 
 115 
 
 378 
 
 277 
Preferred dividend requirements
 
 (2)
 
 (2)
 
 (4)
 
 (4)
Earnings attributable to common shares
$
 174 
$
 113 
$
 374 
$
 273 
See Notes to Condensed Consolidated Financial Statements.
       
 
 

 

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
 
Three months ended September 30,
 
2012
 
2011
 
(unaudited)
   
Non-
     
Non-
 
   
controlling
     
controlling
 
 
SDG&E
Interest
Total
 
SDG&E
Interest
Total
Net income
$
 176 
$
 12 
$
 188 
 
$
 115 
$
 21 
$
 136 
Other comprehensive income (loss), net of tax:
                         
    Net actuarial gain
 
 ― 
 
 ― 
 
 ― 
   
 1 
 
 ― 
 
 1 
    Financial instruments
 
 ― 
 
 (4)
 
 (4)
   
 ― 
 
 (25)
 
 (25)
Total other comprehensive income (loss)
 
 ― 
 
 (4)
 
 (4)
   
 1 
 
 (25)
 
 (24)
Total comprehensive income (loss)
$
 176 
$
 8 
$
 184 
 
$
 116 
$
 (4)
$
 112 
 
Nine months ended September 30,
 
2012
 
2011
 
(unaudited)
   
Non-
     
Non-
 
   
controlling
     
controlling
 
 
SDG&E
Interest
Total
 
SDG&E
Interest
Total
Net income
$
 378 
$
 23 
$
 401 
 
$
 277 
$
 6 
$
 283 
Other comprehensive income (loss), net of tax:
                         
    Net actuarial gain
 
 ― 
 
 ― 
 
 ― 
   
 1 
 
 ― 
 
 1 
    Financial instruments
 
 ― 
 
 (13)
 
 (13)
   
 ― 
 
 (34)
 
 (34)
Total other comprehensive income (loss)
 
 ― 
 
 (13)
 
 (13)
   
 1 
 
 (34)
 
 (33)
Total comprehensive income (loss)
$
 378 
$
 10 
$
 388 
 
$
 278 
$
 (28)
$
 250 
See Notes to Condensed Consolidated Financial Statements.
 
 
 
 

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
   
September 30,
December 31,
   
2012 
2011(1)
   
(unaudited)
   
ASSETS
       
Current assets:
       
    Cash and cash equivalents
$
 22 
$
 29 
    Restricted cash
 
 11 
 
 21 
    Accounts receivable – trade, net
 
 294 
 
 267 
    Accounts receivable – other, net
 
 20 
 
 23 
    Due from unconsolidated affiliates
 
 17 
 
 67 
    Income taxes receivable
 
 171 
 
 102 
    Inventories
 
 83 
 
 82 
    Regulatory balancing accounts, net
 
 301 
 
 38 
    Regulatory assets arising from fixed-price contracts and other derivatives
 
 63 
 
 67 
    Other regulatory assets
 
 11 
 
 11 
    Fixed-price contracts and other derivatives
 
 25 
 
 27 
    Settlements receivable related to wildfire litigation
 
 180 
 
 10 
    Other
 
 109 
 
 51 
        Total current assets
 
 1,307 
 
 795 
           
Other assets:
       
    Restricted cash
 
 20 
 
 22 
    Deferred taxes recoverable in rates
 
 647 
 
 570 
    Regulatory assets arising from fixed-price contracts and other derivatives
 
 138 
 
 191 
    Regulatory assets arising from pension and other postretirement
       
        benefit obligations
 
 287 
 
 309 
    Regulatory assets arising from wildfire litigation costs
 
 326 
 
 594 
    Other regulatory assets
 
 252 
 
 160 
    Nuclear decommissioning trusts
 
 892 
 
 804 
    Sundry
 
 89 
 
 70 
        Total other assets
 
 2,651 
 
 2,720 
           
Property, plant and equipment:
       
    Property, plant and equipment
 
 13,827 
 
 13,003 
    Less accumulated depreciation and amortization
 
 (3,196)
 
 (2,963)
        Property, plant and equipment, net ($473 and $494 at September 30, 2012 and
            December 31, 2011, respectively, related to VIE)
 
 10,631 
 
 10,040 
Total assets
$
 14,589 
$
 13,555 
(1)
Derived from audited financial statements.
       
See Notes to Condensed Consolidated Financial Statements.
       
         
         
         
         

SAN DIEGO GAS & ELECTRIC COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
   
September 30,
December 31,
   
2012 
2011(1)
   
(unaudited)
   
LIABILITIES AND EQUITY
       
Current liabilities:
       
    Short-term debt
$
 2 
$
 ― 
    Accounts payable
 
 304 
 
 375 
    Due to unconsolidated affiliate
 
 20 
 
 14 
    Deferred income taxes
 
 54 
 
 62 
    Dividends and interest payable
 
 55 
 
 32 
    Accrued compensation and benefits
 
 93 
 
 124 
    Current portion of long-term debt
 
 19 
 
 19 
    Fixed-price contracts and other derivatives
 
 54 
 
 55 
    Customer deposits
 
 63 
 
 62 
    Reserve for wildfire litigation
 
 284 
 
 586 
    Other
 
 117 
 
 107 
        Total current liabilities
 
 1,065 
 
 1,436 
Long-term debt ($337 and $345 at September 30, 2012 and December 31, 2011,
    respectively, related to VIE)
 
 4,293 
 
 4,058 
           
Deferred credits and other liabilities:
       
    Customer advances for construction
 
 18 
 
 20 
    Pension and other postretirement benefit obligations, net of plan assets
 
 323 
 
 342 
    Deferred income taxes
 
 1,515 
 
 1,167 
    Deferred investment tax credits
 
 26 
 
 26 
    Regulatory liabilities arising from removal obligations
 
 1,575 
 
 1,462 
    Asset retirement obligations
 
 724 
 
 693 
    Fixed-price contracts and other derivatives
 
 220 
 
 243 
    Reserve for wildfire litigation
 
 127 
 
 10 
    Deferred credits and other
 
 421 
 
 178 
        Total deferred credits and other liabilities
 
 4,949 
 
 4,141 
Contingently redeemable preferred stock
 
 79 
 
 79 
           
Commitments and contingencies (Note 10)
       
           
Equity:
       
    Common stock (255 million shares authorized; 117 million shares outstanding;
       
        no par value)
 
 1,338 
 
 1,338 
    Retained earnings
 
 2,785 
 
 2,411 
    Accumulated other comprehensive income (loss)
 
 (10)
 
 (10)
        Total SDG&E shareholder's equity
 
 4,113 
 
 3,739 
    Noncontrolling interest
 
 90 
 
 102 
        Total equity
 
 4,203 
 
 3,841 
Total liabilities and equity
$
 14,589 
$
 13,555 
(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)
 
Nine months ended
September 30,
 
2012 
2011
 
(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
       
    Net income
$
 401 
$
 283 
    Adjustments to reconcile net income to net cash provided by
       
        operating activities:
       
            Depreciation and amortization
 
 359 
 
 316 
            Deferred income taxes and investment tax credits
 
 262 
 
 226 
            Fixed price contracts and other derivatives
 
 (9)
 
 (13)
            Other
 
 (55)
 
 (43)
    Net change in other working capital components
 
 (518)
 
 18 
    Changes in other assets
 
 201 
 
 32 
    Changes in other liabilities
 
 129 
 
 ― 
        Net cash provided by operating activities
 
 770 
 
 819 
         
CASH FLOWS FROM INVESTING ACTIVITIES
       
    Expenditures for property, plant and equipment
 
 (998)
 
 (1,162)
    Purchases of nuclear decommissioning trust assets
 
 (530)
 
 (395)
    Proceeds from sales by nuclear decommissioning trusts
 
 524 
 
 389 
    Decrease in restricted cash
 
 74 
 
 340 
    Increase in restricted cash
 
 (62)
 
 (355)
        Net cash used in investing activities
 
 (992)
 
 (1,183)
         
CASH FLOWS FROM FINANCING ACTIVITIES
       
    Capital contribution
 
 ― 
 
 200 
    Capital (distribution) contribution at Otay Mesa VIE
 
 (22)
 
 5 
    Preferred dividends paid
 
 (4)
 
 (4)
    Issuance of long-term debt
 
 249 
 
 348 
    Payments on long-term debt
 
 (7)
 
 (7)
    Increase in short-term debt, net
 
 2 
 
 ― 
    Other
 
 (3)
 
 (2)
        Net cash provided by financing activities
 
 215 
 
 540 
         
(Decrease) increase in cash and cash equivalents
 
 (7)
 
 176 
Cash and cash equivalents, January 1
 
 29 
 
 127 
Cash and cash equivalents, September 30
$
 22 
$
 303 
         
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
       
    Interest payments, net of amounts capitalized
$
 96 
$
 80 
    Income tax (refunds) payments, net
 
 (121)
 
 59 
         
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
       
    Accrued capital expenditures
$
 87 
$
 161 
         
SUPPLEMENTAL DISCLOSURE OF NONCASH FINANCING ACTIVITIES
       
    Dividends declared but not paid
$
 1 
$
 1 
See Notes to Condensed Consolidated Financial Statements.
 
 
 
 
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
     
 
Three months ended September 30,
Nine months ended September 30,
 
2012 
2011 
2012 
2011 
 
(unaudited)
                 
Operating revenues
$
 728 
$
 844 
$
 2,328 
$
 2,776 
Operating expenses
               
    Cost of natural gas
 
 175 
 
 267 
 
 703 
 
 1,133 
    Operation and maintenance
 
 316 
 
 331 
 
 933 
 
 946 
    Depreciation and amortization
 
 91 
 
 83 
 
 268 
 
 246 
    Franchise fees and other taxes
 
 27 
 
 28 
 
 91 
 
 94 
        Total operating expenses
 
 609 
 
 709 
 
 1,995 
 
 2,419 
Operating income
 
 119 
 
 135 
 
 333 
 
 357 
Other income, net
 
 6 
 
 3 
 
 14 
 
 9 
Interest income
 
 ― 
 
 1 
 
 ― 
 
 1 
Interest expense
 
 (17)
 
 (17)
 
 (51)
 
 (52)
Income before income taxes
 
 108 
 
 122 
 
 296 
 
 315 
Income tax expense
 
 (37)
 
 (41)
 
 (105)
 
 (106)
Net income
 
 71 
 
 81 
 
 191 
 
 209 
Preferred dividend requirements
 
 ― 
 
 ― 
 
 (1)
 
 (1)
Earnings attributable to common shares
$
 71 
$
 81 
$
 190 
$
 208 
See Notes to Condensed Consolidated Financial Statements.
 
 
 

 
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Dollars in millions)
 
Three months ended September 30,
 
2012
 
2011
 
(unaudited)
Net income
$
 71 
 
$
 81 
Other comprehensive income, net of tax:
         
    Financial instruments
 
 ― 
   
 1 
Total other comprehensive income
 
 ― 
   
 1 
Total comprehensive income
$
 71 
 
$
 82 
 
Nine months ended September 30,
 
2012
 
2011
 
(unaudited)
Net income
$
 191 
 
$
 209 
Other comprehensive income, net of tax:
         
    Financial instruments
 
 1 
   
 2 
Total other comprehensive income
 
 1 
   
 2 
Total comprehensive income
$
 192 
 
$
 211 
See Notes to Condensed Consolidated Financial Statements.
 
 
 
 

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
   
September 30,
December 31,
   
2012 
2011(1)
   
(unaudited)
   
ASSETS
       
Current assets:
       
    Cash and cash equivalents
$
 257 
$
 36 
    Accounts receivable – trade, net
 
 273 
 
 578 
    Accounts receivable – other, net
 
 72 
 
 63 
    Due from unconsolidated affiliates
 
 280 
 
 40 
    Income taxes receivable
 
 19 
 
 17 
    Inventories
 
 166 
 
 151 
    Regulatory assets
 
 6 
 
 9 
    Other
 
 32 
 
 28 
        Total current assets
 
 1,105 
 
 922 
         
Other assets:
       
    Regulatory assets arising from pension and other postretirement
       
        benefit obligations
 
 730 
 
 808 
    Other regulatory assets
 
 117 
 
 137 
    Sundry
 
 11 
 
 8 
        Total other assets
 
 858 
 
 953 
         
Property, plant and equipment:
       
    Property, plant and equipment
 
 10,919 
 
 10,565 
    Less accumulated depreciation and amortization
 
 (4,098)
 
 (3,965)
        Property, plant and equipment, net
 
 6,821 
 
 6,600 
Total assets
$
 8,784 
$
 8,475 
(1)
Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.
 
 
 
 

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
   
September 30,
December 31,
   
2012 
2011(1)
   
(unaudited)
   
LIABILITIES AND SHAREHOLDERS' EQUITY
       
Current liabilities:
       
    Accounts payable – trade
$
 254 
$
 315 
    Accounts payable – other
 
 78 
 
 78 
    Due to unconsolidated affiliate
 
 16 
 
 2 
    Deferred income taxes
 
 42 
 
 44 
    Accrued compensation and benefits
 
 102 
 
 99 
    Regulatory balancing accounts, net
 
 117 
 
 105 
    Current portion of long-term debt
 
 254 
 
 257 
    Customer deposits
 
 76 
 
 75 
    Other
 
 129 
 
 172 
        Total current liabilities
 
 1,068 
 
 1,147 
Long-term debt
 
 1,409 
 
 1,064 
Deferred credits and other liabilities:
       
    Customer advances for construction
 
 113 
 
 110 
    Pension and other postretirement benefit obligations, net of plan assets
 
 756 
 
 833 
    Deferred income taxes
 
 652 
 
 576 
    Deferred investment tax credits
 
 21 
 
 23 
    Regulatory liabilities arising from removal obligations
 
 1,084 
 
 1,075 
    Asset retirement obligations
 
 1,197 
 
 1,161 
    Deferred taxes refundable in rates
 
 55 
 
 87 
    Deferred credits and other
 
 195 
 
 206 
        Total deferred credits and other liabilities
 
 4,073 
 
 4,071 
         
Commitments and contingencies (Note 10)
       
         
Shareholders' equity:
       
    Preferred stock
 
 22 
 
 22 
    Common stock (100 million shares authorized; 91 million shares outstanding;
       
        no par value)
 
 866 
 
 866 
    Retained earnings
 
 1,366 
 
 1,326 
    Accumulated other comprehensive income (loss)
 
 (20)
 
 (21)
        Total shareholders' equity
 
 2,234 
 
 2,193 
Total liabilities and shareholders' equity
$
 8,784 
$
 8,475 
(1)
Derived from audited financial statements.
See Notes to Condensed Consolidated Financial Statements.
 
 
 
 

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Dollars in millions)
 
Nine months ended September 30,
 
2012 
2011 
 
(unaudited)
CASH FLOWS FROM OPERATING ACTIVITIES
       
    Net income
$
 191 
$
 209 
    Adjustments to reconcile net income to net cash provided by
       
        operating activities:
       
            Depreciation and amortization
 
 268 
 
 246 
            Deferred income taxes and investment tax credits
 
 39 
 
 79 
            Other
 
 (9)
 
 (4)
    Net change in other working capital components
 
 240 
 
 (46)
    Changes in other assets
 
 4 
 
 17 
    Changes in other liabilities
 
 13 
 
 (6)
        Net cash provided by operating activities
 
 746 
 
 495 
         
CASH FLOWS FROM INVESTING ACTIVITIES
       
    Expenditures for property, plant and equipment
 
 (462)
 
 (499)
    Increase in loans to affiliates, net
 
 (257)
 
 (96)
        Net cash used in investing activities
 
 (719)
 
 (595)
         
CASH FLOWS FROM FINANCING ACTIVITIES
       
    Issuances of long-term debt
 
 348 
 
 ― 
    Common dividends paid
 
 (150)
 
 (50)
    Payment of long-term debt
 
 ― 
 
 (250)
    Preferred dividends paid
 
 (1)
 
 (1)
    Debt issuance costs
 
 (3)
 
 ― 
        Net cash provided by (used in) financing activities
 
 194 
 
 (301)
         
Increase (decrease) in cash and cash equivalents
 
 221 
 
 (401)
Cash and cash equivalents, January 1
 
 36 
 
 417 
Cash and cash equivalents, September 30
$
 257 
$
 16 
         
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
       
    Interest payments, net of amounts capitalized
$
 36 
$
 39 
    Income tax payments, net of refunds
 
 46 
 
 17 
         
SUPPLEMENTAL DISCLOSURE OF NONCASH INVESTING ACTIVITIES
       
    Accrued capital expenditures
$
 69 
$
 81 
See Notes to Condensed Consolidated Financial Statements.
 
 
 
 
SEMPRA ENERGY AND SUBSIDIARIES
 
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
 

NOTE 1. GENERAL
 

 
PRINCIPLES OF CONSOLIDATION
 
 
2012 Business Segment Realignment
 
Effective January 1, 2012, management realigned some of the company’s major subsidiaries to better fit its strategic direction and to enhance the management and integration of our assets. This realignment resulted in a change in reportable segments in 2012. In accordance with accounting principles generally accepted in the United States (GAAP), historical information for Sempra Energy has been restated in its Condensed Consolidated Financial Statements and these Notes to reflect the effect of this change. All discussions of our operating units and reportable segments in these Notes reflect the new segments and operating structure.
 
 
Sempra Energy
 
Sempra Energy’s Condensed Consolidated Financial Statements include the accounts of Sempra Energy, a California-based Fortune 500 holding company, and its consolidated subsidiaries and variable interest entities (VIEs). Sempra Energy’s principal operating units are
 
§  
San Diego Gas & Electric Company (SDG&E) and Southern California Gas Company (SoCalGas), which are separate, reportable segments;
 
§  
Sempra International, 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 Gas reportable segments.
 
We provide descriptions of each of our segments in Note 11.
 
We refer to SDG&E and SoCalGas collectively as the California Utilities, which do not include the utilities in our Sempra International and Sempra U.S. Gas & Power operating units. 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,” “Sempra U.S. Gas & Power” and their respective reportable segments are not intended to refer to any legal entity with the same or similar name.
 
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 subsidiaries in Note 4 herein and Note 4 of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2011 and in our Current Report on Form 8-K filed on May 11, 2012, discussed below under “Basis of Presentation.”
 
 
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 subsidiaries, which comprise less than one percent of its consolidated financial position and results of operations. SoCalGas’ common stock is wholly owned by Pacific Enterprises (PE), 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.
 
We have prepared the Condensed Consolidated Financial Statements in conformity with 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 September 30, 2012 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, 2011 balance sheet information in the Condensed Consolidated Financial Statements has been derived from our audited 2011 consolidated financial statements. Certain information and note disclosures normally included in annual financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to the interim-period-reporting provisions of GAAP and the Securities and Exchange Commission.
 
You should read the information in this Quarterly Report in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2011 (the Annual Report) and our Quarterly Reports on Form 10-Q for the quarters ended March 31 and June 30, 2012, which are combined reports for Sempra Energy, SDG&E and SoCalGas. You should also read the information in this Quarterly Report in conjunction with Sempra Energy’s Current Report on Form 8-K and accompanying exhibits, filed on May 11, 2012, which updates the information in the Annual Report primarily for the change in reportable segments (discussed above) and change in accounting principle (discussed below) and which we refer to in this Quarterly Report as the Updated Annual Report. Although the Updated Annual Report contains the separate information for SDG&E and SoCalGas, as filed in the Annual Report, the Form 8-K did not provide updates to their information as separate registrants as they were not impacted by the change in reportable segments or change in accounting principle at Sempra Energy.
 
Sempra South American Utilities has controlling interests in two electric distribution utilities in South America. Sempra Natural Gas owns Mobile Gas Service Corporation (Mobile Gas) in southwest Alabama and Willmut Gas Company (Willmut Gas) in Mississippi, and Sempra Mexico owns Ecogas Mexico, S de RL de CV (Ecogas) in Northern Mexico, all natural gas distribution utilities. The California Utilities, Sempra Natural Gas’ Mobile Gas and Willmut Gas, and Sempra Mexico’s Ecogas prepare their financial statements in accordance with GAAP provisions governing regulated operations, as we discuss in Note 1 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
We describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements in the Updated Annual Report. We follow the same accounting policies for interim reporting purposes, except for the adoption of new accounting standards as we discuss in Note 2.
 
 
Change in Accounting Principle
 
Effective January 1, 2012, we changed our method of accounting for investment tax credits (ITC) from the flow-through method to the deferral method for Sempra Energy. Under the flow-through method, we reduced our income tax expense by the amount of ITC in the year in which the qualifying assets were placed in service. Under the deferral method, we record ITC in the year when the qualifying assets are placed in service as a reduction to the cost of the asset that generated the ITC. This results in lower book depreciation over the life of the asset. This change has no historical or prospective impact on the California Utilities because ITC is effectively deferred as a result of the application of regulatory accounting required under GAAP.
 
The flow-through method and the deferral method are both acceptable under GAAP, but the deferral method is the preferred method. We believe that the deferral method is preferable for the ITC we receive because it recognizes ITC benefits over the same periods as the associated costs for which the ITC are intended to compensate.
 
We applied this change in accounting principle by retrospectively adjusting the historical financial statement amounts for all periods presented. Upon adopting the deferral method, we recorded an adjustment for the cumulative effect of the change in accounting principle to reduce Sempra Energy Consolidated retained earnings as of January 1, 2011 by $37 million.
 
For certain solar and wind generating assets being placed into service during 2011 and 2012, we have elected to seek cash grants rather than ITC for which the projects also qualify. Accordingly, cash grant accounting, which is similar to deferral accounting of ITC, is required to be applied. As a result, the impact of our change in accounting policy for ITC on our financial statements for the three months and nine months ending September 30, 2012 is insignificant. Cash grants are generally expected to be collectable in cash shortly after a project is constructed. Conversion of ITC to cash is generally dependent on reducing cash tax payments.
 
The following table summarizes the effects of the change in accounting principle on Sempra Energy’s Condensed Consolidated Financial Statements for the historical periods presented.
 


EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions, except per share amounts)
           
   
Three months ended September 30, 2011
     
As
       
     
Originally
     
Retrospectively
   
Reported
 
Adjustments
 
Adjusted
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
           
Income tax expense
$
68 
$
$
75 
Net income
 
326 
 
(7)
 
319 
Earnings
 
296 
 
(7)
 
289 
               
Basic earnings per common share
$
1.23 
$
(0.02)
$
1.21 
Diluted earnings per common share
$
1.22 
$
(0.02)
$
1.20 
               
   
Nine months ended September 30, 2011
     
As
       
     
Originally
     
Retrospectively
   
Reported
 
Adjustments
 
Adjusted
CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS
           
Depreciation and amortization
$
730 
$
(1)
$
729 
Income before income taxes and equity earnings
           
     of certain unconsolidated subsidiaries
 
1,316 
 
 
1,317 
Income tax expense
 
269 
 
20 
 
289 
Net income
 
1,092 
 
(19)
 
1,073 
Earnings
 
1,065 
 
(19)
 
1,046 
               
Basic earnings per common share
$
4.44 
$
(0.08)
$
4.36 
Diluted earnings per common share
$
4.40 
$
(0.08)
$
4.32 
               
CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS
           
Net income
$
1,092 
$
(19)
$
1,073 
Adjustments to reconcile net income to net cash provided by
           
     operating activities:
           
     Depreciation and amortization
 
730 
 
(1)
 
729 
     Deferred income taxes and investment tax credits
 
224 
 
(13)
 
211 
Net change in other working capital components (income taxes)
 
(108)
 
33 
 
(75)
               
   
As of December 31, 2011
     
As
       
     
Originally
     
Retrospectively
   
Reported
 
Adjustments
 
Adjusted
CONDENSED CONSOLIDATED BALANCE SHEET
           
Property, plant and equipment
$
31,303 
$
(111)
$
31,192 
Less accumulated depreciation and amortization
 
(7,731)
 
 
(7,727)
     Property, plant and equipment, net
$
23,572 
$
(107)
$
23,465 
               
Income taxes payable
$
16 
$
(11)
$
Deferred income taxes, noncurrent liability
 
1,554 
 
(34)
 
1,520 
Deferred credits and other
 
773 
 
 
774 
Retained earnings(1)
 
8,225 
 
(63)
 
8,162 
(1)
Adjustment includes the cumulative effect of the change in accounting principle of reductions in net income and earnings of $26 million, $30 million, a negligible amount, and $7 million for the years ended December 31, 2011, 2010, 2009 and 2008, respectively.

 
 
 

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) 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards (IFRSs)” (ASU 2011-04): ASU 2011-04 amends Accounting Standards Codification (ASC) Topic 820, Fair Value Measurements and Disclosures, and provides changes in the wording used to describe the requirements for measuring fair value and disclosing information about fair value measurement.  ASU 2011-04 results in common fair value measurement and disclosure requirements under both GAAP and IFRSs.
 
ASU 2011-04 expands fair value measurement disclosures for Level 3 instruments to require
 
§  
quantitative information about the unobservable inputs
 
§  
a description of the valuation process
 
§  
a qualitative discussion about the sensitivity of the measurements
 
We adopted ASU 2011-04 on January 1, 2012 and it did not affect our financial position, results of operations or cash flows.  The required disclosure is provided in Note 8.
 
ASU 2011-05, “Presentation of Comprehensive Income” (ASU 2011-05) and ASU 2011-12, “Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05” (ASU 2011-12): ASU 2011-05 amends ASC Topic 220, Comprehensive Income, and eliminates the option to report other comprehensive income and its components in the statement of changes in equity.  The ASU allows an entity an option to present the components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive, statements.
 
ASU 2011-05 does not change the items that must be reported in other comprehensive income, when an item of other comprehensive income must be reclassified to net income, or the earnings per share computation.
 
ASU 2011-12 defers the requirement to separately present on the face of the statement of operations or statement of comprehensive income reclassification adjustments for items that are reclassified from other comprehensive income to net income.
 
We adopted ASU 2011-05 on January 1, 2012 and have elected to present the components of net income and other comprehensive income in two separate, but consecutive, statements for all periods presented.
 
ASU 2011-11, “Disclosures about Offsetting Assets and Liabilities” (ASU 2011-11): In order to allow for balance sheet comparison between GAAP and IFRSs, ASU 2011-11 requires enhanced disclosures related to financial assets and liabilities eligible for offsetting in the statement of financial position.  An entity will have to disclose both gross and net information about financial instruments and transactions subject to a master netting arrangement and eligible for offset, including cash collateral received and posted.
 
We will adopt ASU 2011-11 on January 1, 2013 as required and do not expect it to affect our financial position, results of operations or cash flows. We will provide the additional disclosure in our 2013 interim financial statements.
 
ASU 2012-02, “Testing Indefinite-Lived Intangible Assets for Impairment” (ASU 2012-02): ASU 2012-02 amends ASC Topic 350, Intangibles – Goodwill and Others, to provide an option to first make a qualitative assessment of whether it is more likely than not that the fair value of an indefinite-lived intangible asset is less than its carrying amount before applying the quantitative impairment test.  An entity is required to perform the quantitative test only if it determines that it is more likely than not that the fair value of an indefinite-lived intangible asset is less than its carrying amount.
 
We will adopt ASU 2012-02 for our annual impairment testing as of October 1, 2012 and do not expect it to significantly affect our financial statements.
 

 

NOTE 3. ACQUISITION AND INVESTMENT ACTIVITY
 

We discuss our investments in unconsolidated entities in Note 4.
 
 
SEMPRA SOUTH AMERICAN UTILITIES
 
 
Chilquinta Energía S.A. (Chilquinta Energía) and Luz del Sur S.A.A. (Luz del Sur)
 
On April 6, 2011, Sempra South American Utilities acquired from AEI its interests in Chilquinta Energía in Chile and Luz del Sur in Peru, and their subsidiaries. Prior to the acquisition, Sempra South American Utilities and AEI each owned 50 percent of Chilquinta Energía and approximately 38 percent of Luz del Sur and accounted for the investments under the equity method. Upon completion of the acquisition and a public tender offer to the minority shareholders of Luz del Sur, Sempra South American Utilities owned 100 percent of Chilquinta Energía and approximately 80 percent of Luz del Sur, with the remaining shares of Luz del Sur held by institutional investors and the general public. As part of the transaction, Sempra South American Utilities also acquired AEI’s interests in two energy-services companies, Tecnored S.A. (Tecnored) and Tecsur S.A. (Tecsur). We provide additional information about Sempra South American Utilities’ acquisition of Chilquinta Energía and Luz del Sur and the public tender offer in Note 3 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
Our results for the nine months ended September 30, 2011 include a $277 million gain (both pretax and after-tax) related to the remeasurement of equity method investments, included as Remeasurement of Equity Method Investments on our Condensed Consolidated Statement of Operations.  We discuss the calculation of the gain in Note 3 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
Our Condensed Consolidated Statements of Operations include 100 percent of the acquired companies’ revenues, net income and earnings of $1.1 billion, $155 million and $135 million, respectively, for the nine months ended September 30, 2012, including revenues, net income, and earnings of $356 million, $56 million and $49 million, respectively, for the three months ended September 30, 2012.  Net income and earnings include holding companies reported in Parent and Other.  Revenues, net income and earnings from the date of acquisition were $706 million, $108 million and $92 million, respectively, for the nine months ended September 30, 2011 and $345 million, $60 million and $52 million, respectively, for the three months ended September 30, 2011. These amounts do not include the remeasurement gain.
 
Following are pro forma revenues and earnings for Sempra Energy had the acquisition occurred on January 1, 2010, which primarily reflect the changes to revenues and earnings from our increased ownership and consolidation of the entities acquired. Although some short-term debt borrowings may have resulted from the actual acquisition in 2011, we have not assumed any additional interest expense in the pro forma impact on earnings below, as the amounts would be immaterial due to the low interest rates available to us on commercial paper.  The pro forma amounts do not include the impact of the increased ownership in Luz del Sur resulting from the tender offer completed in September 2011 discussed above and in Note 3 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
   
Three months ended
 
Nine months ended
 
(Dollars in millions)
September 30, 2011
 
September 30, 2011
 
Revenues
$
 2,576 
 
$
 7,775 
 
Earnings(1)
 
 289 
   
 794 
(2)
(1)
As adjusted for the retrospective effect of change in accounting principle as we discuss in Note 1.
 
(2)
Excludes the $277 million gain related to remeasurement of equity method investments.
 
 
SEMPRA NATURAL GAS
 
 
Willmut Gas Company
 
In May 2012, Sempra Natural Gas acquired 100 percent of the outstanding common stock of Willmut Gas Company (Willmut Gas), a regulated natural gas distribution utility serving approximately 20,000 customers in Hattiesburg, Mississippi, in order to expand Sempra Natural Gas’ service area in the Southeast United States.  Willmut Gas was purchased for $19 million in cash and the assumption of $10 million of liabilities.  Included in the acquisition was $17 million in net property, plant and equipment.  As a result of the acquisition, we recorded $10 million of goodwill.
 
The results of operations for Willmut Gas are included in our Condensed Consolidated Statements of Operations and Cash Flows beginning from the date of acquisition and include revenues of $5 million and negligible earnings for the nine months ended September 30, 2012 and revenues of $3 million and negligible earnings for the three months ended September 30, 2012.
 

 

NOTE 4. INVESTMENTS IN UNCONSOLIDATED ENTITIES
 

We provide additional information concerning all of our equity method investments in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
 
SEMPRA RENEWABLES
 
For the nine months ended September 30, 2012, Sempra Renewables invested $296 million in its renewable wind generation joint ventures, of which $249 million was invested in the Flat Ridge 2 Wind Farm project.
 
 
SEMPRA NATURAL GAS
 
Sempra Natural Gas owns a 25-percent interest in Rockies Express Pipeline LLC (Rockies Express), a partnership that operates a natural gas pipeline, the Rockies Express Pipeline (REX), that links producing areas in the Rocky Mountains region to the upper Midwest and the eastern United States. In August 2012, Kinder Morgan Energy Partners L.P. (KMP) announced the sale of its 50 percent interest in Rockies Express, as part of a larger asset group, to Tallgrass Energy Partners, L.P. (Tallgrass). Phillips 66 owns the remaining interest of 25 percent. Our total investment in Rockies Express is accounted for as an equity method investment.
 
The general partner of KMP is Kinder Morgan, Inc. (KMI). As a condition of KMI receiving antitrust approval from the Federal Trade Commission (FTC) for its acquisition of El Paso Corporation, KMI agreed to divest certain assets in its natural gas pipeline group.  Included in these assets is KMP’s interest in Rockies Express. KMP recorded remeasurement losses during the first nine months of 2012 associated with these discontinued operations. We have recorded impairments of our partnership investment in Rockies Express of $300 million ($179 million after-tax) in the quarter ended June 30, 2012 and an additional $100 million ($60 million after-tax) in the quarter ended September 30, 2012.  Our remaining carrying value in Rockies Express as of September 30, 2012 is $369 million. We recorded the write-downs as a result of our estimate of fair value for our investment at the reporting date and our conclusion that the impairments are other-than-temporary, as required by GAAP. We discuss the fair value measurement of our investment in Rockies Express in Note 8.
 
 
RBS SEMPRA COMMODITIES
 
RBS Sempra Commodities LLP (RBS Sempra Commodities) is a United Kingdom limited liability partnership that owned and operated commodities-marketing businesses previously owned by us. We and our partner in the joint venture, The Royal Bank of Scotland plc (RBS), sold substantially all of the partnership’s businesses and assets in four separate transactions completed in July, November and December of 2010 and February of 2011. We account for our investment in RBS Sempra Commodities under the equity method, and report our share of partnership earnings and other associated costs in Parent and Other.
 
In April 2011, we and RBS entered into a letter agreement (Letter Agreement) which amended certain provisions of the agreements that formed RBS Sempra Commodities. The Letter Agreement addresses the wind-down of the partnership and the distribution of the partnership’s remaining assets. In accordance with the Letter Agreement, we received distributions in the nine months ended September 30, 2011 of $329 million on April 15, 2011 and $98 million on August 9, 2011. The investment balance of $126 million at September 30, 2012 reflects remaining distributions expected to be received from the partnership in accordance with the Letter Agreement. The timing and amount of distributions may be impacted by the matters we discuss related to RBS Sempra Commodities in Note 10 under “Other Litigation.” 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.
 
In connection with the Letter Agreement described above, we also released RBS from its indemnification obligations with respect to the items for which J.P. Morgan Chase & Co. (JP Morgan), one of the buyers of the partnership’s businesses, has agreed to indemnify us.
 
We recorded no equity earnings or losses related to the partnership for the three months or nine months ended September 30, 2012.  Pretax equity losses from RBS Sempra Commodities were $16 million and $24 million for the three months and nine months ended September 30, 2011, respectively. Included in the equity losses is an impairment charge of $16 million ($10 million after-tax) for the three months and nine months ended September 30, 2011 to reduce our investment in RBS Sempra Commodities.  We discuss the fair value measurement of our investment in the partnership in Note 8.
 
We discuss the RBS Sempra Commodities sales transactions, the Letter Agreement and other matters concerning the partnership in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 

 

NOTE 5. OTHER FINANCIAL DATA
 

 
U. S. TREASURY GRANTS RECEIVABLE
 
As of September 30, 2012, Sempra Renewables has recorded grants receivable totaling $181 million. Based on eligible costs at its Mesquite Solar 1 and Copper Mountain Solar 2 generating facilities, the grants are recognized as receivables when the projects, or portions of projects, are placed into service. The grants are expected to be received in 2013.
 
 
INVENTORIES
 
The components of inventories by segment are as follows:
 

INVENTORY BALANCES
(Dollars in millions)
   
September 30, 2012
December 31, 2011
September 30, 2012
December 31, 2011
September 30, 2012
December 31, 2011
   
Natural Gas
Materials and supplies
Total
SDG&E
$
 2 
$
 6 
$
 81 
$
 76 
$
 83 
$
 82 
SoCalGas
 
 142 
 
 128 
 
 24 
 
 23 
 
 166 
 
 151 
Sempra South American Utilities
 
 ― 
 
 ― 
 
 37 
 
 36 
 
 37 
 
 36 
Sempra Mexico
 
 10 
 
 10 
 
 8 
 
 7 
 
 18 
 
 17 
Sempra Natural Gas
 
 85 
 
 51 
 
 9 
 
 9 
 
 94 
 
 60 
Sempra Energy Consolidated
$
 239 
$
 195 
$
 159 
$
 151 
$
 398 
$
 346 
   
 
VARIABLE INTEREST ENTITIES (VIE)
 
We consolidate a VIE if we are the primary beneficiary of the VIE. Our determination of whether we are the primary beneficiary is based upon qualitative and quantitative analyses, which assess
 
§  
the purpose and design of the VIE;
 
§  
the nature of the VIE’s risks and the risks we absorb;
 
§  
the power to direct activities that most significantly impact the economic performance of the VIE; and
 
§  
the obligation to absorb losses or right to receive benefits that could be significant to the VIE.
 
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 impacts 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 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, as we discuss below.
 
 
Otay Mesa VIE
 
SDG&E has an agreement to purchase power generated at the Otay Mesa Energy Center (OMEC), a 605-megawatt (MW) generating facility. In addition to tolling, the agreement provides SDG&E with the option to purchase the power plant at the end of the contract term in 2019, or upon earlier termination of the purchased-power 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, 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 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. SDG&E and Sempra Energy have consolidated Otay Mesa VIE since the second quarter of 2007. Otay Mesa VIE’s equity of $90 million at September 30, 2012 and $102 million at December 31, 2011 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 $347 million at September 30, 2012, the proceeds of which were used for the construction of OMEC. The loan is with third party lenders and is secured 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.
 
 
Other Variable Interest Entities
 
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. 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 as of September 30, 2012. 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.
 
Sempra Energy’s other operating units also enter into arrangements which could include variable interests. We evaluate these arrangements and applicable entities based upon 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. In all other cases, we have determined that these contracts are not variable interests in a VIE and therefore are not subject to the requirements of GAAP concerning the consolidation of VIEs.
 
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 financial statements of other consolidated VIEs are not material to the financial statements of Sempra Energy. The captions on 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 September 30,
Nine months ended September 30,
 
2012 
2011 
2012 
2011 
                 
Operating revenues
               
    Electric
$
 ― 
$
 ― 
$
 ― 
$
 ― 
    Natural gas
 
 ― 
 
 ― 
 
 ― 
 
 ― 
        Total operating revenues
 
 ― 
 
 ― 
 
 ― 
 
 ― 
Operating expenses
               
    Cost of electric fuel and purchased power
 
 (26)
 
 (29)
 
 (66)
 
 (55)
    Operation and maintenance
 
 4 
 
 1 
 
 15 
 
 23 
    Depreciation and amortization
 
 7 
 
 7 
 
 19 
 
 20 
        Total operating expenses
 
 (15)
 
 (21)
 
 (32)
 
 (12)
Operating income
 
 15 
 
 21 
 
 32 
 
 12 
Other income (expense), net
 
 ― 
 
 4 
 
 (1)
 
 ― 
Interest expense
 
 (3)
 
 (4)
 
 (8)
 
 (6)
Income before income taxes/Net income
 
 12 
 
 21 
 
 23 
 
 6 
Earnings attributable to noncontrolling interest
 
 (12)
 
 (21)
 
 (23)
 
 (6)
    Earnings
$
 ― 
$
 ― 
$
 ― 
$
 ― 

We provide additional information regarding Otay Mesa VIE in Note 1 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
 
GOODWILL
 
Goodwill is the excess of the purchase price over the fair value of the identifiable net assets of acquired companies measured at the time of acquisition. Goodwill is not amortized but is tested annually on October 1 for impairment. Impairment of goodwill occurs when the carrying amount (book value) of goodwill exceeds its implied fair value.  If the carrying value of the reporting unit, including goodwill, exceeds its fair value, and the book value of goodwill is greater than its fair value on the test date, we record a goodwill impairment loss.
 
Goodwill included on the Sempra Energy Condensed Consolidated Balance Sheets is recorded as follows:
 

GOODWILL
               
(Dollars in millions)
               
     
Sempra
           
     
South American
 
Sempra
 
Sempra
   
     
Utilities
 
Mexico
 
Natural Gas
 
Total
Balance as of December 31, 2011
$
 949 
$
 25 
$
 62 
$
 1,036 
Foreign currency translation(1)
 
 63 
 
 ― 
 
 ― 
 
 63 
Acquisition of subsidiary
 
 ― 
 
 ― 
 
 10 
 
 10 
Balance at September 30, 2012
$
 1,012 
$
 25 
$
 72 
$
 1,109 
(1)
We record the offset of this fluctuation to other comprehensive income.
   

We provide additional information concerning goodwill in Note 3 above and Notes 1 and 3 of the Notes to Consolidated Financial Statements in the Updated Annual Report. 
 
PENSION AND OTHER POSTRETIREMENT BENEFITS
 
 
Remeasurement
 
The SoCalGas union collective bargaining agreement (CBA) covering wages, hours, working conditions and medical and other benefit plans was ratified on March 1, 2012 and is effective January 1, 2012 through September 30, 2015.  The new CBA includes a change in plans offered for post-65 medical benefits. As a result, SoCalGas changed the option for administering the Medicare Part D benefit to an Employer Group Waiver Plan (EGWP). The EGWP allows a plan sponsor to contract with a Medicare Part D sponsor to receive the benefit of the subsidy through reduced premiums. Because this change in benefits is a significant event under GAAP, SoCalGas was required to remeasure the benefit obligations for this postretirement welfare plan as of February 29, 2012 and determined that a discount rate of 4.65% was appropriate. The effect of the remeasurement was a $66 million decrease in the recorded liability for other postretirement benefits as of March 31, 2012 at SoCalGas and Sempra Energy Consolidated. We discuss the Medicare Part D benefit in Note 8 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
 
Employee Stock Ownership Plan (ESOP)
 
Sempra Energy terminated the ESOP effective June 30, 2012, as all ESOP debt was paid and all shares were released from the ESOP Trust as of that date. We describe the ESOP and ESOP debt in Note 8 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
 
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 September 30,
Three months ended September 30,
 
2012 
2011 
2012 
2011 
Service cost
$
 23 
$
 20 
$
 4 
$
 8 
Interest cost
 
 40 
 
 41 
 
 11 
 
 16 
Expected return on assets
 
 (38)
 
 (36)
 
 (13)
 
 (12)
Amortization of:
               
    Prior service cost
 
 ― 
 
 1 
 
 ― 
 
 ― 
    Actuarial loss
 
 12 
 
 8 
 
 2 
 
 4 
Settlement
 
 1 
 
 1 
 
 ― 
 
 ― 
Regulatory adjustment
 
 9 
 
 31 
 
 3 
 
 2 
Total net periodic benefit cost
$
 47 
$
 66 
$
 7 
$
 18 
 
Nine months ended September 30,
Nine months ended September 30,
 
2012 
2011 
2012 
2011 
Service cost
$
 68 
$
 63 
$
 19 
$
 23 
Interest cost
 
 122 
 
 126 
 
 39 
 
 49 
Expected return on assets
 
 (116)
 
 (109)
 
 (40)
 
 (36)
Amortization of:
               
    Prior service cost (credit)
 
 2 
 
 3 
 
 (2)
 
 ― 
    Actuarial loss
 
 35 
 
 26 
 
 9 
 
 13 
Settlement
 
 8 
 
 11 
 
 ― 
 
 ― 
Regulatory adjustment
 
 (9)
 
 6 
 
 8 
 
 6 
Total net periodic benefit cost
$
 110 
$
 126 
$
 33 
$
 55 


NET PERIODIC BENEFIT COST – SDG&E
(Dollars in millions)
 
Pension Benefits
Other Postretirement Benefits
 
Three months ended September 30,
Three months ended September 30,
 
2012 
2011 
2012 
2011 
Service cost
$
 7 
$
 6 
$
 1 
$
 1 
Interest cost
 
 11 
 
 12 
 
 2 
 
 2 
Expected return on assets
 
 (11)
 
 (10)
 
 (1)
 
 (1)
Amortization of:
               
    Prior service cost
 
 ― 
 
 ― 
 
 1 
 
 1 
    Actuarial loss
 
 4 
 
 2 
 
 ― 
 
 ― 
Settlement
 
 (1)
 
 ― 
 
 ― 
 
 ― 
Regulatory adjustment
 
 7 
 
 15 
 
 1 
 
 1 
Total net periodic benefit cost
$
 17 
$
 25 
$
 4 
$
 4 
 
Nine months ended September 30,
Nine months ended September 30,
 
2012 
2011 
2012 
2011 
Service cost
$
 21 
$
 21 
$
 5 
$
 5 
Interest cost
 
 34 
 
 37 
 
 6 
 
 7 
Expected return on assets
 
 (35)
 
 (35)
 
 (5)
 
 (5)
Amortization of:
               
    Prior service cost
 
 1 
 
 1 
 
 3 
 
 3 
    Actuarial loss
 
 11 
 
 7 
 
 ― 
 
 ― 
Settlement
 
 1 
 
 1 
 
 ― 
 
 ― 
Regulatory adjustment
 
 7 
 
 13 
 
 2 
 
 2 
Total net periodic benefit cost
$
 40 
$
 45 
$
 11 
$
 12 
 

 
NET PERIODIC BENEFIT COST – SOCALGAS
(Dollars in millions)
 
Pension Benefits
Other Postretirement Benefits
 
Three months ended September 30,
Three months ended September 30,
 
2012 
2011 
2012 
2011 
Service cost
$
 13 
$
 10 
$
 2 
$
 7 
Interest cost
 
 24 
 
 24 
 
 9 
 
 12 
Expected return on assets
 
 (23)
 
 (21)
 
 (10)
 
 (10)
Amortization of:
               
    Prior service cost (credit)
 
 ― 
 
 1 
 
 (1)
 
 (1)
    Actuarial loss
 
 6 
 
 4 
 
 1 
 
 4 
Regulatory adjustment
 
 2 
 
 16 
 
 2 
 
 1 
Total net periodic benefit cost
$
 22 
$
 34 
$
 3 
$
 13 
 
Nine months ended September 30,
Nine months ended September 30,
 
2012 
2011 
2012 
2011 
Service cost
$
 40 
$
 34 
$
 12 
$
 17 
Interest cost
 
 74 
 
 74 
 
 31 
 
 39 
Expected return on assets
 
 (72)
 
 (64)
 
 (33)
 
 (30)
Amortization of:
               
    Prior service cost (credit)
 
 1 
 
 2 
 
 (5)
 
 (3)
    Actuarial loss
 
 17 
 
 12 
 
 8 
 
 13 
Settlement
 
 1 
 
 1 
 
 ― 
 
 ― 
Regulatory adjustment
 
 (16)
 
 (7)
 
 6 
 
 4 
Total net periodic benefit cost
$
 45 
$
 52 
$
 19 
$
 40 
 

 
 
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 2012:
 

 
Sempra Energy
   
(Dollars in millions)
Consolidated
SDG&E
SoCalGas
Contributions through September 30, 2012:
           
    Pension plans
$
 111 
$
 36 
$
 45 
    Other postretirement benefit plans
 
 32 
 
 10 
 
 19 
Total expected contributions in 2012:
           
    Pension plans
$
 123 
$
 45 
$
 47 
    Other postretirement benefit plans
 
 41 
 
 13 
 
 23 

Expected contributions to our pension plans in 2012 have decreased significantly due to the passage of legislation in July 2012, the Moving Ahead for Progress in the 21st Century Act, that significantly reduces the minimum contributions required for single employer defined benefit plans, but increases premiums to the Pension Benefit Guaranty Corporation.
 
 
EARNINGS PER SHARE
 
The following table provides the per share computations for our earnings for the three months and nine months ended September 30, 2012 and 2011. Basic earnings per common share (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 COMPUTATIONS
         
(Dollars in millions, except per share amounts; shares in thousands)
         
   
Three months ended September 30,
 
Nine months ended September 30,
   
2012 
2011(1)
 
2012 
2011(1)
Numerator:
                 
    Earnings/Income attributable to common shareholders
$
 268 
$
 289 
 
$
 566 
$
 1,046 
                   
Denominator:
                 
    Weighted-average common shares
                 
        outstanding for basic EPS
 
 241,689 
 
 239,545 
   
 241,133 
 
 239,693 
    Dilutive effect of stock options, restricted
                 
        stock awards and restricted stock units
 
 4,113 
 
 2,335 
   
 3,880 
 
 2,262 
    Weighted-average common shares
                 
        outstanding for diluted EPS
 
 245,802 
 
 241,880 
   
 245,013 
 
 241,955 
 
                 
Earnings per share:
                 
    Basic
$
 1.11 
$
 1.21 
 
$
 2.35 
$
 4.36 
    Diluted
$
 1.09 
$
 1.20 
 
$
 2.31 
$
 4.32 
(1)
As adjusted for the retrospective effect of a change in accounting principle as we discuss in Note 1.
         

The dilution from common stock options is based on the treasury stock method. Under this method, proceeds based on the exercise price plus unearned compensation and windfall tax benefits recognized and 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 upon the assumed exercise 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 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). We had no such antidilutive stock options outstanding during the three months ended September 30, 2012 and 40,000 such antidilutive stock options outstanding during the nine months ended September 30, 2012. We had 2,112,880 and 2,111,839 such stock options outstanding during the three months and nine months ended September 30, 2011, respectively.
 
We had no stock options outstanding during either the three months or nine months ended September 30, 2012 that were antidilutive because of the unearned compensation and windfall tax benefits included in the assumed proceeds under the treasury stock method.  We had no such stock options during the three months ended September 30, 2011 and 900 such antidilutive stock options during the nine months ended September 30, 2011.
 
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 and minus tax shortfalls recognized related to the awards and units are assumed to be used to repurchase shares on the open market at the average market price for the period. The windfall tax benefits recognized or tax shortfalls recognized are the difference between tax deductions we would receive upon the assumed vesting of RSAs or RSUs and the deferred income taxes we recorded related to the compensation expense on such awards and units.  There were 3,387 antidilutive RSUs from the application of unearned compensation in the treasury stock method for the three months and 1,881 such antidilutive RSUs for the nine months ended September 30, 2012. There were 1,109 such antidilutive RSUs for the three months ended September 30, 2011 and no such antidilutive RSUs for the nine months ended September 30, 2011.  There were no such antidilutive RSAs for the three months ended September 30, 2012 and 14,319 such antidilutive RSAs for the nine months ended September 30, 2012. There were no such antidilutive RSAs for the three months and nine months ended September 30, 2011.
 
Each performance-based RSU represents the right to receive between zero and 1.5 shares of Sempra Energy common stock based on Sempra Energy’s four-year cumulative total shareholder return compared to the Standard & Poor’s (S&P) 500 Utilities Index, as follows:
 
Four-Year Cumulative Total Shareholder Return Ranking versus S&P 500 Utilities Index(1)
Number of Sempra Energy Common Shares Received for Each Restricted Stock Unit(2)
75th Percentile or Above
1.5 
50th Percentile
35th Percentile or Below
(1) If Sempra Energy ranks at or above the 50th percentile compared to the S&P 500 Index, participants will receive a minimum of 1.0 share for each restricted stock unit.
(2) Participants may also receive additional shares for dividend equivalents on units subject to restricted stock units, which are reinvested to purchase additional units that become subject to the same vesting conditions as the restricted stock units to which the dividends relate.

 
RSAs have a maximum potential of 100 percent vesting. We include our performance-based RSUs in potential dilutive shares at zero to 150 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 index, dilutive RSU shares may vary widely from period-to-period. We include our RSAs, which are solely service-based, in potential dilutive shares at 100 percent.
 
RSUs and RSAs may be excluded from potential dilutive shares by the application of unearned compensation in the treasury stock method, as we discuss above, or because performance goals are currently not met.  The maximum excluded RSAs and RSUs, assuming performance goals were met at maximum levels, were 2,349,338 and 2,523,343 for the three months and nine months ended September 30, 2012, respectively, and 3,473,578 and 3,630,253 for the three months and nine months ended September 30, 2011, respectively.
 
 
COMMON STOCK REPURCHASE PROGRAM
 
In September 2010, we entered into a share repurchase program under which we prepaid $500 million to repurchase shares of our common stock in a share forward transaction. The program was completed in March 2011 with a total of 9,574,435 shares repurchased at an average price of $52.22 per share. Our outstanding shares used to calculate earnings per share were reduced by the number of shares repurchased when they were delivered to us, and the $500 million purchase price was recorded as a reduction in shareholders’ equity upon its prepayment. We received 5,670,006 shares during the quarter ended September 30, 2010; 2,407,994 shares on October 4, 2010 and 1,496,435 shares on March 22, 2011.  We discuss the repurchase program further in Note 13 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
 
PREFERRED STOCK OF SUBSIDIARY
 
On June 30, 2011, PE redeemed all five series of its outstanding preferred stock for $81 million. Each series was redeemed for cash at redemption prices ranging from $100 to $101.50 per share, plus accrued dividends up to the redemption date of an aggregate of $1 million. The redeemed shares are no longer outstanding and represent only the right to receive the applicable redemption price, to the extent the shares have not yet been presented for payment. We provide more detail concerning PE’s preferred stock in Note 12 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
 
SHARE-BASED COMPENSATION
 
We discuss our share-based compensation plans in Note 9 of the Notes to Consolidated Financial Statements in the Updated Annual Report. We recorded share-based compensation expense, net of income taxes, of $5 million and $7 million for the three months ended September 30, 2012 and 2011, respectively, and $18 million and $20 million for the nine months ended September 30, 2012 and 2011, respectively. Pursuant to our share-based compensation plans, we granted 927,734 RSUs and 18,487 RSAs during the nine months ended September 30, 2012, primarily in January.
 
 
CAPITALIZED FINANCING COSTS
 
Capitalized financing costs include capitalized interest costs and, primarily at the California Utilities, an allowance for funds used during construction (AFUDC) related to both debt and equity financing of construction projects.  The following table shows capitalized financing costs for the three months and nine months ended September 30, 2012 and 2011.
 

CAPITALIZED FINANCING COSTS
       
(Dollars in millions)
       
 
Three months ended September 30,
Nine months ended
September 30,
 
2012 
2011 
2012 
2011 
Sempra Energy Consolidated:
               
    AFUDC related to debt
$
 5 
$
 10 
$
 32 
$
 27 
    AFUDC related to equity
 
 13 
 
 26 
 
 80 
 
 67 
    Other capitalized financing costs
 
 13 
 
 6 
 
 40 
 
 20 
        Total Sempra Energy Consolidated
$
 31 
$
 42 
$
 152 
$
 114 
SDG&E:
               
    AFUDC related to debt
$
 3 
$
 8 
$
 26 
$
 22 
    AFUDC related to equity
 
 6 
 
 21 
 
 61 
 
 54 
        Total SDG&E
$
 9 
$
 29 
$
 87 
$
 76 
SoCalGas:
               
    AFUDC related to debt
$
 2 
$
 2 
$
 6 
$
 5 
    AFUDC related to equity
 
 7 
 
 5 
 
 19 
 
 13 
        Total SoCalGas
$
 9 
$
 7 
$
 25 
$
 18 

 
COMPREHENSIVE INCOME
 
The amounts for comprehensive income in the Condensed Consolidated Statements of Comprehensive Income are net of income tax expense (benefit) as follows:
 

INCOME TAX EXPENSE (BENEFIT) ASSOCIATED WITH OTHER COMPREHENSIVE INCOME
(Dollars in millions)
   
Three months ended September 30,
   
2012 
 
2011 
   
Share-
Non-
   
Share-
Non-
 
   
holders'
controlling
Total
 
holders'
controlling
Total
   
Equity(1)
Interests
Equity
 
Equity(1)
Interests
Equity
Sempra Energy Consolidated:
                         
    Foreign currency translation adjustments
$
 ― 
$
 ― 
$
 ― 
 
$
 (1)
$
 ― 
$
 (1)
    Net actuarial (loss) gain
 
 (7)
 
 ― 
 
 (7)
   
 1 
 
 ― 
 
 1 
    Financial instruments
 
 (1)
 
 ― 
 
 (1)
   
 (11)
 
 ― 
 
 (11)
SoCalGas:
                         
    Financial instruments
$
 1 
$
 ― 
$
 1 
 
$
 ― 
$
 ― 
$
 ― 
                             
   
Nine months ended September 30,
   
2012 
 
2011 
   
Share-
Non-
   
Share-
Non-
 
   
holders'
controlling
Total
 
holders'
controlling
Total
   
Equity(1)
Interests
Equity
 
Equity(1)
Interests
Equity
Sempra Energy Consolidated:
                         
    Foreign currency translation adjustments
$
 ― 
$
 ― 
$
 ― 
 
$
 (1)
$
 ― 
$
 (1)
    Net actuarial (loss) gain
 
 (4)
 
 ― 
 
 (4)
   
 5 
 
 ― 
 
 5 
    Financial instruments
 
 (5)
 
 ― 
 
 (5)
   
 (11)
 
 ― 
 
 (11)
SoCalGas:
                         
    Financial instruments
$
 1 
$
 ― 
$
 1 
 
$
 1 
$
 ― 
$
 1 
 (1)
Shareholders equity of Sempra Energy Consolidated or SoCalGas as indicated in left margin.
   

Income tax amounts associated with other comprehensive income during the three months and nine months ended September 30, 2012 and 2011 at SDG&E were negligible.
 

 
SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS
 
The following two tables provide a reconciliation of Sempra Energy’s and SDG&E’s shareholders’ equity and noncontrolling interests for the nine months ended September 30, 2012 and 2011.
 

SHAREHOLDERS’ EQUITY AND NONCONTROLLING INTERESTS
(Dollars in millions)
   
Sempra
       
   
Energy
 
Non-
   
   
Shareholders’
 
controlling
 
Total
   
Equity
 
Interests
 
Equity
Balance at December 31, 2011
$
 9,775 
$
 403 
$
 10,178 
Comprehensive income
 
 671 
 
 42 
 
 713 
Preferred dividends of subsidiaries
 
 (5)
 
 ― 
 
 (5)
Share-based compensation expense
 
 33 
 
 ― 
 
 33 
Common stock dividends declared
 
 (435)
 
 ― 
 
 (435)
Issuance of common stock
 
 50 
 
 ― 
 
 50 
Repurchase of common stock
 
 (16)
 
 ― 
 
 (16)
Common stock released from ESOP
 
 9 
 
 ― 
 
 9 
Equity contributed by noncontrolling interest
 
 ― 
 
 5 
 
 5 
Distributions to noncontrolling interests
 
 ― 
 
 (36)
 
 (36)
Balance at September 30, 2012
$
 10,082 
$
 414 
$
 10,496 
Balance at December 31, 2010
$
 8,990 
$
 211 
$
 9,201 
Comprehensive income (loss)
 
 879 
 
 (14)
 
 865 
Preferred dividends of subsidiaries
 
 (6)
 
 ― 
 
 (6)
Share-based compensation expense
 
 36 
 
 ― 
 
 36 
Common stock dividends declared
 
 (346)
 
 ― 
 
 (346)
Issuance of common stock
 
 22 
 
 ― 
 
 22 
Tax benefit related to share-based compensation
 
 6 
 
 ― 
 
 6 
Repurchase of common stock
 
 (18)
 
 ― 
 
 (18)
Common stock released from ESOP
 
 15 
 
 ― 
 
 15 
Distributions to noncontrolling interests
 
 ― 
 
 (9)
 
 (9)
Equity contributed by noncontrolling interest
 
 ― 
 
 6 
 
 6 
Acquisition of South American entities
 
 ― 
 
 279 
 
 279 
Purchase of noncontrolling interests in subsidiary
 
 (4)
 
 (39)
 
 (43)
Redemption of preferred stock of subsidiary
 
 ― 
 
 (80)
 
 (80)
Balance at September 30, 2011
$
 9,574 
$
 354 
$
 9,928 


SHAREHOLDER’S EQUITY AND NONCONTROLLING INTEREST
(Dollars in millions)
   
SDG&E
 
Non-
   
   
Shareholder’s
 
controlling
 
Total
   
Equity
 
Interest
 
Equity
Balance at December 31, 2011
$
 3,739 
$
 102 
$
 3,841 
Comprehensive income
 
 378 
 
 10 
 
 388 
Preferred stock dividends declared
 
 (4)
 
 ― 
 
 (4)
Distributions to noncontrolling interest
 
 ― 
 
 (22)
 
 (22)
Balance at September 30, 2012
$
 4,113 
$
 90 
$
 4,203 
Balance at December 31, 2010
$
 3,108 
$
 113 
$
 3,221 
Comprehensive income (loss)
 
 278 
 
 (28)
 
 250 
Preferred stock dividends declared
 
 (4)
 
 ― 
 
 (4)
Capital contribution
 
 200 
 
 ― 
 
 200 
Equity contributed by noncontrolling interest
 
 ― 
 
 6 
 
 6 
Balance at September 30, 2011
$
 3,582 
$
 91 
$
 3,673 

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.  Net income or loss attributable to the noncontrolling interests is separately identified on the Condensed Consolidated Statements of Operations, and comprehensive income attributable to the noncontrolling interests is separately identified on the Condensed Consolidated Statements of Comprehensive Income.
 
The preferred stock of SoCalGas is presented at Sempra Energy as a noncontrolling interest at September 30, 2012 and December 31, 2011. The preferred stock of SDG&E is contingently redeemable preferred stock. At Sempra Energy, the preferred stock dividends of both SDG&E and SoCalGas are charges against income related to noncontrolling interests. We provide additional information concerning preferred stock in Note 12 of the Notes to Consolidated Financial Statements in the Updated Annual Report. 
 
At September 30, 2012 and December 31, 2011, Sempra Energy Consolidated reported the following other noncontrolling ownership interests held by others 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 Others
   
September 30, 2012
 
December 31, 2011
Bay Gas Storage, Ltd.(1)
%
$
 19 
$
 17 
Southern Gas Transmission Company(1)
49 
   
 1 
 
 1 
Liberty Gas Storage, LLC(1)
25 
   
 13 
 
 9 
Tecsur
10 
   
 4 
 
 4 
Luz del Sur
20 
   
 230 
 
 216 
Chilquinta Energía subsidiaries
15 - 43
   
 37 
 
 34 
Otay Mesa VIE (at SDG&E)
100 
   
 90 
 
 102 
      Total Sempra Energy
   
$
 394 
$
 383 
 (1)
Part of Sempra Natural Gas.
   

 
TRANSACTIONS WITH AFFILIATES
 
 
Loans to Unconsolidated Affiliates
 
Sempra South American Utilities has a U.S. dollar-denominated loan to Camuzzi Gas del Sur S.A., an affiliate of the segment’s Argentine investments, which we discuss in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report. At September 30, 2012, the loan has an $18 million principal balance outstanding plus $7 million of accumulated interest at a variable interest rate (7.41 percent as of September 30, 2012). In June 2012, the maturity date of the loan was extended from June 30, 2012 to June 30, 2013. The loan was fully reserved at September 30, 2012 and December 31, 2011.
 
 
Investments
 
Sempra Energy, at Parent and Other, has an investment in bonds issued by Chilquinta Energía that we discuss in Note 5 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
 
Other Affiliate Transactions
 
Sempra Energy, SDG&E and SoCalGas provide certain services to each other and are charged an allocable share of the cost of such services. Amounts due to/from affiliates are as follows:
 

AMOUNTS DUE TO AND FROM AFFILIATES AT SDG&E AND SOCALGAS
(Dollars in millions)
   
September 30,
 
December 31,
 
2012 
 
2011 
SDG&E
         
Current:
         
    Due from SoCalGas
$
 16 
 
$
 2 
    Due from various affiliates
 
 1 
   
 65 
 
$
 17 
 
$
 67 
             
    Due to Sempra Energy
$
 20 
 
$
 14 
             
    Income taxes due from Sempra Energy(1)
$
 149 
 
$
 97 
           
SoCalGas
         
Current:
         
    Due from Sempra Energy
$
 280 
 
$
 23 
    Due from various affiliates
 
 ― 
   
 17 
   
$
 280 
 
$
 40 
           
    Due to SDG&E
$
 16 
 
$
 2 
             
    Income taxes due from Sempra Energy(1)
$
 15 
 
$
 17 
(1)
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 the companies’ having always filed a separate return.

Revenues from unconsolidated affiliates at SDG&E and SoCalGas are as follows:
 

REVENUES FROM UNCONSOLIDATED AFFILIATES AT SDG&E AND SOCALGAS
(Dollars in millions)
     
 
Three months ended September 30,
Nine months ended September 30,
 
2012 
2011 
2012 
2011 
SDG&E
$
 2 
$
 3 
$
 6 
$
 6 
SoCalGas
 
 17 
 
 13 
 
 48 
 
 38 

 
Transactions with RBS Sempra Commodities
 
Several of our segments have engaged in transactions with RBS Sempra Commodities. As a result of the divestiture of substantially all of RBS Sempra Commodities’ businesses, transactions between our segments and RBS Sempra Commodities were assigned over time to the buyers of the joint venture businesses. The assignments of the related contracts were substantially completed by May 1, 2011. Amounts in our Condensed Consolidated Statements of Operations related to these transactions are as follows:
 

AMOUNTS RECORDED FOR TRANSACTIONS WITH RBS SEMPRA COMMODITIES
(Dollars in millions)
     
Three months ended September 30, 2011(1)
Nine months ended September 30, 2011(1)
Revenues:
           
    Sempra Mexico
$
 
 ― 
$
 
 37 
    Sempra Natural Gas
   
 ― 
   
 7 
                 
Cost of natural gas:
           
    Sempra Mexico
$
 
 3 
$
 
 74 
    Sempra Natural Gas
   
 ― 
   
 3 
(1)
With the exception of Sempra Mexico, whose contract with RBS Sempra Commodities expired in July 2011, amounts only include activities prior to May 1, 2011, the date by which substantially all the contracts with RBS Sempra Commodities were assigned to buyers of the joint venture businesses.

 
 
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 September 30,
Nine months ended September 30,
   
2012 
2011 
2012 
2011 
Sempra Energy Consolidated:
               
Allowance for equity funds used during construction
$
 13 
$
 26 
$
 80 
$
 67 
Investment gains (losses)(1)
 
 17 
 
 (6)
 
 27 
 
 13 
Gains (losses) on interest rate and foreign exchange instruments, net
 
 1 
 
 (26)
 
 11 
 
 (14)
Regulatory interest, net(2)
 
 ― 
 
 ― 
 
 1 
 
 1 
Sundry, net
 
 13
 
 18 
 
 18 
 
 19 
   Total
$
 44
$
 12
$
 137
$
 86
SDG&E:
               
Allowance for equity funds used during construction
$
 6 
$
 21 
$
 61 
$
 54 
Regulatory interest, net(2)
 
 ― 
 
 ― 
 
 1 
 
 1 
Sundry, net
 
 (1)
 
 5 
 
 (3)
 
 ― 
   Total
$
 5 
$
 26 
$
 59 
$
 55 
SoCalGas:
               
Allowance for equity funds used during construction
$
 7 
$
 5 
$
 19 
$
 13 
Sundry, net
 
 (1)
 
 (2)
 
 (5)
 
 (4)
   Total
$
 6 
$
 3 
$
 14 
$
 9 
(1)
Represents investment gains (losses) on dedicated assets in support of our executive retirement and deferred compensation plans. These amounts are partially offset by corresponding changes in compensation expense related to the plans.
(2)
Interest on regulatory balancing accounts.
               

 
INCOME TAXES
 
INCOME TAX EXPENSE AND EFFECTIVE INCOME TAX RATES
(Dollars in millions)
     
Three months ended September 30,
   
2012 
 
2011 
         
Effective
       
Effective
 
     
Income Tax
 
Income
   
Income Tax
 
 Income
 
     
Expense
 
Tax Rate
   
Expense
 
Tax Rate
 
Sempra Energy Consolidated
$
 49 
 
 15 
%
$
 75 
 
 19 
%
SDG&E
 
 38 
 
 17 
   
 63 
 
 32 
 
SoCalGas
 
 37 
 
 34 
   
 41 
 
 34 
 
     
Nine months ended September 30,
   
2012 
 
2011 
         
Effective
       
Effective
 
     
Income Tax
 
 Income
   
Income Tax
 
Income
 
     
Expense
 
Tax Rate
   
Expense
 
Tax Rate
 
Sempra Energy Consolidated
$
 48 
 
 8 
%
$
 289 
 
 22 
%
SDG&E
 
 151 
 
 27 
   
 154 
 
 35 
 
SoCalGas
 
 105 
 
 35 
   
 106 
 
 34 
 

 
Changes in Effective Income Tax Rates
 
Sempra Energy Consolidated
 
The lower effective income tax rate in the three months ended September 30, 2012 was primarily due to:
 
§  
$38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012. The change in income tax treatment was made pursuant to an Internal Revenue Service Revenue Procedure allowing certain capitalized repair costs for electric transmission and distribution assets to be deducted from taxable income when incurred for tax years beginning on or after January 1, 2011; and
 
§  
higher planned renewable energy income tax credits and deferred income tax benefits related to renewable energy projects; offset by
 
§  
higher income tax expense in 2012 due to Mexican currency translation and inflation adjustments; and
 
§  
higher income tax expense due to unfavorable resolution of prior years’ income tax items.
 
The lower effective income tax rate in the nine months ended September 30, 2012 was primarily due to:
 
§  
$54 million income tax benefit primarily associated with our decision to hold life insurance contracts kept in support of certain benefit plans to term. Previously, we took the position that we might cash in or sell these contracts before maturity, which required that we record deferred income taxes on unrealized gains on investments held within the insurance contracts;
 
§  
$38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012, as discussed above; and
 
§  
higher planned renewable energy income tax credits and deferred income tax benefits related to renewable energy projects; offset by
 
§  
lower income in 2012 in countries with lower statutory income tax rates; such income was higher in 2011 due to the $277 million non-taxable gain from our equity method investments related to our acquisition from AEI of its investments in Chile and Peru;
 
§  
higher income tax expense in 2012 due to Mexican currency translation and inflation adjustments;
 
§  
higher income tax expense due to unfavorable resolution of prior years’ income tax items; and
 
§  
higher U.S. income tax on non-U.S. non-operating activity due to the expiration of the look-through rule, as we discuss below.
 
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 are factored into the forecasted effective tax rate and their impact is spread evenly over the year. The forecasted items, anticipated on a full year basis, may include, among others, self-developed software, repairs to certain utility plant fixed assets, renewable energy income tax credits, deferred income tax benefits related to renewable energy projects, exclusions from taxable income of the equity portion of AFUDC, and depreciation on a certain portion of utility plant assets. Items that cannot be reliably forecasted (e.g., adjustments related to prior years’ income tax items, Mexican currency translation and inflation adjustments, deferred income tax benefit associated with the impairment of a book investment, etc.) are recorded in the interim period in which they actually occur, which can result in variability to income tax expense.
 
We have used grant accounting for certain assets placed into service in 2012, including assets that were under construction in 2011, in anticipation of applying for cash grants. Grant accounting for cash grants is very similar to the deferral method of accounting for investment tax credits, the primary difference being the recording of a grant receivable instead of an income tax receivable.
 
Under the deferral method of accounting for ITC and under grant accounting for cash grants, a deferred income tax benefit, on day one, is reflected in income tax expense by recording a deferred tax asset when renewable energy assets are placed in service. This deferred tax asset results from the day-one difference in the income tax basis and financial statement basis of the renewable energy assets, referred to as the “day-one basis difference.” The financial statement basis of the assets is reduced by 100 percent of the ITC or grant expected; U.S. federal income tax basis is reduced by only 50 percent for both ITC and grants; and state income tax basis is reduced 50 percent for grants and not at all for ITC.
 
In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (2010 Tax Act) was signed into law. The 2010 Tax Act extended for years 2010 and 2011 the U.S. federal income tax law known as the look-through rule. This rule allows, under certain situations, for certain non-operating activity (e.g., dividend income, royalty income, interest income, rental income, etc.), of a greater than 50-percent owned non-U.S. subsidiary, to not be taxed under U.S. federal income tax law. As of September 30, 2012, this rule has not yet been extended beyond 2011, which has a negative impact on Sempra Energy’s effective income tax rate for 2012.
 
SDG&E
 
The decrease in the effective income tax rate in the three months ended September 30, 2012 was primarily due to:
 
§  
$38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012.  The change in income tax treatment was made pursuant to an Internal Revenue Service Revenue Procedure allowing certain capitalized repair costs for electric transmission and distribution assets to be deducted from taxable income when incurred for tax years beginning on or after January 1, 2011; and
 
§  
higher favorable resolutions of prior years' income tax items; offset by
 
§  
the impact of Otay Mesa VIE, as we discuss below; and
 
§  
lower exclusions from taxable income of the equity portion of AFUDC.
 
The decrease in the effective tax rate in the nine months ended September 30, 2012 was primarily due to:
 
§  
$38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012, as discussed above;
 
§  
the impact of Otay Mesa VIE, as we discuss below;
 
§  
lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; and
 
§  
higher favorable resolutions of prior years’ income tax items; offset by
 
§  
lower exclusions from taxable income of the equity portion of AFUDC.
 
Results for Sempra Energy Consolidated and SDG&E include Otay Mesa VIE, which is consolidated, and therefore, their effective income tax rates are impacted by the VIE’s stand-alone effective income tax rate.
 
 
SoCalGas
 
While the effective income tax rate for the three months ended September 30, 2012 did not change significantly from the same period in 2011, it was impacted by:
 
§  
lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; and
 
§  
higher exclusions from taxable income of the equity portion of AFUDC; offset by
 
§  
lower deductions for cost of removal of utility plant fixed assets.
 
The increase in the effective income tax rate in the nine months ended September 30, 2012 was primarily due to:
 
§  
lower deductions for self-developed software costs; offset by
 
§  
lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; and
 
§  
higher exclusions from taxable income of the equity portion of AFUDC.
 
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-through temporary differences, deferred income taxes are not recorded to deferred income tax expense, but rather to a regulatory asset or liability. 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 to a certain portion of utility plant fixed assets
 
§  
the equity portion of AFUDC
 
§  
cost of removal of utility plant assets
 
§  
self-developed software costs
 
§  
depreciation on a certain portion of utility plant fixed assets
 

 

NOTE 6. DEBT AND CREDIT FACILITIES
 

 
COMMITTED LINES OF CREDIT
 
At September 30, 2012, Sempra Energy Consolidated had an aggregate of $4.1 billion in committed lines of credit to provide liquidity and to support commercial paper and variable-rate demand notes, the major components of which we detail below. Available unused credit on these lines at September 30, 2012 was $3.5 billion.
 
 
Sempra Energy
 
In March 2012, Sempra Energy entered into a new $1.067 billion, five-year syndicated revolving credit agreement expiring in March 2017. Citibank, N.A. serves as administrative agent for the syndicate of 24 lenders. No single lender has greater than a 7-percent share. The new facility replaced the $1.0 billion credit agreement that was scheduled to expire in 2014.
 
Borrowings bear interest at benchmark rates plus a margin that varies with market index rates and 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. The facility also provides for issuance of up to $700 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 September 30, 2012, Sempra Energy had $47 million of letters of credit outstanding supported by the facility.
 
 
Sempra Global
 
In March 2012, Sempra Global entered into a $2.189 billion, five-year syndicated revolving credit agreement expiring in March 2017. Citibank, N.A. serves as administrative agent for the syndicate of 25 lenders. No single lender has greater than a 7-percent share. The new facility replaced the $2.0 billion credit agreement that was scheduled to expire in 2014.
 
Sempra Energy guarantees Sempra Global’s obligations under the credit facility. Borrowings bear interest at benchmark rates plus a margin that varies with market index rates and 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 September 30, 2012, Sempra Global had $545 million of commercial paper outstanding supported by the facility. At December 31, 2011, $400 million of commercial paper outstanding was classified as long-term debt based on management’s intent and ability to maintain this level of borrowing on a long-term basis either supported by this credit facility or by issuing long-term debt. This classification has no impact on cash flows. As a result of issuances of long-term debt in the nine months ended September 30, 2012, as we discuss below, none of the commercial paper outstanding at September 30, 2012 is classified as long-term debt.
 
 
California Utilities
 
In March 2012, SDG&E and SoCalGas entered into a new combined $877 million, five-year syndicated revolving credit agreement expiring in March 2017. JPMorgan Chase Bank, N.A. serves as administrative agent for the syndicate of 24 lenders. No single lender has greater than a 7-percent share. The agreement permits each utility to individually borrow up to $658 million, subject to a combined limit of $877 million 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 $200 million for both utilities. The amount of borrowings otherwise available under the facility is reduced by the amount of outstanding letters of credit. The new facility replaced the $800 million combined credit agreement that was scheduled to expire in 2014.
 
Borrowings under the facility bear interest at benchmark rates plus a margin that varies with market index rates and the borrowing utility’s credit ratings. The agreement requires each utility 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.
 
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 September 30, 2012, SoCalGas had no outstanding borrowings and SDG&E had $2 million of commercial paper outstanding supported by the facility. Available unused credit on the line at September 30, 2012 was $656 million at SDG&E and $658 million at SoCalGas, subject to the combined limit on the facility of $877 million.
 
 
GUARANTEES
 
 
RBS Sempra Commodities
 
As we discuss in Note 4, in 2010 and early 2011, Sempra Energy, RBS and RBS Sempra Commodities sold substantially all of the businesses and assets within the partnership in four separate transactions. In connection with each of these transactions, the buyers were, subject to certain qualifications, obligated to replace any guarantees that we had issued in connection with the applicable businesses sold with guarantees of their own. The buyers have substantially completed this process with regard to all existing, open positions, except for one remaining position expected to terminate by January 2013. For those guarantees which have not been replaced, the buyers are obligated to indemnify us in accordance with the applicable transaction documents for any claims or losses in connection with the guarantees that we issued associated with the businesses sold.
 
At September 30, 2012, RBS Sempra Commodities no longer requires significant working capital support. However, we have provided back-up guarantees for a portion of RBS Sempra Commodities’ remaining trading obligations. A few of these back-up guarantees may continue for a prolonged period of time. RBS has fully indemnified us for any claims or losses in connection with these arrangements, with the exception of those obligations for which JP Morgan has agreed to indemnify us. We discuss the indemnification release in Note 4. We discuss additional matters related to our investment in RBS Sempra Commodities in Note 10.
 
 
WEIGHTED AVERAGE INTEREST RATES
 
The weighted average interest rates on the total short-term debt outstanding at Sempra Energy were 0.82 percent and 0.93 percent at September 30, 2012 and December 31, 2011, respectively. The weighted average interest rate on the total short-term debt outstanding at SDG&E was 0.2 percent at September 30, 2012.  The weighted average interest rates at Sempra Energy at December 31, 2011 include interest rates for commercial paper borrowings classified as long-term, as we discuss above.
 
 
LONG-TERM DEBT
 
 
Sempra Energy
 
In March 2012, Sempra Energy publicly offered and sold $600 million of 2.30-percent notes maturing in 2017. In September 2012, Sempra Energy publicly offered and sold $500 million of 2.875-percent notes maturing in 2022.
 
 
SDG&E
 
In March 2012, SDG&E publicly offered and sold $250 million of 4.30-percent first mortgage bonds maturing in 2042.
 
In September 2012, SDG&E remarketed $161 million of variable rate demand notes at a fixed rate of 1.65 percent maturing in 2018 and $75 million of variable rate demand notes at a fixed rate of 4.00 percent maturing in 2039.
 
 
SoCalGas
 
In September 2012, SoCalGas publicly offered and sold $350 million of 3.75-percent first mortgage bonds maturing in 2042.
 
 
Sempra South American Utilities
 
In February 2012, Luz del Sur publicly offered and sold Peruvian corporate bonds, denominated in the local currency, in the amounts of $21 million at 5.97 percent maturing in 2017 and $9 million at 6.34 percent maturing in 2019. In July 2012, Luz del Sur publicly offered and sold $25 million of Peruvian corporate bonds, denominated in the local currency, at 5.44 percent and maturing in 2019.
 
 
Sempra Renewables
 
In June 2012, Sempra Renewables obtained a $117 million loan, the proceeds of which were applied to construction costs of the Copper Mountain Solar 1 project. The loan fully matures in December 2028. To partially moderate its exposure to interest rate changes, Sempra Renewables has also entered into floating-to-fixed interest rate swaps maturing December 2028. Accordingly, $88 million of this loan has interest rates that are effectively fixed at 4.54 percent. The remaining balance bears interest at rates varying with market rates (2.86 percent at September 30, 2012).
 
 
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 and benchmark interest rate risk. We may also manage foreign exchange rate exposures using derivatives. 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 presented below.
 
We record all 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 (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.
 
In certain cases, we apply the normal purchase or sale exception to derivative accounting 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.
 
 
HEDGE ACCOUNTING
 
We may designate a derivative as a cash flow hedging instrument if it effectively converts anticipated revenues or expenses to a fixed dollar amount. We may utilize cash flow hedge accounting for derivative commodity 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 a given future 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 instruments 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.
 
§  
The California Utilities use natural gas energy derivatives, on their customers’ behalf, with the objective of managing price risk and basis risks, and lowering natural gas costs. These derivatives include fixed price natural gas positions, options, and basis risk instruments, which are either exchange-traded or over-the-counter financial instruments. This activity is governed by risk management and transacting activity plans that have been filed with and approved by the CPUC. Natural gas 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 are recorded in Cost of Electric Fuel and Purchased Power, which is recoverable in rates, on the Condensed Consolidated Statements of Operations.
 
§  
Sempra Mexico and Sempra Natural Gas 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, power generation, and Sempra Natural Gas’ storage. 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.
 
§  
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 as of September 30, 2012 and December 31, 2011 as follows:
 

           
Segment and Commodity
September 30, 2012
December 31, 2011
 
California Utilities:
     
    SDG&E:
     
        Natural gas
23 million MMBtu
35 million MMBtu
(1)
        Congestion revenue rights
18 million MWh
19 million MWh
(2)
           
Energy-Related Businesses:
     
    Sempra Natural Gas:
     
        Electric power
2 million MWh
5 million MWh
 
        Natural gas
32 million MMBtu
20 million MMBtu
 
    Sempra Mexico - natural gas
1 million MMBtu
1 million MMBtu
 
(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 our customers, assets and other contractual obligations, 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. We periodically enter into interest rate derivative agreements intended to moderate our exposure to interest rates and to lower our overall costs of borrowing. We 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, which are 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. 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 natural gas derivatives. Accordingly, interest rate derivatives are generally accounted for as hedges at the California Utilities, as well as at the rest of Sempra Energy’s subsidiaries. Separately, Otay Mesa VIE has entered into interest rate swap agreements to moderate its exposure to interest rate changes. This activity was designated as a cash flow hedge as of April 1, 2011.
 
The net notional amounts of our interest rate derivatives as of September 30, 2012 and December 31, 2011 were:
 

   
September 30, 2012
December 31, 2011
(Dollars in millions)
Notional Debt
Maturities
Notional Debt
Maturities
Sempra Energy Consolidated(1)
$
6-369
2013-2028
$
15-305
2013-2019
SDG&E(1)
 
285-347
2019
 
285-355
2019
(1)
Includes Otay Mesa VIE. All of SDG&E’s interest rate derivatives relate to Otay Mesa VIE.
 
 
 
FOREIGN CURRENCY DERIVATIVES
 
We are exposed to exchange rate movements primarily as a result of our Mexican subsidiaries, which have U.S. dollar denominated receivables and payables (monetary assets and liabilities) that give rise to Mexican currency exchange rate movements for Mexican income tax purposes. These subsidiaries also have deferred income tax assets and liabilities that are denominated in the Mexican peso, which must be translated into U.S. dollars for financial reporting purposes. From time to time, we may utilize short-term foreign currency derivatives at our subsidiaries and at the consolidated level as a means to manage the risk of exposure to significant fluctuations in our income tax expense from these impacts.
 
 
FINANCIAL STATEMENT PRESENTATION
 
The following tables provide the fair values of derivative instruments, without consideration of margin deposits held or posted, on the Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011:
 

DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
   
September 30, 2012
                 
Deferred
                 
credits
     
Current
     
Current
 
and other
     
assets:
     
liabilities:
 
liabilities:
     
Fixed-price
 
Investments
 
Fixed-price
 
Fixed-price
     
contracts
 
and other
 
contracts
 
contracts
     
and other
 
assets:
 
and other
 
and other
Derivatives designated as hedging instruments
 
derivatives(1)
 
Sundry
 
derivatives(2)
 
derivatives
Sempra Energy Consolidated:
               
    Interest rate instruments(3)
$
 6 
$
 15 
$
 (20)
$
 (69)
    Commodity contracts not subject to rate recovery
 
 ― 
 
 ― 
 
 (3)
 
 ― 
    Total
$
 6 
$
 15 
$
 (23)
$
 (69)
SDG&E:
               
    Interest rate instruments(3)
$
 ― 
$
 ― 
$
 (17)
$
 (68)
                   
Derivatives not designated as hedging instruments
               
Sempra Energy Consolidated:
               
    Interest rate and foreign exchange instruments
$
 8 
$
 43 
$
 (8)
$
 (38)
    Commodity contracts not subject to rate recovery
 
 119 
 
 19 
 
 (131)
 
 (31)
        Associated offsetting commodity contracts
 
 (111)
 
 (15)
 
 111 
 
 15 
    Commodity contracts subject to rate recovery
 
 9 
 
 20 
 
 (39)
 
 (7)
        Associated offsetting commodity contracts
 
 (5)
 
 (1)
 
 5 
 
 1 
    Total
$
 20 
$
 66 
$
 (62)
$
 (60)
SDG&E:
               
    Commodity contracts subject to rate recovery
$
 7 
$
 20 
$
 (37)
$
 (7)
        Associated offsetting commodity contracts
 
 (4)
 
 (1)
 
 4 
 
 1 
    Total
$
 3 
$
 19 
$
 (33)
$
 (6)
SoCalGas:
               
    Commodity contracts subject to rate recovery
$
 2 
$
 ― 
$
 (2)
$
 ― 
        Associated offsetting commodity contracts
 
 (1)
 
 ― 
 
 1 
 
 ― 
    Total
$
 1 
$
 ― 
$
 (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.
                   
 

 
DERIVATIVE INSTRUMENTS ON THE CONDENSED CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
   
December 31, 2011
                 
Deferred
                 
credits
     
Current
     
Current
 
and other
     
assets:
     
liabilities:
 
liabilities:
     
Fixed-price
 
Investments
 
Fixed-price
 
Fixed-price
     
contracts
 
and other
 
contracts
 
contracts
     
and other
 
assets:
 
and other
 
and other
Derivatives designated as hedging instruments
 
derivatives(1)
 
Sundry
 
derivatives(2)
 
derivatives
Sempra Energy Consolidated:
               
    Interest rate instruments(3)
$
 5 
$
 11 
$
 (17)
$
 (65)
SDG&E:
               
    Interest rate instruments(3)
$
 ― 
$
 ― 
$
 (16)
$
 (65)
                   
Derivatives not designated as hedging instruments
               
Sempra Energy Consolidated:
               
    Interest rate instruments
$
 8 
$
 41 
$
 (7)
$
 (36)
    Commodity contracts not subject to rate recovery
 
 156 
 
 72 
 
 (148)
 
 (94)
        Associated offsetting commodity contracts
 
 (120)
 
 (68)
 
 120 
 
 68 
    Commodity contracts subject to rate recovery
 
 28 
 
 8 
 
 (62)
 
 (24)
        Associated offsetting commodity contracts
 
 (10)
 
 (2)
 
 10 
 
 2 
    Total
$
 62 
$
 51 
$
 (87)
$
 (84)
SDG&E:
               
    Commodity contracts subject to rate recovery
$
 22 
$
 8 
$
 (55)
$
 (24)
        Associated offsetting commodity contracts
 
 (5)
 
 (2)
 
 5 
 
 2 
    Total
$
 17 
$
 6 
$
 (50)
$
 (22)
SoCalGas:
               
    Commodity contracts subject to rate recovery
$
 6 
$
 ― 
$
 (7)
$
 ― 
        Associated offsetting commodity contracts
 
 (5)
 
 ― 
 
 5 
 
 ― 
    Total
$
 1 
$
 ― 
$
 (2)
$
 ― 
(1)
Included in Current Assets: Other for SoCalGas.
               
(2)
Included in Current Liabilities: Other for SoCalGas.
               
(3)
Includes Otay Mesa VIE. All of SDG&E’s amounts relate to Otay Mesa VIE.

 
The effects of derivative instruments designated as hedges on the Condensed Consolidated Statements of Operations and on Other Comprehensive Income (OCI) and Accumulated Other Comprehensive Income (AOCI) for the three months and nine months ended September 30 were:
 
 
FAIR VALUE HEDGE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
       
     
Gain on derivatives recognized in earnings
Gain (loss) on derivatives recognized in earnings
     
Three months ended September 30,
Nine months ended September 30,
 
Location
2012 
2011 
2012 
2011 
Sempra Energy Consolidated:
               
    Interest rate instruments
Interest Expense
$
 1 
$
 2 
$
 5 
$
 7 
    Interest rate instruments
Other Income, Net
 
 4 
 
 13 
 
 6 
 
 16 
    Total(1)
 
$
 5 
$
 15 
$
 11 
$
 23 
SoCalGas:
                 
    Interest rate instrument
Interest Expense
$
 ― 
$
 ― 
$
 ― 
$
 1 
    Interest rate instrument
Other Income, Net
 
 ― 
 
 ― 
 
 ― 
 
 (3)
    Total(1)
 
$
 ― 
$
 ― 
$
 ― 
$
 (2)
(1)
There has been no hedge ineffectiveness on these swaps. 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.
 

 
CASH FLOW HEDGE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
   
Pretax loss recognized
   
Gain (loss) reclassified from AOCI
   
in OCI (effective portion)
   
into earnings (effective portion)
   
Three months ended September 30,
   
Three months ended September 30,
 
2012 
2011 
 
Location
2012 
2011 
Sempra Energy Consolidated:
                   
    Interest rate instruments(1)
$
 (6)
$
 (21)
 
Interest Expense
$
 (3)
$
 4 
             
Equity Losses,
       
    Interest rate instruments
 
 (6)
 
 (27)
 
    Before Income Tax
 
 (4)
 
 (2)
    Commodity contracts not subject
         
Cost of Natural Gas, Electric
       
        to rate recovery
 
 (3)
 
 ― 
 
    Fuel and Purchased Power
 
 ― 
 
 ― 
    Total
$
 (15)
$
 (48)
   
$
 (7)
$
 2 
SDG&E:
                   
    Interest rate instruments(1)
$
 (6)
$
 (21)
 
Interest Expense
$
 (2)
$
 4 
SoCalGas:
                   
    Interest rate instruments
$
 ― 
$
 ― 
 
Interest Expense
$
 (1)
$
 (1)
   
Nine months ended September 30,
   
Nine months ended September 30,
 
2012 
2011 
 
Location
2012 
2011 
Sempra Energy Consolidated:
                   
    Interest rate instruments(1)
$
 (21)
$
 (32)
 
Interest Expense
$
 (5)
$
 ― 
             
Equity Losses,
       
    Interest rate instruments
 
 (12)
 
 (34)
 
    Before Income Tax
 
 (4)
 
 (3)
    Commodity contracts not subject
         
Cost of Natural Gas, Electric
       
        to rate recovery
 
 (3)
 
 ― 
 
    Fuel and Purchased Power
 
 ― 
 
 ― 
    Total
$
 (36)
$
 (66)
   
$
 (9)
$
 (3)
SDG&E:
                   
    Interest rate instruments(1)
$
 (16)
$
 (32)
 
Interest Expense
$
 (3)
$
 2 
SoCalGas:
                   
    Interest rate instruments
$
 ― 
$
 ― 
 
Interest Expense
$
 (2)
$
 (3)
(1)
Amounts include Otay Mesa VIE. All of SDG&E’s interest rate derivative activity relates to Otay Mesa VIE. There has been a negligible amount of ineffectiveness related to these swaps.

Sempra Energy expects that losses of $18 million, 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. Actual amounts ultimately reclassified into earnings depend on the interest rates in effect when derivative contracts that are currently outstanding mature.
 
SDG&E and SoCalGas expect that losses of $8 million and $1 million, respectively, 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 term over which we are hedging exposure to the variability of cash flows at September 30, 2012 is approximately 17 years and 7 years for Sempra Energy and SDG&E, respectively. The maximum term of hedged interest rate variability related to debt at Sempra Renewables’ equity method investees is 18 years.
 
We recorded $1 million of hedge ineffectiveness in both the three months and nine months ended September 30, 2012.
 
The effects of derivative instruments not designated as hedging instruments on the Condensed Consolidated Statements of Operations for the three months and nine months ended September 30 were:
 

UNDESIGNATED DERIVATIVE IMPACT ON THE CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Dollars in millions)
     
Gain (loss) on derivatives recognized in earnings
     
Three months ended September 30,
Nine months ended September 30,
 
Location
2012 
2011 
2012 
2011 
Sempra Energy Consolidated:
                 
    Interest rate and foreign exchange
                 
         instruments
Other Income, Net
$
 1 
$
 (26)
$
 11 
$
 (14)
    Commodity contracts not subject
Revenues: Energy-Related
               
        to rate recovery
    Businesses
 
 (5)
 
 3 
 
 (3)
 
 17 
    Commodity contracts not subject
Cost of Natural Gas, Electric
               
        to rate recovery
    Fuel and Purchased Power
 
 ― 
 
 ― 
 
 ― 
 
 1 
    Commodity contracts not subject
                 
        to rate recovery
Operation and Maintenance
 
 1 
 
 ― 
 
 1 
 
 1 
    Commodity contracts subject
Cost of Electric Fuel
               
        to rate recovery
    and Purchased Power
 
 41 
 
 (15)
 
 32 
 
 (6)
    Commodity contracts subject
                 
        to rate recovery
Cost of Natural Gas
 
 ― 
 
 (2)
 
 (1)
 
 (1)
    Total
 
$
 38 
$
 (40)
$
 40 
$
 (2)
SDG&E:
                 
    Commodity contracts not subject
                 
        to rate recovery
Operation and Maintenance
$
 ― 
$
 (1)
$
 ― 
$
 ― 
    Commodity contracts subject
Cost of Electric Fuel
               
        to rate recovery
    and Purchased Power
 
 41 
 
 (15)
 
 32 
 
 (6)
    Total
 
$
 41 
$
 (16)
$
 32 
$
 (6)
SoCalGas:
                 
    Commodity contracts not subject
                 
        to rate recovery
Operation and Maintenance
$
 1 
$
 (1)
$
 1 
$
 ― 
    Commodity contracts subject
                 
        to rate recovery
Cost of Natural Gas
 
 ― 
 
 (2)
 
 (1)
 
 (1)
    Total
 
$
 1 
$
 (3)
$
 ― 
$
 (1)
 
 
CONTINGENT FEATURES
 
For Sempra Energy and SDG&E, certain of our derivative instruments contain credit limits which vary depending upon 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 and SDG&E, the total fair value of this group of derivative instruments in a net liability position at September 30, 2012 is $11 million and $6 million, respectively. As of September 30, 2012, if the credit ratings of Sempra Energy and SDG&E were reduced below investment grade, $11 million and $6 million, respectively, of additional assets could be required to be posted as collateral for these derivative contracts.
 
For Sempra Energy, 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 Notes 1 and 2 of the Notes to Consolidated Financial Statements in the Updated Annual Report. We have not changed the valuation techniques or inputs we use to measure fair value during the nine months ended September 30, 2012.
 
 
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 as of September 30, 2012 and December 31, 2011. 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.
 
The fair value of commodity derivative assets and liabilities is determined in accordance with our netting policy, as discussed below under “Derivative Positions Net of Cash Collateral.”
 
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 as of September 30, 2012 and December 31, 2011 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 securities are valued using quoted prices listed on nationally recognized securities exchanges or based on closing prices reported in the active market in which the identical security is traded (Level 1). Other debt securities are valued based on yields that are currently available for comparable securities of issuers with similar credit ratings (Level 2).
 
§  
We enter into commodity contracts and interest rate derivatives primarily as a means to manage price exposures. 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). All Level 3 recurring items are related to CRRs at SDG&E, as discussed below under “Level 3 Information.” Commodity derivative contracts that are subject to rate recovery are recorded as commodity costs that are offset by regulatory account balances and are recovered in rates.
 
§  
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).
 
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)
 
At fair value as of September 30, 2012
               
Collateral
   
   
Level 1
 
Level 2
 
Level 3
 
netted
 
Total
Assets:
                   
    Nuclear decommissioning trusts:
                   
          Equity securities
$
 529 
$
 ― 
$
 ― 
$
 ― 
$
 529 
          Debt securities:
                   
              Debt securities issued by the U.S. Treasury and other
                   
                   U.S. government corporations and agencies
 
 72 
 
 74 
 
 ― 
 
 ― 
 
 146 
              Municipal bonds
 
 ― 
 
 66 
 
 ― 
 
 ― 
 
 66 
              Other securities
 
 ― 
 
 123 
 
 ― 
 
 ― 
 
 123 
          Total debt securities
 
 72 
 
 263 
 
 ― 
 
 ― 
 
 335 
    Total nuclear decommissioning trusts(1)
 
 601 
 
 263 
 
 ― 
 
 ― 
 
 864 
    Interest rate instruments
 
 ― 
 
 73 
 
 ― 
 
 ― 
 
 73 
    Commodity contracts subject to rate recovery
 
 21 
 
 ― 
 
 23 
 
 ― 
 
 44 
    Commodity contracts not subject to rate recovery
 
 19 
 
 19 
 
 ― 
 
 ― 
 
 38 
    Investments
 
 1 
 
 ― 
 
 ― 
 
 ― 
 
 1 
Total
$
 642 
$
 355 
$
 23 
$
 ― 
$
 1,020 
Liabilities:
                   
    Interest rate and foreign exchange instruments
$
 ― 
$
 136 
$
 ― 
$
 ― 
$
 136 
    Commodity contracts subject to rate recovery
 
 32 
 
 8 
 
 ― 
 
 (32)
 
 8 
    Commodity contracts not subject to rate recovery
 
 9 
 
 30 
 
 ― 
 
 (13)
 
 26 
Total
$
 41 
$
 174 
$
 ― 
$
 (45)
$
 170 
                     
 
At fair value as of December 31, 2011
               
Collateral
   
   
Level 1
 
Level 2
 
Level 3
 
netted
 
Total
Assets:
                   
    Nuclear decommissioning trusts:
                   
          Equity securities
$
 468 
$
 ― 
$
 ― 
$
 ― 
$
 468 
          Debt securities:
                   
              Debt securities issued by the U.S. Treasury and other
                   
                   U.S. government corporations and agencies
 
 92 
 
 78 
 
 ― 
 
 ― 
 
 170 
              Municipal bonds
 
 ― 
 
 77 
 
 ― 
 
 ― 
 
 77 
              Other securities
 
 ― 
 
 78 
 
 ― 
 
 ― 
 
 78 
          Total debt securities
 
 92 
 
 233 
 
 ― 
 
 ― 
 
 325 
    Total nuclear decommissioning trusts(1)
 
 560 
 
 233 
 
 ― 
 
 ― 
 
 793 
    Interest rate instruments
 
 ― 
 
 66 
 
 ― 
 
 ― 
 
 66 
    Commodity contracts subject to rate recovery
 
 10 
 
 1 
 
 23 
 
 ― 
 
 34 
    Commodity contracts not subject to rate recovery
 
 15 
 
 35 
 
 ― 
 
 (2)
 
 48 
    Investments
 
 5 
 
 ― 
 
 ― 
 
 ― 
 
 5 
Total
$
 590 
$
 335 
$
 23 
$
 (2)
$
 946 
Liabilities:
                   
    Interest rate instruments
$
 1 
$
 124 
$
 ― 
$
 ― 
$
 125 
    Commodity contracts subject to rate recovery
 
 61 
 
 13 
 
 ― 
 
 (61)
 
 13 
    Commodity contracts not subject to rate recovery
 
 1 
 
 52 
 
 ― 
 
 (4)
 
 49 
Total
$
 63 
$
 189 
$
 ― 
$
 (65)
$
 187 
(1)
Excludes cash balances and cash equivalents.
                   


RECURRING FAIR VALUE MEASURES – SDG&E
(Dollars in millions)
 
At fair value as of September 30, 2012
               
Collateral
   
   
Level 1
 
Level 2
 
Level 3
 
netted
 
Total
Assets:
                   
    Nuclear decommissioning trusts:
                   
          Equity securities
$
 529 
$
 ― 
$
 ― 
$
 ― 
$
 529 
          Debt securities:
                   
              Debt securities issued by the U.S. Treasury and other
                   
                   U.S. government corporations and agencies
 
 72 
 
 74 
 
 ― 
 
 ― 
 
 146 
              Municipal bonds
 
 ― 
 
 66 
 
 ― 
 
 ― 
 
 66 
              Other securities
 
 ― 
 
 123 
 
 ― 
 
 ― 
 
 123 
          Total debt securities
 
 72 
 
 263 
 
 ― 
 
 ― 
 
 335 
    Total nuclear decommissioning trusts(1)
 
 601 
 
 263 
 
 ― 
 
 ― 
 
 864 
    Commodity contracts subject to rate recovery
 
 19 
 
 ― 
 
 23 
 
 ― 
 
 42 
    Commodity contracts not subject to rate recovery
 
 2 
 
 ― 
 
 ― 
 
 ― 
 
 2 
Total
$
 622 
$
 263 
$
 23 
$
 ― 
$
 908 
                     
Liabilities:
                   
    Interest rate instruments
$
 ― 
$
 85 
$
 ― 
$
 ― 
$
 85 
    Commodity contracts subject to rate recovery
 
 32 
 
 7 
 
 ― 
 
 (32)
 
 7 
Total
$
 32 
$
 92 
$
 ― 
$
 (32)
$
 92 
                     
 
At fair value as of December 31, 2011
               
Collateral
   
   
Level 1
 
Level 2
 
Level 3
 
netted
 
Total
Assets:
                   
    Nuclear decommissioning trusts:
                   
          Equity securities
$
 468 
$
 ― 
$
 ― 
$
 ― 
$
 468 
          Debt securities:
                   
              Debt securities issued by the U.S. Treasury and other
                   
                   U.S. government corporations and agencies
 
 92 
 
 78 
 
 ― 
 
 ― 
 
 170 
              Municipal bonds
 
 ― 
 
 77 
 
 ― 
 
 ― 
 
 77 
              Other securities
 
 ― 
 
 78 
 
 ― 
 
 ― 
 
 78 
          Total debt securities
 
 92 
 
 233 
 
 ― 
 
 ― 
 
 325 
    Total nuclear decommissioning trusts(1)
 
 560 
 
 233 
 
 ― 
 
 ― 
 
 793 
    Commodity contracts subject to rate recovery
 
 9 
 
 ― 
 
 23 
 
 ― 
 
 32 
    Commodity contracts not subject to rate recovery
 
 1 
 
 ― 
 
 ― 
 
 ― 
 
 1 
Total
$
 570 
$
 233 
$
 23 
$
 ― 
$
 826 
                     
Liabilities:
                   
    Interest rate instruments
$
 ― 
$
 81 
$
 ― 
$
 ― 
$
 81 
    Commodity contracts subject to rate recovery
 
 61 
 
 12 
 
 ― 
 
 (61)
 
 12 
Total
$
 61 
$
 93 
$
 ― 
$
 (61)
$
 93 
(1)
Excludes cash balances and cash equivalents.
                   


RECURRING FAIR VALUE MEASURES – SOCALGAS
(Dollars in millions)
 
At fair value as of September 30, 2012
               
Collateral
   
   
Level 1
 
Level 2
 
Level 3
 
netted
 
Total
Assets:
                   
    Commodity contracts subject to rate recovery
$
 2 
$
 ― 
$
 ― 
$
 ― 
$
 2 
    Commodity contracts not subject to rate recovery
 
 2 
 
 ― 
 
 ― 
 
 ― 
 
 2 
Total
$
 4 
$
 ― 
$
 ― 
$
 ― 
$
 4 
                     
Liabilities:
                   
    Commodity contracts subject to rate recovery
$
 ― 
$
 1 
$
 ― 
$
 ― 
$
 1 
Total
$
 ― 
$
 1 
$
 ― 
$
 ― 
$
 1 
                     
 
At fair value as of December 31, 2011
               
Collateral
   
   
Level 1
 
Level 2
 
Level 3
 
netted
 
Total
Assets:
                   
    Commodity contracts subject to rate recovery
$
 1 
$
 1 
$
 ― 
$
 ― 
$
 2 
    Commodity contracts not subject to rate recovery
 
 2 
 
 ― 
 
 ― 
 
 ― 
 
 2 
Total
$
 3 
$
 1 
$
 ― 
$
 ― 
$
 4 
                     
Liabilities:
                   
    Commodity contracts subject to rate recovery
$
 ― 
$
 1 
$
 ― 
$
 ― 
$
 1 
Total
$
 ― 
$
 1 
$
 ― 
$
 ― 
$
 1 

 
Level 3 Information
 
The following table sets forth reconciliations of changes in the fair value of CRRs classified as Level 3 in the fair value hierarchy for Sempra Energy Consolidated and SDG&E:
 

 
Three months ended September 30,
(Dollars in millions)
2012 
2011 
Balance as of July 1
$
 13 
$
 3 
    Realized and unrealized gains
 
 16 
 
 5 
    Allocated transmission instruments
 
 17 
 
 ― 
    Settlements
 
 (23)
 
 (5)
Balance as of September 30
$
 23 
$
 3 
Change in unrealized gains or losses relating to
       
    instruments still held at September 30
$
 ― 
$
 ― 
 

 
 
Nine months ended September 30,
(Dollars in millions)
2012 
2011 
Balance as of January 1
$
 23 
$
 2 
    Realized and unrealized gains
 
 23 
 
 17 
    Allocated transmission instruments
 
 18 
 
 2 
    Settlements
 
 (41)
 
 (18)
Balance as of September 30
$
 23 
$
 3 
Change in unrealized gains or losses relating to
       
    instruments still held at September 30
$
 ― 
$
 ― 

CRRs are recorded at fair value based almost entirely on the most current auction prices published by the California Independent System Operator (ISO), an objective source. The impact associated with discounting is negligible. Because auction prices are a less observable input, these instruments are classified as Level 3. Auction prices range from $(3) per MWh to $5 per MWh at a given location, and the fair value of these instruments is derived from auction price differences between two locations. Positive values between two locations represent expected future reductions in congestion costs, whereas negative values between two locations represent expected future charges. Valuation of our CRRs is sensitive to a change in auction price. If auction prices at one location increase (decrease) relative to another location, this could result in a higher (lower) fair value measurement. We summarize CRR volumes in Note 7. The earnings impacts of CRRs are deferred and recorded in regulatory accounts to the extent they are recoverable or refundable through rates. Upon settlement, CRRs are included in Cost of Electric Fuel and Purchased Power on the Condensed Consolidated Statements of Operations.
 
 
Derivative Positions Net of Cash Collateral
 
Each Condensed Consolidated Balance Sheet reflects the offsetting of net derivative positions with fair value amounts for cash collateral with the same counterparty when management believes a legal right of offset exists.
 
The following table provides the amount of fair value of cash collateral receivables that were not offset in the Condensed Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011:
 

 
September 30,
December 31,
(Dollars in millions)
2012 
2011 
Sempra Energy Consolidated
$
 46 
$
 20 
SDG&E
 
 20 
 
 10 
SoCalGas
 
 4 
 
 2 
 
Fair Value of Financial Instruments
 
The fair values of certain of our financial instruments (cash, temporary investments, accounts and notes receivable, dividends and accounts payable, short-term debt and customer deposits) approximate their carrying amounts. The following table provides the carrying amounts and fair values of certain other financial instruments at September 30, 2012 and December 31, 2011:
 


FAIR VALUE OF FINANCIAL INSTRUMENTS
(Dollars in millions)
   
September 30, 2012
   
Carrying
 
Fair Value
   
Amount
 
Level 1
Level 2
Level 3
Total
Sempra Energy Consolidated:
                     
Investments in affordable housing partnerships(1)
$
 16 
 
$
 ― 
$
 ― 
$
 46 
$
 46 
Total long-term debt(2)
 
 11,727 
   
 ― 
 
 12,556 
 
 755 
 
 13,311 
Preferred stock of subsidiaries
 
 99 
   
 ― 
 
 108 
 
 ― 
 
 108 
SDG&E:
                     
Total long-term debt(3)
$
 4,137 
 
$
 ― 
$
 4,308 
$
 347 
$
 4,655 
Contingently redeemable preferred stock
 
 79 
   
 ― 
 
 86 
 
 ― 
 
 86 
SoCalGas:
                     
Total long-term debt(4)
$
 1,662 
 
$
 ― 
$
 1,872 
$
 ― 
$
 1,872 
Preferred stock
 
 22 
   
 ― 
 
 24 
 
 ― 
 
 24 
                         
   
December 31, 2011
   
Carrying
 
Fair Value
   
Amount
 
Level 1
Level 2
Level 3
Total
Sempra Energy Consolidated:
                     
Investments in affordable housing partnerships(1)
$
 21 
 
$
 ― 
$
 ― 
$
 48 
$
 48 
Total long-term debt(2)
 
 9,826 
   
 ― 
 
 10,447 
 
 600 
 
 11,047 
Preferred stock of subsidiaries
 
 99 
   
 ― 
 
 106 
 
 ― 
 
 106 
SDG&E:
                     
Total long-term debt(3)
$
 3,895 
 
$
 ― 
$
 3,933 
$
 355 
$
 4,288 
Contingently redeemable preferred stock
 
 79 
   
 ― 
 
 86 
 
 ― 
 
 86 
SoCalGas:
                     
Total long-term debt(4)
$
 1,313 
 
$
 ― 
$
 1,506 
$
 ― 
$
 1,506 
Preferred stock
 
 22 
   
 ― 
 
 23 
 
 ― 
 
 23 
(1)
We discuss our investments in affordable housing partnerships in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
(2)
Before reductions for unamortized discount (net of premium) of $17 million at September 30, 2012 and $16 million at December 31, 2011, and excluding capital leases of $192 million at September 30, 2012 and $204 million at December 31, 2011, and commercial paper classified as long-term debt of $400 million at December 31, 2011. We discuss our long-term debt in Note 6 above and in Note 5 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
(3)
Before reductions for unamortized discount of $12 million at September 30, 2012 and $11 million at December 31, 2011, and excluding capital leases of $187 million at September 30, 2012 and $193 million at December 31, 2011.
(4)
Before reductions for unamortized discount of $4 million at September 30, 2012 and $3 million at December 31, 2011, and excluding capital leases of $5 million at September 30, 2012 and $11 million at December 31, 2011.

We calculate the fair value of our investments in affordable housing partnerships using an income approach based on the present value of estimated future cash flows discounted at rates available for similar investments (Level 3).
 
We base the fair value of certain of our long-term debt and preferred stock on a market approach using quoted market prices for identical or similar securities in thinly-traded markets (Level 2). 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).
 
 
Nuclear Decommissioning Trusts
 
We discuss SDG&E’s investments in nuclear decommissioning trust funds in Note 6 of the Notes to Consolidated Financial Statements in the Updated Annual Report. The following table shows the fair values and gross unrealized gains and losses for the securities held in the trust funds:
 

NUCLEAR DECOMMISSIONING TRUSTS
(Dollars in millions)
         
Gross
 
Gross
 
Estimated
         
Unrealized
 
Unrealized
 
Fair
     
Cost
 
Gains
 
Losses
 
Value
As of September 30, 2012:
               
Debt securities:
               
    Debt securities issued by the U.S. Treasury and other
               
         U.S. government corporations and agencies(1)
$
 134 
$
 12 
$
 ― 
$
 146 
    Municipal bonds(2)
 
 60 
 
 6 
 
 ― 
 
 66 
    Other securities(3)
 
 114 
 
 9 
 
 ― 
 
 123 
Total debt securities
 
 308 
 
 27 
 
 ― 
 
 335 
Equity securities
 
 249 
 
 284 
 
 (4)
 
 529 
Cash and cash equivalents
 
 28 
 
 ― 
 
 ― 
 
 28 
Total
$
 585 
$
 311 
$
 (4)
$
 892 
As of December 31, 2011:
               
Debt securities:
               
    Debt securities issued by the U.S. Treasury and other
               
         U.S. government corporations and agencies
$
 157 
$
 13 
$
 ― 
$
 170 
    Municipal bonds
 
 72 
 
 5 
 
 ― 
 
 77 
    Other securities
 
 76 
 
 3 
 
 (1)
 
 78 
Total debt securities
 
 305 
 
 21 
 
 (1)
 
 325 
Equity securities
 
 246 
 
 227 
 
 (5)
 
 468 
Cash and cash equivalents
 
 11 
 
 ― 
 
 ― 
 
 11 
Total
$
 562 
$
 248 
$
 (6)
$
 804 
(1)
Maturity dates are 2013-2042
(2)
Maturity dates are 2012-2057
(3)
Maturity dates are 2013-2111

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

SALES OF SECURITIES
(Dollars in millions)
 
Three months ended September 30,
Nine months ended September 30,
 
2012 
2011 
2012 
2011 
Proceeds from sales
$
 204 
$
 294 
$
 524 
$
 384 
Gross realized gains
 
 3 
 
 27 
 
 12 
 
 29 
Gross realized losses
 
 (1)
 
 (8)
 
 (6)
 
 (10)

Net unrealized gains (losses) are included in Regulatory Liabilities Arising from Removal Obligations on the Condensed Consolidated Balance Sheets. We determine the cost of securities in the trusts on the basis of specific identification.
 
 
Non-Recurring Fair Value Measures – Sempra Energy Consolidated
 
We discuss non-recurring fair value measures and the associated accounting impact on our investments in RBS Sempra Commodities and Argentina in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report and, with regard to RBS Sempra Commodities, in Note 4 above. We also discuss non-recurring fair value measures and the associated accounting impact on our investment in Rockies Express in Note 4 above.
 
 
Rockies Express
 
In the second quarter of 2012, the noncash impairment charge of $300 million ($179 million after-tax) primarily resulted from the continuing decline in basis differential on REX associated with shale gas production zones coming on line, assumptions related to the re-contracting of the long-term transportation agreements, and the refinancing of the existing project level debt, discussed further below. The fair value measurement was significantly impacted by unobservable inputs (Level 3) as defined by the accounting guidance for fair value measurements, which we discuss in Note 11 of the Notes to Consolidated Financial Statements in the Updated Annual Report. We considered a market participant’s view of the total value for Rockies Express, based on an estimation of the future cash distributions it would be able to generate, adjusted for our 25-percent ownership interest. To estimate future cash distributions, we considered factors impacting Rockies Express’ ability to pay future distributions including:
 
§  
the extent to which future cash flows are hedged by capacity sales contracts and their duration (generally through 2019), as well as the creditworthiness of the various counterparties;
 
§  
Rockies Express’ future financing needs, including the ability to secure borrowings at reasonable rates as well as potentially using operating cash to retire principal;
 
§  
prospects for generating attractive revenues and cash flows beyond 2019, including natural gas’ future basis differentials (driven by the location and extent of future supply and demand) and alternative strategies potentially available to utilize the assets; and
 
§  
discount rates commensurate with the risks inherent in the cash flows.
 
In the third quarter of 2012, KMI reached an agreement, expected to close in the fourth quarter of 2012, to sell the FTC-mandated asset group, which includes its interest in Rockies Express. Events in the third quarter of 2012 related to this agreement have provided us with additional market participant data. We therefore updated our analysis of the fair value of our investment in Rockies Express as of September 30, 2012 to reflect these additional inputs and recorded an additional impairment charge of $100 million ($60 million after-tax). This fair value measurement in the third quarter was based primarily on the Level 2 input.  We believe this is useful and reliable information, but we considered that it may be impacted by the FTC’s requirement for KMI to sell its interest in Rockies Express. To reflect this uncertainty, our updated analysis included the less subjective Level 2 market participant input as the primary indicator of fair value, with less weight ascribed to value based on estimated discounted cash flows as discussed above and in the table below. The updates to the cash flow analyses used in determining fair value in the second quarter reflected discussions with Tallgrass as to the strategic direction they are planning to take with their equity partners for Rockies Express, as well as additional discussions with other market participants. Tallgrass is expected to be the operator of Rockies Express.
 
We believe our analysis forms a reasonable estimate of the fair value of Rockies Express. This estimate includes the material input described above, which was generally observable during the period most relevant to our analysis. Regarding the unobservable inputs, significant uncertainties exist with regard to REX’s ability to secure attractive revenues beyond 2019. Accordingly, our analysis suggests that the fair value of our investment in Rockies Express could be materially different from the value we have estimated at this time. For example, if REX is able to sustain the level of revenues currently generated beyond 2019, the value of our investment in Rockies Express would be materially enhanced and the indicated value of our investment in Rockies Express could be significantly higher. Conversely, if REX is unable to sell its transport capacity at sufficient rates or in sufficient volumes beyond 2019, the fair value of our investment in Rockies Express could be materially lower than our carrying amount. Separately, future events involving REX equity could occur and may also provide additional information regarding the fair value of our investment in REX.
 
Sempra Natural Gas developed the models and scenarios used to measure the fair value of our investment in REX.  This modeling used inputs from external sources as described above and in the table below, as well as internally available data, such as operating and maintenance budgets used for financial planning purposes.  External experts that forecast the future price of natural gas at various physical locations were also engaged to help validate certain scenarios and modeling assumptions.  The fair value measurements were reviewed in detail by Sempra Natural Gas’ financial management, as well as Sempra Energy’s financial management team.
 
 
RBS Sempra Commodities
 
In both the three months and nine months ended September 30, 2011, we reduced our investment in RBS Sempra Commodities to reflect the latest estimates of our expected future cash distributions from the partnership.  This fair value measurement was significantly impacted by unobservable inputs (i.e. Level 3 inputs) as described in the table below.
 
The following table summarizes significant inputs impacting non-recurring fair value measures related to our investments in REX and RBS Sempra Commodities:
 

NON-RECURRING FAIR VALUE MEASURES – SEMPRA ENERGY CONSOLIDATED
(Dollars in millions)
 
Estimated
 
Fair
     
 
Fair
 
Value
% of Fair Value
 
Range of
 
Value
Valuation Technique
Hierarchy
Measurement
Inputs Used to Develop Measurement
Inputs
Investment in
           
Rockies Express
$ 369
Market approach
Level 2
67%
Equity sale offer price
100%
             
             
   
Probability weighted
Level 3
33%
Combined transportation rate assumption(1)
6% - 78%
   
discounted cash flow
   
Counterparty credit risk on existing contracts
Low
         
Operation and maintenance escalation rate
0% - 1%
         
Forecasted interest rate on debt to be refinanced
5% - 10%
         
Discount rate
8% - 10%
Investment in
           
RBS Sempra
           
Commodities
$ 126
Discounted cash flow
Level 3
100%
Future cash distributions
90% - 110%
(1)
Transportation rate beyond existing contract terms as a percentage of current mean REX rates.

 
 
 

NOTE 9. CALIFORNIA UTILITIES' REGULATORY MATTERS
 

 
JOINT MATTERS
 
 
General Rate Case (GRC)
 
The CPUC uses a general rate case proceeding to prospectively set rates sufficient 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. In December 2010, the California Utilities filed their 2012 General Rate Case (GRC) applications to establish their authorized 2012 revenue requirements and the ratemaking mechanisms by which those requirements will change on an annual basis over the subsequent three-year (2013-2015) period. Both SDG&E and SoCalGas filed revised applications with the CPUC in July 2011. Evidentiary hearings were completed in January 2012, and final briefs reflecting the results from these hearings were filed with the CPUC in May 2012.
 
In February 2012, the California Utilities filed amendments to update their July 2011 revised applications. With these amendments, SDG&E is requesting a revenue requirement in 2012 of $1.849 billion, an increase of $235 million (or 14.6%) over 2011, of which $67 million is being requested for cost recovery of the incremental wildfire insurance premiums which are not included in the 2011 revenue requirement as set forth in the 2008 GRC. SoCalGas is requesting a revenue requirement in 2012 of $2.112 billion, an increase of $268 million (14.5%) over 2011. The Division of Ratepayer Advocates (DRA) is recommending that the CPUC reduce the utilities’ revenue requirements in 2012 by approximately 5 percent compared to 2011.
 
Until such time as a final decision for the 2012 GRC is issued, the California Utilities are recording revenues in 2012 based on levels authorized in 2011 plus, for SDG&E, consistent with the recent CPUC decisions for cost recovery for SDG&E’s incremental wildfire insurance premiums, an amount for the recovery of 2012 wildfire insurance premiums. The current CPUC schedule indicates a final decision for the 2012 GRC, which will be made effective retroactive to January 1, 2012, by the end of 2012. However, if the CPUC does not issue a final decision for the 2012 GRC by December 31, 2012, Sempra Energy and the California Utilities will not be able to report the retroactive impact to January 1, 2012 of the final decision in their 2012 financial results, but would reflect the impact in 2013 financial results in the period in which such final decision is issued.
 
 
Cost of Capital
 
A cost of capital proceeding determines a utility’s authorized capital structure and authorized rate of return on rate base (ROR), which is a weighted average of the authorized returns on debt, preferred stock, and common equity (return on equity or ROE). The authorized ROR is the rate that the California Utilities are authorized to use in establishing rates to recover their cost of debt and equity, used to finance their investment in electric and natural gas distribution, natural gas transmission and electric generation assets. In addition, a cost of capital proceeding also addresses the automatic ROR adjustment mechanism which applies market-based benchmarks to determine whether an adjustment to the authorized ROR is required during the interim years between cost of capital proceedings.
 
SDG&E and SoCalGas filed separate applications with the CPUC in April 2012 to update their cost of capital effective January 1, 2013. Southern California Edison (Edison) and Pacific Gas and Electric Company (PG&E) also filed separate cost of capital applications with the CPUC. SDG&E proposes to adjust its authorized capital structure by increasing the amount of its common equity from 49.0 percent to 52.0 percent. SDG&E also proposes to lower its authorized ROE from 11.1 percent to 11.0 percent and, as reflected in its supplemental filing with the CPUC in October 2012, to lower its authorized ROR from 8.40 percent to 8.15 percent. SoCalGas proposes to adjust its authorized capital structure by increasing the amount of its common equity from 48.0 percent to 52.0 percent. SoCalGas also proposes to increase its authorized ROE from 10.82 percent to 10.9 percent and, as reflected in its supplemental filing with the CPUC in October 2012, to lower its authorized ROR from 8.68 percent to 8.44 percent. In addition, SDG&E proposes to continue its currently approved cost of capital adjustment mechanism which uses a utility bond benchmark. SoCalGas proposes switching from its current cost of capital adjustment mechanism, which is based on U.S. Treasury Bonds, to a mechanism using a utility bond benchmark similar to SDG&E, Edison and PG&E. Both SDG&E and SoCalGas are proposing to add an “off ramp” provision to the adjustment mechanism as a safeguard to protect against extreme changes in interest rates and to allow the CPUC latitude to suspend the annual mechanism if prudent.
 
The CPUC issued a ruling in June 2012 bifurcating the proceeding. Phase 1 will address each utility’s cost of capital for 2013 with a final decision expected by the end of 2012. Phase 2 will address the cost of capital adjustment mechanisms for SDG&E, SoCalGas, Edison and PG&E, with a final decision expected in the first half of 2013.
 
SDG&E’s current cost of capital adjustment mechanism benchmark is based on the 12-month average monthly A-rated utility bond yield as published by Moody’s for the 12-month period October through September of each fiscal year. If the 12-month average falls outside of a specified range, then SDG&E’s authorized ROE would be adjusted, upward or downward, by one-half of the difference between the 12-month average and the mid-point of the specified range. In addition, SDG&E’s authorized recovery rate for the cost of debt and preferred stock would also be adjusted to their respective actual weighted average cost. Therefore, SDG&E’s authorized ROR would adjust, upward or downward, as a result of all three adjustments with the new rate going into effect on January 1 following the year in which the benchmark range was exceeded. SDG&E’s current mechanism only applies during the intervening years between scheduled cost of capital updates and does not apply for any change in 2013 given the pending cost of capital application and the expectation of an updated cost of capital effective as of January 1, 2013.
 
SoCalGas’ Market Indexed Capital Adjustment Mechanism (MICAM) identifies two conditions for determining whether a change in the authorized rate of return is required. Both conditions are based on the 30-year Treasury bond yields – one being the most recent trailing 12-month rolling average yield and the second being the corresponding 12-month forward forecast yield as published by Global Insight. If both conditions fall outside a specified range in a given month, SoCalGas’ authorized ROE would be adjusted, upward or downward, by one-half of the difference between the trailing 12-month rolling average yield and the midpoint of the range, effective January 1 following the year in which both conditions were exceeded. Also, SoCalGas’ authorized recovery rate for the cost of debt and preferred stock would be adjusted to their respective actual weighted average cost. Therefore, SoCalGas’ authorized ROR would adjust, upward or downward, as a result of all three cost adjustments. In the event of such an event occurring, the benchmark interest rate would be reset to the interest rate in effect at the time it was determined that the benchmark range had been exceeded.
 
In August 2012, the CPUC issued an administrative ruling that confirmed SoCalGas’ participation in Phase 1 of the proceeding and held in abeyance the implementation of SoCalGas’ MICAM triggering event to make the ROE and ROR authorized by the CPUC in this proceeding effective on January 1, 2013.
 
 
Natural Gas Pipeline Operations Safety Assessments
 
Various regulatory agencies, including the CPUC, are evaluating natural gas pipeline safety regulations, practices and procedures. In February 2011, the CPUC opened a forward-looking rulemaking proceeding to examine what changes should be made to existing pipeline safety regulations for California natural gas pipelines. The California Utilities are parties to this proceeding.
 
In June 2011, the CPUC directed SoCalGas, SDG&E, PG&E and Southwest Gas to file comprehensive implementation plans to test or replace all natural gas transmission pipelines that have not been pressure tested. The California Utilities filed their Pipeline Safety Enhancement Plan (PSEP) with the CPUC in August 2011. The proposed safety measures, investments and estimated costs are not included in the California Utilities’ 2012 GRC requests discussed above.
 
In December 2011, the assigned Commissioner to the rulemaking proceeding for the pipeline safety regulations ruled that SDG&E’s and SoCalGas’ Triennial Cost Allocation Proceeding (TCAP) would be the most logical proceeding to conduct the reasonableness and ratemaking review of the companies’ PSEP.
 
In January 2012, the CPUC Consumer Protection and Safety Division (CPSD) issued a Technical Report of the California Utilities’ PSEP.  The report, along with testimony and evidentiary hearings, will be used to evaluate the PSEP in the regulatory process.  Generally, the report found that the PSEP approach to pipeline replacement and pressure testing and other proposed enhancements is reasonable. 
 
In February 2012, the assigned Commissioner in the TCAP issued a ruling setting a schedule for the review of the SDG&E and SoCalGas PSEP with evidentiary hearings held in August 2012. SDG&E and SoCalGas expect a final decision late in the first half of 2013. In April 2012, the CPUC issued an interim decision in the rulemaking proceeding formally transferring the PSEP to the TCAP and authorizing SDG&E and SoCalGas to establish regulatory accounts to record the incremental costs of initiating the PSEP prior to a final decision on the PSEP. The TCAP proceeding will address the recovery of the costs recorded in the regulatory account.
 
In April 2012, the CPUC issued a decision expanding the scope of the rulemaking proceeding to incorporate the provisions of California Senate Bill 705, which requires gas utilities to develop and implement a plan for the safe and reliable operation of their gas pipeline facilities. SDG&E and SoCalGas submitted their pipeline safety plans in June 2012. The CPUC must accept, modify or reject the plans by the end of 2012. The CPUC decision also orders the utilities to undergo independent management and financial audits to assure that the utilities are fully meeting their safety responsibilities. CPSD will select the independent auditors and will oversee the audits. A schedule for the audits has not been established.
 
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 Updated Annual Report.
 
 
Utility Incentive Mechanisms
 
The CPUC applies performance-based measures and incentive mechanisms to all California investor-owned utilities, under which the California Utilities have earnings potential above authorized base margins if they achieve or exceed specific performance and operating goals.
 
We provide additional information regarding these incentive mechanisms in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report, and in the updates below.
 
Energy Efficiency
 
We expect a final decision on an incentive mechanism for the 2013-2014 program period by the end of 2012. We expect a draft decision on how and if an incentive mechanism should apply to the 2010-2012 program cycle and a final decision on any incentive awards for the 2010-2012 period by the end of 2012. The CPUC issued its latest Order Instituting Rulemaking (OIR) in January 2012 to continue its review of the incentive mechanism.
 
Natural Gas Procurement
 
In the first quarter of 2012, the CPUC approved and SoCalGas recorded SoCalGas’ application for its Gas Cost Incentive Mechanism (GCIM) award of $6.2 million for natural gas procured for its core customers during the 12-month period ending March 31, 2011.
 
In June 2012, SoCalGas applied to the CPUC for approval of a GCIM award of $5.4 million for natural gas procured for its core customers during the 12-month period ending March 31, 2012. SoCalGas expects a CPUC decision in the first half of 2013.
 
 
SDG&E MATTERS
 
 
San Onofre Nuclear Generating Station (SONGS)
 
SDG&E has a 20-percent ownership interest in San Onofre Nuclear Generating Station (SONGS), a 2,150-MW nuclear generating facility near San Clemente, California. SONGS is operated by Edison and is subject to the jurisdiction of the Nuclear Regulatory Commission (NRC) and the CPUC.
 
In 2005, the CPUC authorized a project to install four new steam generators in Units 2 and 3 at SONGS and remove and dispose of their predecessor generators. Edison completed the installation of these steam generators in 2010 and 2011 for Units 2 and 3, respectively. In January 2012, a water leak occurred in the Unit 3 steam generator which caused it to be shut down. Edison conducted inspection testing and determined that the water leak was the result of excessive wear from tube-to-tube contact. During a planned maintenance and refueling outage on the Unit 2 steam generators in February 2012, inspections found high levels of unexpected wear in some heat transfer tubes of the Unit 2 steam generators. As of today, both Units 2 and 3 remain offline.
 
Any remedial action that will permit restart of one or both of the Units will need to be approved by the NRC. In March 2012, the NRC issued a Confirmatory Action Letter (CAL) that required NRC permission to restart Unit 2 and Unit 3 and outlined actions that Edison must complete before permission to restart either Unit may be sought. The NRC could also choose to impose additional inspections and assessment processes that could result in significant costs or additional delay. In October 2012, Edison submitted a plan to the NRC to restart and operate Unit 2 at a reduced power level for five months and then shut it down for further inspection. The plan submitted to the NRC does not address Unit 3. It is not clear at this time whether Unit 3 can be restarted without extensive additional repairs, and Edison has not indicated when it believes Unit 3 may be ready to restart operations. The timing of the restart of either of the Units is dependent upon approval by the NRC. The NRC may employ other procedures before making any determination about whether to grant permission pursuant to the terms of the CAL. It is also possible that one or more amendments to the NRC operating license for SONGS might be required (whether or not as a prerequisite to return a Unit to safe operation). There is no set or predetermined time period for such processes, and, accordingly, there can be no assurance about the length of time the NRC may take to review any request to restart submitted by Edison under the CAL or whether any such request would be granted in whole or in part.
 
Through September 30, 2012, SDG&E’s proportional investment in the steam generators was approximately $180 million. These investment amounts remain subject to CPUC review upon submission of Edison’s final costs for the overall project.
 
During the unscheduled outage at SONGS, SDG&E has procured replacement power, the cost of which is fully recovered in revenues subject to a reasonableness review by the CPUC. Replacement power costs for outages associated with the unscheduled SONGS outage (commencing in 2012 on January 31 for Unit 3 and March 5 for Unit 2) through September 30, 2012 were approximately $54 million. Total replacement power costs will not be known until the Units are returned to service.
 
Currently, SDG&E is collecting in customer rates its share of the operating costs, depreciation and return on its investment in SONGS. For the nine-month period ended September 30, 2012, SDG&E has recognized (and collected through customer rates) an estimated $153 million of revenue associated with its investment in SONGS and operating costs. At September 30, 2012, SDG&E’s weighted average rate base investment in SONGS was approximately $220 million and its net book investment, including construction work in progress and nuclear fuel was $485 million.
 
In November 2012, the CPUC issued an Order Instituting Investigation (OII) into the SONGS outage pursuant to California Public Utilities Code Section 455.5 to determine whether Edison and SDG&E should remove from customer rates some or all revenue requirement associated with the portion of the facility that is out of service. This OII will consolidate all SONGS issues from related regulatory proceedings and consider the appropriate cost recovery for SONGS, including among other costs, the cost of the steam generator replacement project, replacement power costs, capital expenditures, operation and maintenance costs and seismic study costs. The OII requires that all costs related to SONGS incurred since January 1, 2012 be tracked in a separate memorandum account, with all revenues collected in recovery of such costs subject to refund, and will address the extent to which such revenues, if any, will be required to be refunded to customers.
 
Under Section 455.5, any determination to adjust rates would be made after hearings are conducted in connection with Edison’s next general rate case. If, after investigation and hearings, the CPUC were to require SDG&E to reduce rates as a result of a Unit being out of service and the Unit is subsequently returned to service, rates may be readjusted to reflect that return to service after 100 continuous hours of operation. Notwithstanding the requirements of Section 455.5, the CPUC may institute other proceedings relating to the impact of the extended outage at SONGS and its potential effects on rates.
 
The steam generators were designed and supplied by Mitsubishi Heavy Industries (MHI) and are warranted for an initial period of 20 years from acceptance. MHI is contractually obligated to repair or replace defective items and to pay specified damages for certain repairs. On July 18, 2012, the NRC issued a report providing the result of the inspection performed by the Augmented Inspection Team (AIT). The inspection concluded that faulty computer modeling that inadequately predicted conditions in the steam generators at SONGS and manufacturing issues contributed to excessive wear of the components. The most probable causes of the tube-to-tube wear were a combination of higher than predicted thermal/hydraulic conditions and changes in the manufacturing of the Unit 3 steam generators. This report also identified a number of yet unresolved issues that are continuing to be examined. Edison’s purchase contract with MHI states that MHI’s liability under the purchase agreement is limited to $137 million and excludes consequential damages, defined to include the cost of replacement power. Such limitations in the contract are subject to applicable exceptions. In September 2012, Edison submitted an invoice on behalf of all owners to MHI in the amount of $45 million for certain steam generator repair costs incurred. Edison expects to continue to invoice MHI for any additional costs incurred.
 
SDG&E is a named insured on the Edison insurance policies covering SONGS. These policies, issued by Nuclear Electric Insurance Limited (NEIL), cover nuclear property and non-nuclear property damage at the SONGS facility, as well as accidental outage insurance. Edison has placed NEIL on notice of potential claims for loss recovery. On October 1, 2012, Edison submitted to NEIL a Partial Proof of Loss on behalf of Edison, SDG&E and the City of Riverside in connection with the outages of SONGS Units 2 and 3. The NEIL policies contain a number of exclusions and limitations that may reduce or eliminate coverage. SDG&E will assist Edison in pursuing claims recoveries from NEIL, as well as warranty claims with MHI, but there is no assurance that SDG&E will recover all or any of its applicable costs pursuant to these arrangements.
 
In light of the aftermath and the significant safety events at the Fukushima Daiichi nuclear plant in Japan resulting from the earthquake and tsunami in March 2011, the NRC plans to perform additional operation and safety reviews of nuclear facilities in the United States. The lessons learned from the events in Japan and the results of the NRC reviews may materially impact future operations and capital requirements at nuclear facilities in the United States, including the operations and capital requirements at SONGS.
 
Edison is also addressing a number of other regulatory and performance issues at SONGS, and the NRC has required Edison to take actions to provide greater assurance of compliance by SONGS personnel. Edison continues to implement plans and address the identified issues, however a number of these issues remain outstanding. To the extent that these issues persist, it is likely that additional action will be required by Edison, which may result in increased SONGS operating costs and/or materially adversely impacted operations. Currently, SDG&E is allowed to fully offset its share of SONGS operating costs in revenue. If further action is required, it may result in an increase in SDG&E’s Operation and Maintenance expense, with any increase being fully offset in Operating Revenues – Electric.
 
We provide more information about SONGS in Note 10 and in Notes 6, 14 and 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
 
Power Procurement and Resource Planning
 
Renewable Energy
 
SDG&E is subject to the Renewables Portfolio Standard (RPS) Program administered by both the CPUC and the California Energy Commission (CEC), which requires each California utility to procure 33 percent of its annual electric energy requirements from renewable energy sources by 2020, with an average of 20 percent required from January 1, 2011 to December 31, 2013; 25 percent by December 31, 2016; and 33 percent by December 31, 2020. The CPUC began a rulemaking in May 2011 to address the implementation of the 33% RPS Program. We discuss the RPS Program further in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
 
South Orange County Reliability Enhancement
 
SDG&E filed an application with the CPUC in May 2012 for a Certificate of Public Convenience and Necessity (CPCN) to construct the South Orange County Reliability Enhancement project. The purpose of the project is to enhance the capacity and reliability of SDG&E’s electric service to the south Orange County area. The proposed project primarily includes replacing and upgrading approximately eight miles of transmission lines and rebuilding and upgrading a substation at an existing site. SDG&E expects a final CPUC decision approving the estimated $473 million project in the second half of 2013. SDG&E obtained approval for the project from the ISO in May 2011. The project is planned to be in service by the second half of 2017.
 
 
Incremental Insurance Premium Cost Recovery
 
In December 2010, the CPUC approved SDG&E’s request for a $29 million revenue requirement for the recovery of the incremental increase in its general liability and wildfire liability insurance premium costs for the July 2009/June 2010 policy period. In its decision approving this cost recovery, the CPUC also authorized SDG&E to request recovery of any incremental insurance premiums for future policy periods through December 31, 2011, with a $5 million deductible applied to each policy renewal period. This approval was in response to a request filed by SDG&E with the CPUC in August 2009 seeking authorization to recover higher liability insurance premiums (amounts in excess of those authorized to be recovered in the 2008 GRC), which SDG&E began incurring commencing July 1, 2009, and any losses realized due to higher deductibles associated with the new policies. SDG&E made the filing under the CPUC’s rules allowing utilities to seek recovery of significant cost increases incurred between GRC filings that meet certain criteria, subject to a $5 million deductible per event.
 
In December 2011, the CPUC approved SDG&E’s request for an incremental revenue requirement of $63 million for the July 2010/June 2011 policy period. In May 2012, the CPUC approved SDG&E’s request for a $28 million revenue requirement for the first six months of the July 2011/June 2012 policy period.
 
In the CPUC’s December 2010 decision, discussed above, the CPUC directed SDG&E to include in its 2012 GRC application the amount of the incremental wildfire insurance premiums it would be seeking recovery for in rates subsequent to December 31, 2011. SDG&E’s 2012 GRC application does request $67 million of revenue requirement for cost recovery of wildfire insurance premiums in 2012. As a decision on SDG&E’s 2012 GRC application is pending with the CPUC, and based on the CPUC’s rulings for the recovery of the cost of the incremental wildfire insurance premiums incurred since July 2009, SDG&E’s 2012 revenue through September 30, 2012 reflects the expected recovery of the cost of the incremental wildfire insurance premiums incurred in the current year.
 
 
Excess Wildfire Claims Cost Recovery
 
SDG&E and SoCalGas filed an application, along with other related filings, with the CPUC in August 2009 proposing a new mechanism for the future recovery of all wildfire-related expenses for claims, litigation expenses and insurance premiums that are in excess of amounts authorized by the CPUC for recovery in distribution rates. This application was made jointly with Edison and PG&E. In July 2010, the CPUC approved SDG&E’s and SoCalGas’ requests for separate regulatory memorandum accounts to record the subject expenses while the application is pending before the CPUC. Several parties protested the original application and, in response, the four utilities jointly submitted an amended application in August 2010. In November 2011, Edison and PG&E requested to withdraw from the joint utility application due, in part, to the delays in the proceeding. In January 2012, the CPUC granted their requests to withdraw and held evidentiary hearings for SDG&E and SoCalGas, both of which are still moving forward with the application. Legal briefs were completed in March 2012.
 
In October 2012, the Administrative Law Judge’s (ALJ) draft decision (Proposed Decision or PD) and the Assigned Commissioner’s alternate draft decision (Alternate Decision or AD) in this proceeding were issued. The PD rejects SDG&E’s and SoCalGas’ request for a new balancing account and cost recovery mechanism and directs both SDG&E and SoCalGas to close the regulatory memorandum account that was previously authorized by the CPUC in July 2010 and remove any amount recorded to it. The PD does, however, state that should SDG&E continue to pursue recovery of such costs incurred, there are other established mechanisms that SDG&E can utilize to seek recovery. The AD approves SDG&E’s and SoCalGas’ request for a new balancing account and cost recovery mechanism but only for wildfire events that occur after July 2010, the effective date of the CPUC decision authorizing the regulatory memorandum account. The AD also directs SDG&E to remove any amounts recorded in the regulatory memorandum account associated with the 2007 wildfires. Under the terms of the AD, for wildfires for which the utility is found not to be at fault, SDG&E and SoCalGas may seek recovery in rates of 90 percent of costs incurred for payments made to settle claims associated with inverse condemnation which exceed the sum of $10 million per wildfire, their insurance coverage, and recoveries made from other third parties. For any costs incurred for wildfire events occurring prior to July 2010, the AD allows the utility to use the existing Z-factor application process to request recovery of such costs. A Z-factor application process allows utilities to seek recovery of significant cost increases incurred between GRC filings. We expect a final CPUC decision in the current proceeding by the end of 2012.
 
Following the issuance of the PD and the AD and consistent with CPUC rules and procedures, SDG&E requested an ex parte meeting with the Assigned Commissioner and staff. The request was granted, and the ex parte meeting was held on October 29, 2012. At the meeting, SDG&E provided information to the Assigned Commissioner addressing key issues from the AD that SDG&E believes contradict prior CPUC rulings and decisions. On November 5, 2012, SDG&E provided the CPUC with written comments and suggested changes to the AD. While there can be no assurance that the Assigned Commissioner will amend the AD, given the relevant regulatory and statutory standards and the issues discussed at the ex parte meeting, SDG&E has concluded that it remains probable that SDG&E will be permitted to recover from ratepayers substantially all reasonably incurred costs associated with the 2007 wildfires that exceed amounts recovered from its insurance coverage and other responsible third parties. SDG&E intends to continue to pursue recovery of such costs in this proceeding or, if necessary, in a future application, such as the Z-factor application noted in both the PD and the AD.
 
SDG&E will continue to assess the recovery of these excess wildfire costs from ratepayers. Should SDG&E conclude that the amount of recovery from ratepayers is no longer reasonably estimable or that recovery is no longer probable, including as a result of the CPUC’s failure to adopt a final decision in this proceeding that supports future recovery from ratepayers, SDG&E will record a charge against earnings at the time such conclusion is reached. If SDG&E had concluded that such recovery was no longer probable or reasonably estimable as of September 30, 2012, the resulting after-tax charge against earnings would have been approximately $175 million. In addition, in periods following any such conclusion, SDG&E’s earnings will be adversely impacted by increases in the estimated cost to settle pending wildfire claims.
 
We provide additional information about 2007 wildfire litigation costs and their recovery in Note 10.
 
 
East County Substation
 
In June 2012, the CPUC approved SDG&E’s application for authorization to proceed with the East County Substation project, estimated to cost $435 million. The Bureau of Land Management (BLM) issued its record of decision in August 2012. SDG&E expects to begin construction in the first half of 2013 and the substation to be placed in service in 2014. We provide additional information on the project in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
 
SOCALGAS MATTER
 
 
Aliso Canyon Natural Gas Storage Compressor Replacement
 
In September 2009, SoCalGas filed an application with the CPUC requesting approval to replace certain obsolete natural gas turbine compressors used in the operations of SoCalGas’ Aliso Canyon natural gas storage reservoir, with a new electric compressor station. In April 2012, the CPUC issued a draft environmental impact report (EIR) for the project concluding that no significant or unavoidable adverse environmental impacts have been identified from the construction or operation of the proposed project. We expect a final EIR and CPUC decision on the estimated $200 million project in 2013.
 
We discuss additional matters affecting our California Utilities in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 

 
 

NOTE 10. COMMITMENTS AND CONTINGENCIES
 

 
LEGAL PROCEEDINGS
 
We accrue losses for legal proceedings 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 coverages and could materially adversely affect our business, cash flows, results of operations, and financial condition. Unless otherwise indicated, we are unable to estimate reasonably possible losses in excess of any amounts accrued.
 
At September 30, 2012, Sempra Energy’s accrued liabilities for material legal proceedings, on a consolidated basis, were $427 million. At September 30, 2012, accrued liabilities for material legal proceedings for SDG&E and SoCalGas were $411 million and $5 million, respectively. At September 30, 2012, liabilities of $411 million at Sempra Energy and SDG&E were related to wildfire litigation discussed 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.” Cal Fire reported that the Rice fire burned approximately 9,500 acres and damaged 206 homes and two commercial properties, and the Witch and Guejito fires merged and eventually burned approximately 198,000 acres, resulting in two fatalities, approximately 40 firefighters injured and an estimated 1,141 homes destroyed.
 
A September 2008 staff report issued by the CPUC’s CPSD 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. In April 2010, proceedings initiated by the CPUC to determine if any of its rules were violated were settled with SDG&E’s payment of $14.75 million.
 
Numerous parties have 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. These include owners and insurers of properties that were destroyed or damaged in the fires and government entities seeking recovery of firefighting, emergency response, and environmental costs. They assert 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.
 
In October 2010, the Court of Appeal affirmed the trial court’s ruling that these claims must be pursued in individual lawsuits, rather than as class actions on behalf of all persons who incurred wildfire damages. In February 2011, the California Supreme Court denied a petition for review of the affirmance. No trial date is currently scheduled.
 
SDG&E filed cross-complaints against Cox seeking indemnification for any liability that SDG&E might incur in connection with the Guejito fire, two SDG&E contractors seeking indemnification in connection with the Witch fire, and one SDG&E contractor seeking indemnification in connection with the Rice fire. SDG&E has entered into settlement agreements with Cox and the three contractors for a total of approximately $824 million. Among other things, the settlement agreements provide that SDG&E will defend and indemnify Cox and the three contractors against all compensatory damage claims and related costs arising out of the wildfires.
 
SDG&E has settled all of the approximately 19,000 claims brought by homeowner insurers for damage to insured property relating to the three fires. Under the settlement agreements, SDG&E has paid or will pay 57.5 percent of the approximately $1.6 billion paid or reserved for payment by the insurers to their policyholders and received an assignment of the insurers’ claims against other parties potentially responsible for the fires.
 
The wildfire litigation also includes claims of non-insurer plaintiffs for damage to uninsured and underinsured structures, business interruption, evacuation expenses, agricultural damage, emotional harm, personal injuries and other losses. SDG&E has settled the claims of approximately 4,700 of these plaintiffs, including all of the government entities. Approximately 1,550 of the approximately 1,750 remaining individual and business plaintiffs have submitted settlement demands and damage estimates totaling approximately $1.4 billion. SDG&E does not expect significant additional plaintiffs to file lawsuits given the applicable statutes of limitation, but does expect to receive additional settlement demands and damage estimates from existing plaintiffs as settlement negotiations continue. SDG&E has established reserves for the wildfire litigation as we discuss below.
 
SDG&E’s settled claims and defense costs have exceeded its $1.1 billion of liability insurance coverage and the approximately $824 million received or receivable from third parties to date. It expects that its wildfire reserves and amounts paid to resolve wildfire claims will continue to increase as it obtains additional information.
 
As we discuss in Note 9, upon consideration of the relevant regulatory and statutory standards and the issues discussed at an ex parte meeting with the CPUC Assigned Commissioner, SDG&E has concluded that it is probable that it will be permitted to recover from its utility customers substantially all reasonably incurred costs of resolving wildfire claims in excess of its liability insurance coverage and the amounts recovered from other responsible parties. Accordingly, although such recovery will require future regulatory actions, at September 30, 2012, Sempra Energy and SDG&E have recorded assets of $326 million in Regulatory Assets Arising From Wildfire Litigation Costs on their Condensed Consolidated Balance Sheets, including $292 million related to CPUC operations, which represents the amount substantially equal to the aggregate amount it has paid or reserved for payment for the resolution of wildfire claims and related costs in excess of its liability insurance coverage and amounts received or receivable from third parties. SDG&E will increase the regulatory assets as additional amounts are paid or reserves are recorded.
 
SDG&E will continue to assess the recovery of these excess wildfire costs from ratepayers. Should SDG&E conclude that the amount of recovery from ratepayers is no longer reasonably estimable or that recovery 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 such recovery was no longer probable or reasonably estimable as of September 30, 2012, the resulting after-tax charge against earnings would have been approximately $175 million. In addition, in periods following any such conclusion, SDG&E’s earnings will be adversely impacted by increases in the estimated cost to settle pending wildfire claims. We provide additional information about excess wildfire claims cost recovery in Note 9.
 
SDG&E’s cash flow may be materially adversely affected due to the timing differences between the resolution of claims and the recoveries from utility customers, which may extend over a number of years. Also, recovery from customers will require future regulatory actions, and a failure to obtain substantial or full recovery, 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 position, cash flows and results of operations.
 
SDG&E will continue to gather information to evaluate and assess the remaining wildfire claims and the likelihood, amount and timing of related recoveries from utility customers and will make appropriate adjustments to wildfire reserves and the related regulatory assets as additional information becomes available.
 
Since 2010, as liabilities for wildfire litigation have become reasonably estimable in the form of settlement demands, damage estimates, and other damage information, SDG&E has recorded related reserves as a liability. The impact of this liability at September 30, 2012 is offset by the recognition of regulatory assets, as discussed above, for reserves in excess of the insurance coverage and recoveries from third parties. Due primarily to the recovery from two of SDG&E’s contractors, the impact of the reserves on SDG&E’s and Sempra Energy’s after-tax earnings was an increase of $1 million and a decrease of $5 million for the three months ended September 30, 2012 and 2011, respectively, and a decrease of $4 million and $7 million for the nine months ended September 30, 2012 and 2011, respectively. At September 30, 2012, wildfire litigation reserves were $411 million ($284 million in current and $127 million in long-term). Additionally, through September 30, 2012, SDG&E has expended $187 million (excluding amounts covered by insurance and amounts recovered from other responsible third parties) to pay costs associated with the settlement of wildfire claims.
 
 
Sunrise Powerlink Electric Transmission Line
 
SDG&E commenced construction on the Sunrise Powerlink in the fall of 2010. The Sunrise Powerlink is a new 117-mile, 500-kilovolt (kV) electric transmission line between the Imperial Valley and the San Diego region, along a route that generally runs south of the Anza-Borrego Desert State Park. Construction of the transmission line has been completed and the line was energized and placed in service in June 2012.
 
The Sunrise Powerlink project was originally approved by the CPUC in December 2008, including approval of the environmental impact review conducted jointly with the BLM. The CPUC subsequently denied or dismissed all requests for rehearing of its approval of the project. In February 2011, the California Supreme Court denied a petition filed jointly by the Utility Consumers’ Action Network (UCAN) and the Center for Biological Diversity/Sierra Club challenging the CPUC’s decision with regard to implementation of the California Environmental Quality Act (CEQA).
 
In January 2009, the BLM issued its decision approving the portions of the project, route and environmental review within its jurisdiction. The Interior Board of Land Appeals subsequently denied or dismissed all administrative appeals that were filed challenging the BLM’s approval of the project.
 
In February 2010, parties opposed to the project filed a lawsuit in Federal District Court in San Diego alleging that the BLM failed to properly address the environmental impacts of the approved Sunrise Powerlink route and the related potential development of renewable resources in east San Diego County and Imperial County. In July 2012, the U.S. Court of Appeals for the Ninth Circuit affirmed the District Court’s grant of the defendants’ motion for summary judgment.
 
In July 2010, the United States Forest Service (USFS) issued its decision approving the portions of the project, route and environmental review within its jurisdiction. The USFS subsequently denied all administrative appeals challenging its approval of the project.
 
The CPUC and BLM jointly approved the final Project Modification Report for Sunrise Powerlink in September 2010, accepting all of the proposed modifications to the approved route and finding that no additional environmental review was required. In March 2011, opponents of the Sunrise Powerlink filed a petition with the California Supreme Court challenging the CPUC’s acceptance of the Project Modification Report. The California Supreme Court denied the petition in April 2011.
 
In January 2011, project opponents filed a lawsuit in Federal District Court in San Diego alleging that the federal approvals for construction of the project on USFS land and BLM land violated the National Environmental Policy Act and other federal environmental laws. In June 2012, the U.S. Court of Appeals for the Ninth Circuit affirmed the District Court’s denial of plaintiffs’ motion for a preliminary injunction.
 
In February 2011, opponents of the Sunrise Powerlink filed a lawsuit in Sacramento County Superior Court against the State Water Resources Control Board and SDG&E alleging that the water quality certification issued by the Board under the Federal Clean Water Act violated CEQA. The Superior Court denied the plaintiffs’ petition in July 2012, and the plaintiffs have appealed.
 
September 2011 Power Outage
 
In September 2011, a power outage lasting approximately 12 hours affected millions of people from Mexico to southern Orange County, California. Within several days of the outage, several SDG&E customers filed a class action lawsuit in Federal District Court in San Diego against Arizona Public Service Company, Pinnacle West, and SDG&E alleging that the companies failed to prevent the outage. The lawsuit seeks recovery of unspecified amounts of damages, including punitive damages. In July 2012, the court granted SDG&E’s motion to dismiss the punitive damages request and dismissed Arizona Public Service Company and Pinnacle West from the lawsuit. In addition, more than 7,000 customers’ claims, primarily related to food spoilage, have been submitted directly to SDG&E. The Federal Energy Regulatory Commission (FERC) and North American Electric Reliability Corp. (NERC) conducted a joint inquiry to determine the cause of the power failure and issued a report in May 2012 regarding their findings. The report does not include any findings of failure on SDG&E’s part that led to the power failure.
 
Smart Meters Patent Infringement Lawsuit
 
In October 2011, SDG&E was sued by a Texas design and manufacturing company in Federal District Court 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.
 
 
SoCalGas
 
SoCalGas, along with Monsanto Co., Solutia, Inc., Pharmacia Corp., and Pfizer, Inc., are defendants in five 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 two of the five lawsuits for an amount that is not significant and has been recorded.
 
 
Sempra Natural Gas
 
Liberty Gas Storage, LLC (Liberty) received a demand for arbitration from Williams Midstream Natural Gas Liquids, Inc. (Williams) in February 2011 related to a sublease agreement. Williams alleges that Liberty was negligent in its attempt to convert certain salt caverns to natural gas storage and seeks damages of $56.7 million. Liberty filed a counterclaim alleging breach of contract in the inducement and seeks damages of more than $215 million.
 
 
Sempra Mexico
 
Sempra Mexico has been engaged in a long-running land dispute relating to property adjacent to its Energía Costa Azul liquefied natural gas (LNG) terminal near Ensenada, Mexico. The adjacent property is not required by environmental or other regulatory permits 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. In February 2011, based on a complaint by the claimant, the new Ensenada Mayor attempted 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. 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 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.
 
Additionally, several administrative challenges are pending in Mexico before the Mexican environmental protection agency (SEMARNAT) and/or 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 EIA are inadequate and challenge findings that the activities of the terminal are consistent with regional development guidelines. Also, there are two real property cases pending against Energía Costa Azul in which the plaintiffs seek to annul the recorded property titles for parcels on which the Energía Costa Azul LNG terminal is situated and to obtain possession of different parcels that allegedly sit in the same place. Sempra Mexico expects further proceedings on each of these matters.
 
In July 2012, a Mexicali state court issued a ruling declaring the purchase contract by which Termoeléctrica de Mexicali (TDM) acquired the property on which the facility is located to be invalid, on the grounds that the proceeding in which the seller acquired title was invalid. TDM has appealed the ruling, and it is not enforceable while the appeal is pending. In accordance with Mexican law, TDM remains in possession of the property, and its operations have not been affected.
 
 
Other Litigation
 
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 December 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 resolves all issues with regard to sales between the California Department of Water Resources (DWR) 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.
 
Sempra Energy and several subsidiaries, along with three oil and natural gas companies, the City of Beverly Hills, and the Beverly Hills Unified School District, were defendants in toxic tort lawsuits filed beginning in 2003 in Los Angeles County Superior Court by approximately 1,000 plaintiffs. These lawsuits claimed that various emissions resulted in cancer or fear of cancer. In November 2006, the court granted the defendants’ summary judgment motions based on lack of medical causation for the 12 initial plaintiffs scheduled to go to trial first. The court also granted summary judgment excluding punitive damages. In June 2010, a tentative settlement as to Sempra Energy and its subsidiaries was reached for an amount that was not significant and was recorded. The settlement was finalized in August 2012.
 
As described in Note 4, we hold a noncontrolling interest in RBS Sempra Commodities, a limited liability partnership in the process of being liquidated. In March 2012, RBS received a letter from the United Kingdom’s Revenue and Customs Department (HMRC) regarding a value-added-tax (VAT) matter related to RBS Sempra Energy Europe (RBS SEE), a former indirect subsidiary of RBS Sempra Commodities that was sold to JP Morgan. The letter states that HMRC is conducting a number of investigations into VAT tax refund claims made by various businesses related to the purchase and sale of carbon credit allowances. The letter also states that HMRC believes it has grounds to deny RBS the ability to reduce its VAT liability by VAT paid during 2009 because it 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 an assessment of £86 million for the VAT paid in connection with these transactions and identified several options for responding, including requesting a review by HMRC and appealing to an independent tribunal. HMRC indicated that the assessment was issued on a protective basis as discussion about the issues is continuing.
 
We are also defendants in ordinary routine litigation incidental to our businesses, including personal injury, product liability, property damage and other claims. California juries have demonstrated an increasing willingness to grant large awards, including punitive damages, in these types of cases.
 
 
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 million in coverage limits, the maximum amount available, including coverage for acts of terrorism. In addition, the Price-Anderson Act provides for up to $12.2 billion of secondary financial protection (SFP). If a nuclear liability loss occurring at any U.S. licensed/commercial reactor exceeds the $375 million insurance limit, all nuclear reactor owners could be required to contribute to the SFP. SDG&E’s contribution would be up to $47 million. This amount is subject to an annual maximum of $7 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 billion of nuclear property, decontamination, and debris removal insurance. In addition, the SONGS owners have up to $490 million insurance coverage for outage expenses and replacement power costs due to accidental property damage. This coverage is limited to $3.5 million per week for the first 52 weeks, then $2.8 million per week for up to 110 additional weeks. There is a 12-week waiting period deductible. These insurance coverages are provided through a mutual insurance company. Insured members are subject to retrospective premium assessments. SDG&E could be assessed up to $9.7 million.
 
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.
 
We provide additional information about SONGS in Note 9.
 
 
CONTRACTUAL COMMITMENTS
 
We discuss below significant changes in the first nine months of 2012 to contractual commitments discussed in Note 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
 
Natural Gas Contracts
 
SoCalGas’ natural gas purchase and pipeline capacity commitments have increased by $232 million since December 31, 2011. The increase, primarily due to new natural gas purchase and pipeline capacity contracts of $591 million, is offset by a reduction of $359 million from fulfillment of commitments in the first nine months of 2012. Net future payments are expected to decrease by $231 million in 2012 and increase by $307 million in 2013, $67 million in 2014, $34 million in 2015, $4 million in 2016 and $51 million thereafter compared to December 31, 2011.
 
Sempra Mexico’s natural gas purchase commitments have decreased by $128 million since December 31, 2011, primarily due to changes in forward prices and fulfillment of commitments in the first nine months of 2012. Net future payments are therefore expected to decrease by $81 million in 2012, $22 million in 2013 and $25 million in 2014 compared to December 31, 2011.
 
Sempra Natural Gas’ natural gas purchase and storage capacity commitments have increased by $73 million since December 31, 2011, primarily due to new storage capacity contracts in the first nine months of 2012. Net future payments are expected to decrease by $7 million in 2012, and increase by $14 million in 2013, $10 million in 2014, $11 million in 2015, $11 million in 2016 and $34 million thereafter compared to December 31, 2011.
 
 
LNG Purchase Agreements
 
At September 30, 2012, Sempra Natural Gas has various purchase agreements with major international companies for the supply of LNG to the Energía Costa Azul and Cameron receipt terminals. We discuss these agreements further in Note 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report. Sempra Natural Gas’ commitments under all LNG purchase agreements, reflecting changes in forward prices since December 31, 2011 and actual transactions for the first nine months of 2012, are expected to decrease by $384 million in 2012, $9 million in 2013, $18 million in 2014, $27 million in 2015, $33 million in 2016 and $523 million thereafter compared to December 31, 2011.
 
The LNG commitment amounts above are based on Sempra Natural Gas’ commitment to accept the maximum possible delivery of cargoes under the agreements. Actual LNG purchases for the nine months ended September 30, 2012 have been significantly lower than the maximum amounts possible.
 
 
Purchased-Power Contracts
 
SDG&E’s commitments under purchased-power contract commitments have increased by $1.6 billion since December 31, 2011. The increase is primarily due to new contracts associated with renewable energy development projects and changes in expected prices. Net future payments are therefore expected to decrease by $47 million in 2012, and increase by $18 million in 2013, $61 million in 2014, $66 million in 2015, $67 million in 2016 and $1.4 billion thereafter compared to December 31, 2011.
 
Sempra South American Utilities’ purchased-power contracts have increased by $96 million since December 31, 2011, primarily due to foreign currency translation (as the contracts are denominated in the local currency), offset by changes in expected prices and fulfillment of commitments in the first nine months of 2012. Net future payments for the purchased-power contracts at Luz del Sur are expected to decrease by $291 million in 2012, increase by $15 million in 2013 and $2 million in 2014, decrease by $1 million in 2015, and to increase by $8 million in 2016 and $105 million thereafter.  Net future payments for the purchased-power contracts at Chilquinta Energía are expected to decrease by $205 million in 2012, and increase by $28 million in 2013, $32 million in 2014, $34 million in 2015, $34 million in 2016 and $335 million thereafter. These amounts are based on estimated future purchases at current contracted rates, as the contracts require no minimum purchases.
 
 
Operating Leases
 
Sempra Renewables entered into a land lease for the Copper Mountain Solar 2 project, which lease expires in 2054. Future payments on the lease are $2 million in 2013, $2 million in 2014, $2 million in 2015, $2 million in 2016 and $57 million thereafter.
 
 
Construction and Development Projects
 
In the first nine months of 2012, significant increases to contractual commitments at SDG&E were $34 million for electric transmission and distribution systems, $11 million for infrastructure improvements for natural gas transmission and distribution operations and $196 million for construction costs associated with the ECO Substation. The future payments for these contractual commitments are expected to be $62 million in 2012, $159 million in 2013 and $20 million in 2014.
 
In connection with the completion of the Sunrise Powerlink project, the CPUC required that SDG&E establish a fire mitigation fund to minimize the risk of fire as well as reduce the potential wildfire impact on residences and structures near the Sunrise Powerlink.  The future payments for these contractual commitments are expected to be approximately $3 million per year, subject to escalation of 2 percent per year, for 58 years. At September 30, 2012, the present value of these future payments of $116 million has been recorded as a regulatory asset as the amounts represent a cost that will be recovered from customers in the future, and the related liability was $113 million.
 
In the first nine months of 2012, significant increases to contractual commitments at SoCalGas were $60 million for construction and infrastructure improvements for natural gas transmission and distribution operations. The payments for these contractual commitments are all expected to be in 2012.
 
 
Other
 
In July 2012, SDG&E received $85 million from Citizens Sunrise Transmission, LLC (Citizens), a subsidiary of Citizens Energy Corporation. For this payment, under the terms of the agreement with Citizens, SDG&E will provide Citizens with access to a segment of the Sunrise Powerlink transmission line known as the Border-East transmission line equal to 50 percent of the transfer capacity of this portion of the line for a period of 30 years. After the 30-year contract term, the transfer capability will revert to SDG&E. SDG&E will amortize deferred revenues from the use of the transfer capability over the 30-year term, and depreciation for 50 percent of the Border-East transmission line segment will be accelerated from an estimated 58-year life to 30 years.
 

 

NOTE 11. 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 operates electric transmission and distribution utilities in Chile and Peru, and owns interests in utilities in Argentina. We are currently pursuing the sale of our interests in the Argentine utilities, which we discuss further in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report.

4.  
Sempra Mexico develops, owns and operates, or holds interests in, natural gas transmission pipelines and propane systems, a natural gas distribution utility, electric generation facilities, including wind, and a terminal for the import of LNG and sale of natural gas in Mexico.

5.  
Sempra Renewables develops, owns and operates, or holds interests in, wind and solar energy projects in Arizona, California, Colorado, Hawaii, Indiana, Kansas, Nevada and Pennsylvania to serve wholesale electricity markets in the United States.
 
6.  
Sempra Natural Gas develops, owns and operates, or holds interests in, a natural gas-fired electric generation plant, 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, all within the United States.

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.
 
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 and the former commodities-marketing businesses.
 

SEGMENT INFORMATION
                               
(Dollars in millions)
                               
   
Three months ended September 30,
Nine months ended September 30,
   
2012 
2011 
2012 
2011 
REVENUES
                               
  SDG&E
$
 1,092 
44 
%
$
 868 
 34 
%
$
 2,706 
39 
%
$
 2,405 
32 
%
  SoCalGas
 
 728 
29 
   
 844 
 33 
   
 2,328 
33 
   
 2,776 
37 
 
  Sempra South American Utilities
 
 356 
14 
   
 345 
 13 
   
 1,061 
15 
   
 706 
10 
 
  Sempra Mexico
 
 181 
   
 183 
 7 
   
 434 
   
 561 
 
  Sempra Renewables
 
 27 
   
 7 
 ― 
   
 49 
   
 17 
 ― 
 
  Sempra Natural Gas
 
 294 
12 
   
 455 
 18 
   
 761 
11 
   
 1,340 
18 
 
  Adjustments and eliminations
 
 ― 
 ― 
   
 (1)
 ― 
   
 (1)
 ― 
   
 (1)
 ― 
 
  Intersegment revenues(1)
 
 (171)
(7)
   
 (125)
 (5)
   
 (359)
(5)
   
 (372)
(5)
 
      Total
$
 2,507 
 100 
%
$
 2,576 
 100 
%
$
 6,979 
 100 
%
$
 7,432 
 100 
%
INTEREST EXPENSE
                               
  SDG&E
$
 49 
   
$
 37 
   
$
 124 
   
$
 104 
   
  SoCalGas
 
 17 
     
 17 
     
 51 
     
 52 
   
  Sempra South American Utilities
 
 6 
     
 9 
     
 22 
     
 23 
   
  Sempra Mexico
 
 4 
     
 4 
     
 10 
     
 15 
   
  Sempra Renewables
 
 6 
     
 4 
     
 13 
     
 9 
   
  Sempra Natural Gas
 
 26 
     
 22 
     
 72 
     
 62 
   
  All other
 
 62 
     
 58 
     
 185 
     
 174 
   
  Intercompany eliminations
 
 (44)
     
 (33)
     
 (125)
     
 (95)
   
      Total
$
 126 
   
$
 118 
   
$
 352 
   
$
 344 
   
INTEREST INCOME
                               
  SoCalGas
$
 ― 
   
$
 1 
   
$
 ― 
   
$
 1 
   
  Sempra South American Utilities
 
 3 
     
 6 
     
 11 
     
 18 
   
  Sempra Mexico
 
 4 
     
 3 
     
 10 
     
 7 
   
  Sempra Renewables
 
 2 
     
 ― 
     
 3 
     
 ― 
   
  Sempra Natural Gas
 
 15 
     
 8 
     
 41 
     
 25 
   
  All other
 
 ― 
     
 (2)
     
 ― 
     
 1 
   
  Intercompany eliminations
 
 (19)
     
 (10)
     
 (51)
     
 (31)
   
      Total
$
 5 
   
$
 6 
   
$
 14 
   
$
 21 
   
DEPRECIATION AND AMORTIZATION
           
  SDG&E
$
 128 
46 
%
$
 108 
 43 
%
$
 359 
45 
%
$
 316 
 43 
%
  SoCalGas
 
 91 
33 
   
 83 
 33 
   
 268 
33 
   
 246 
 34 
 
  Sempra South American Utilities
 
 15 
   
 14 
 6 
   
 42 
   
 27 
 4 
 
  Sempra Mexico
 
 15 
   
 15 
 6 
   
 46 
   
 46 
 6 
 
  Sempra Renewables
 
 4 
   
 1 
 ― 
   
 10 
   
 4 
 1 
 
  Sempra Natural Gas
 
 24 
   
 26 
 10 
   
 69 
   
 79 
 11 
 
  All other
 
 3 
   
 4 
 2 
   
 9 
   
 11 
 1 
 
      Total
$
 280 
 100 
%
$
 251 
 100 
%
$
 803 
 100 
%
$
 729 
 100 
%
INCOME TAX EXPENSE (BENEFIT)
           
  SDG&E
$
 38 
   
$
 63 
   
$
 151 
   
$
 154 
   
  SoCalGas
 
 37 
     
 41 
     
 105 
     
 106 
   
  Sempra South American Utilities
 
 27 
     
 18 
     
 57 
     
 30 
   
  Sempra Mexico
 
 21 
     
 (7)
     
 44 
     
 24 
   
  Sempra Renewables
 
 (12)
     
 (9)
     
 (47)
     
 (22)
   
  Sempra Natural Gas
 
 (45)
     
 27 
     
 (171)
     
 97 
   
  All other
 
 (17)
     
 (58)
     
 (91)
     
 (100)
   
      Total
$
 49 
   
$
 75 
   
$
 48 
   
$
 289 
   
                                 
                                 
                                 

SEGMENT INFORMATION (Continued)
           
(Dollars in millions)
                               
 
Three months ended September 30,
Nine months ended September 30,
 
2012 
2011 
2012 
2011 
EQUITY EARNINGS (LOSSES)
                               
 Earnings (losses) recorded before tax:
           
   Sempra Renewables
$
 (6)
   
$
 (6)
   
$
 (7)
   
$
 (6)
   
   Sempra Natural Gas
 
 (87)
     
 10 
     
 (366)
     
 29 
   
   All other
 
 (1)
     
 (16)
     
 (2)
     
 (27)
   
       Total
$
 (94)
   
$
 (12)
   
$
 (375)
   
$
 (4)
   
 Earnings recorded net of tax:
           
   Sempra South American Utilities
$
 ― 
   
$
 ― 
   
$
 ― 
   
$
 23 
   
   Sempra Mexico
 
 10 
     
 6 
     
 29 
     
 22 
   
       Total
$
 10 
   
$
 6 
   
$
 29 
   
$
 45 
   
EARNINGS (LOSSES)
                               
   SDG&E(2)
$
 174 
 65 
%
$
 113 
39 
%
$
 374 
 66 
%
$
 273 
 26 
%
   SoCalGas(2)
 
 71 
 26 
   
 81 
28 
   
 190 
 34 
   
 208 
 20 
 
   Sempra South American Utilities
 
 40 
 15 
   
 50 
17 
   
 118 
 21 
   
 386 
 37 
 
   Sempra Mexico
 
 54 
 20 
   
 47 
16 
   
 134 
 24 
   
 121 
 12 
 
   Sempra Renewables
 
 13 
 5 
   
 1 
 1 
   
 47 
 8 
   
 9 
 1 
 
   Sempra Natural Gas
 
 (68)
 (25)
   
 41 
14 
   
 (260)
 (46)
   
 151 
 14 
 
   All other
 
 (16)
 (6)
   
 (44)
(15)
   
 (37)
 (7)
   
 (102)
 (10)
 
       Total
$
 268 
 100 
%
$
 289 
 100 
%
$
 566 
 100 
%
$
 1,046 
 100 
%
                   
Nine months ended September 30,
                     
2012 
   
2011 
 
EXPENDITURES FOR PROPERTY PLANT & EQUIPMENT
   
   SDG&E
               
$
 998 
 44 
%
$
 1,162 
 57 
%
   SoCalGas
                 
 462 
 21 
   
 499 
 25 
 
   Sempra South American Utilities
                 
 117 
 5 
   
 63 
 3 
 
   Sempra Mexico
                 
 13 
 1 
   
 11 
 1 
 
   Sempra Renewables
                 
 564 
 25 
   
 124 
 6 
 
   Sempra Natural Gas
                 
 84 
 4 
   
 171 
 8 
 
   All other
                 
 3 
 ― 
   
 1 
 ― 
 
       Total
               
$
 2,241 
 100 
%
$
 2,031 
 100 
%
     
September 30, 2012
December 31, 2011
ASSETS
   
   SDG&E
               
$
 14,589 
 41 
%
$
 13,555 
 41 
%
   SoCalGas
                 
 8,784 
 25 
   
 8,475 
 25 
 
   Sempra South American Utilities
                 
 3,241 
 9 
   
 2,981 
 9 
 
   Sempra Mexico
                 
 3,042 
 9 
   
 2,914 
 9 
 
   Sempra Renewables
                 
 2,412 
 7 
   
 1,210 
 4 
 
   Sempra Natural Gas
                 
 5,910 
 17 
   
 5,738 
 17 
 
   All other
                 
 520 
 1 
   
 538 
 2 
 
   Intersegment receivables(3)
                 
 (3,108)
 (9)
   
 (2,162)
 (7)
 
       Total
               
$
 35,390 
 100 
%
$
 33,249 
 100 
%
INVESTMENTS IN EQUITY METHOD INVESTEES
   
   Sempra Mexico
               
$
 333 
   
$
 302 
   
   Sempra Renewables
                 
 666 
     
 390 
   
   Sempra Natural Gas
                 
 369 
     
 800 
   
   All other
                 
 135 
     
 137 
   
       Total
               
$
 1,503 
   
$
 1,629 
   
(1)
Revenues for reportable segments include intersegment revenues of:
 
$3 million, $17 million, $78 million and $73 million for the three months ended September 30, 2012; $6 million, $48 million, $161 million and $144 million for the nine months ended September 30, 2012; $2 million, $13 million, $48 million and $62 million for the three months ended September 30, 2011; and $5 million, $38 million, $157 million and $172 million for the nine months ended September 30, 2011 for SDG&E, SoCalGas, Sempra Mexico and Sempra Natural Gas, respectively.
(2)
After preferred dividends.
                               
(3)
Assets for reportable segments include intersegment receivables of:
 
$17 million, $280 million, $54 million, $643 million, $521 million, and $1.6 billion at September 30, 2012; and $67 million, $40 million, $52 million, $543 million, $263 million, and $1.2 billion at December 31, 2011 for SDG&E, SoCalGas, Sempra South American Utilities, Sempra Mexico, Sempra Renewables and Sempra Natural Gas, respectively.
 
 
 
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
You should read the following discussion in conjunction with the financial statements contained in this Form 10-Q; “Management’s Discussion and Analysis of Financial Condition and Results of Operations” contained in Exhibit 99.4 to Sempra Energy’s Current Report on Form 8-K dated May 11, 2012 (Form 8-K); the Notes to Consolidated Financial Statements contained in Exhibit 99.5 to the Form 8-K; and “Risk Factors” contained in our 2011 Annual Report on Form 10-K (Form 10-K). We refer to the Form 8-K throughout this Form 10-Q as the Updated Annual Report.
 

 

OVERVIEW
 

 
2012 Business Segment Realignment
 
Effective January 1, 2012, management realigned some of the company’s major subsidiaries to better fit its strategic direction and to enhance the management and integration of our assets. This realignment resulted in a change in reportable segments in 2012. In accordance with accounting principles generally accepted in the United States (GAAP), we have restated historical information in this Form 10-Q to reflect the effect of this change. All discussions of our operating units and reportable segments in this report reflect the new segments and operating structure.
 
Sempra Energy is a Fortune 500 energy-services holding company whose operating units develop energy infrastructure, operate utilities and provide related services to their customers. Our operations are divided principally between 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 reportable segments – Sempra Renewables and Sempra Natural Gas.
 
This report includes information for the following separate registrants:
 
§  
Sempra Energy and its consolidated entities
 
§  
SDG&E
 
§  
SoCalGas
 
References in this report to “we,” “our” and “Sempra Energy Consolidated” are to Sempra Energy and its consolidated entities, collectively, unless otherwise indicated by the context. All references in this report to “Sempra International” and “Sempra U.S. Gas & Power,” and to their respective principal segments, are not intended to refer to any legal entity with the same or similar name.
 
Below are summary descriptions of our operating units and their reportable segments.
 
 
SEMPRA ENERGY OPERATING UNITS AND REPORTABLE SEGMENTS
 

CALIFORNIA UTILITIES
   
 
MARKET
SERVICE TERRITORY
SAN DIEGO GAS & ELECTRIC COMPANY (SDG&E)
A regulated public utility; infrastructure supports electric generation, transmission and distribution, and natural gas distribution
§ Provides electricity to 3.4 million consumers (1.4 million meters)
 
§ Provides natural gas to 3.1 million consumers (855,000 meters)
 
 
Serves the county of San Diego, California and an adjacent portion of southern Orange County covering 4,100 square miles
SOUTHERN CALIFORNIA GAS COMPANY (SOCALGAS)
A regulated public utility; infrastructure supports natural gas distribution, transmission and storage
§ Residential, commercial, industrial, utility electric generation and wholesale customers
 
§ Covers a population of 21 million (5.8 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 and Sempra U.S. Gas & Power operating units described below.
 
We provide descriptions of our reorganized businesses, Sempra International and Sempra U.S. Gas & Power, below.
 
SEMPRA INTERNATIONAL
   
 
MARKET
GEOGRAPHIC REGION
SEMPRA SOUTH AMERICAN UTILITIES
Infrastructure supports electric transmission and distribution
§ Provides electricity to more than 600,000 customers in Chile and more than 900,000 customers in Peru
 
 
 
 
§ Serves the cities of Valparaiso and Viña del Mar in central Chile
 
§ Serves the southern zone of metropolitan Lima, Peru
 
 
SEMPRA MEXICO
Develops, owns and operates, or holds interests in:
§ natural gas transmission pipelines and propane systems
 
§ a natural gas distribution utility
 
§ electric generation facilities, including wind
 
§ a terminal in Mexico for the importation of liquefied natural gas (LNG) and purchase and sale of natural gas
 
 
§ Natural gas
 
§ Wholesale electricity
 
§ Liquefied natural gas
 
 
 
§ Mexico
 
 
 

 
 
Sempra International
 
Sempra South American Utilities
 
Sempra South American Utilities operates electric transmission and distribution utilities in Chile and Peru, and owns interests in utilities in Argentina.
 
On April 6, 2011, Sempra South American Utilities completed the acquisition of AEI’s interests in Chilquinta Energía S.A. (Chilquinta Energía) in Chile and Luz del Sur S.A.A. (Luz del Sur) in Peru. Upon completion of the transaction, Sempra South American Utilities owned 100 percent of Chilquinta Energía and approximately 76 percent of Luz del Sur, and the companies are now consolidated. Pursuant to a tender offer that was completed in September 2011, Sempra South American Utilities now owns 79.82 percent of Luz del Sur, as we discuss in Note 3 of the Notes to Consolidated Financial Statements in the Updated Annual Report. The remaining shares of Luz del Sur are held by institutional investors and the general public.
 
We provide additional information about the acquisition and Sempra South American Utilities’ investments in Chilquinta Energía and Luz del Sur in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.
 
Sempra South American Utilities also is currently pursuing the sale of its interests in the Argentine utilities, which we discuss further in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
Sempra Mexico
 
Gas Business
 
Pipelines. Sempra Mexico owns and operates natural gas transmission pipelines and propane systems in Mexico. These facilities are contracted under long-term, U.S. dollar-based agreements with PEMEX (the Mexican state-owned oil company), the Federal Electricity Commission (Comisión Federal de Electricidad, or CFE), Shell México Gas Natural (Shell), Gazprom Marketing & Trading Mexico (Gazprom) and other similar counterparties. Sempra Mexico also owns a 50-percent interest in Gasoductos de Chihuahua, a joint venture with PEMEX which operates two natural gas pipelines and a propane system in northern Mexico.
 
LNG. Sempra Mexico’s Energía Costa Azul LNG terminal in Baja California, Mexico is capable of processing 1 billion cubic feet (Bcf) of natural gas per day. The Energía Costa Azul facility generates revenue under a capacity services agreement with Shell, expiring in 2028, that originally permitted Shell to use one-half of the terminal’s capacity. In April 2009, Shell assigned a portion of its terminal capacity at Energía Costa Azul to Gazprom, transferring all further rights and obligations with respect to the assigned capacity, and a separate capacity services agreement between Energía Costa Azul and Gazprom was put into place.
 
A nitrogen-injection facility at Energía Costa Azul allows the terminal to process LNG cargoes from a wider variety of sources and provides additional revenue from payments for capacity reservation and usage fees for nitrogen injection services for Shell and Gazprom.
 
In connection with Sempra Natural Gas’ LNG purchase agreement with Tangguh PSC Contractors (Tangguh PSC), which we discuss below, Sempra Mexico purchases from Sempra Natural Gas the LNG delivered to Energía Costa Azul by Tangguh PSC. Sempra Mexico uses the natural gas produced from this LNG to supply a contract through 2022 for the sale of an average of approximately 150 million cubic feet per day of natural gas to Mexico’s national electric company, the CFE, at prices that are based on the Southern California border index. If LNG volumes received from Tangguh PSC are not sufficient to satisfy the commitment to the CFE, Sempra Mexico may purchase natural gas from Sempra Natural Gas’ natural gas marketing operations. Under an agreement which expires in the third quarter of 2014 among Sempra Natural Gas, Sempra Mexico, J.P. Morgan Mexico and J.P. Morgan Ventures, Sempra Natural Gas and Sempra Mexico sell to J.P. Morgan Ventures and J.P. Morgan Mexico any volumes received from Tangguh PSC that are not sold to the CFE. The agreement was previously with RBS Sempra Commodities LLP (RBS Sempra Commodities). In connection with the 2010 sale of businesses within RBS Sempra Commodities, substantially all contracts with RBS Sempra Commodities were assigned to J.P. Morgan Ventures by May 1, 2011, as we discuss under “Transactions with RBS Sempra Commodities” in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.
 
Natural Gas Distribution. Sempra Mexico’s natural gas distribution utility, Ecogas Mexico, S de RL de CV (Ecogas), operates in three separate areas in Mexico, and had approximately 90,000 customers and sales volume of 60 million cubic feet per day in 2011.
 
Power Business
 
Natural Gas-Fired Generation. Sempra Mexico’s Termoeléctrica de Mexicali, a 625-megawatt (MW) natural gas-fired power plant, is located in Mexicali, Baja California, Mexico. Under an agreement with Sempra Natural Gas, Sempra Mexico records revenue for the sale of power generated by Termoeléctrica de Mexicali to Sempra Natural Gas, and records cost of sales for purchases from Sempra Natural Gas of natural gas to fuel the facility. J.P. Morgan Ventures Energy Corporation (J.P. Morgan Ventures) facilitates the natural gas transactions between the segments.
 
Wind Power Generation. Sempra Mexico is developing a wind power generation project, Energía Sierra Juárez, in Baja California, Mexico. The project will be developed in phases. In April 2011, SDG&E entered into a 20-year contract for up to 156 MW of renewable power supplied from the first phase of the project, which we expect to be fully operational in 2014.


SEMPRA U.S. GAS & POWER
   
 
MARKET
GEOGRAPHIC REGION
SEMPRA RENEWABLES
Develops, owns, operates, or holds interests in renewable energy generation projects
§ Wholesale electricity
 
 
§ U.S.A.
 
 
 
SEMPRA NATURAL GAS
Develops, owns and operates, or holds interests in:
§ a natural gas-fired electric generation plant
 
§ natural gas pipelines and storage facilities
 
§ natural gas distribution utilities
 
§ a terminal in the U.S. for the importation and export of LNG and sale of natural gas
 
§ marketing operations
 
 
§ Wholesale electricity
 
§ Natural gas
 
§ Liquefied natural gas
 
 
 
§ U.S.A.
 
 
 
 

 
 
Sempra U.S. Gas & Power
 
Sempra Renewables
 
The following table provides information about the Sempra Renewables facilities that were operational as of September 30, 2012. The generating capacity of these facilities is fully contracted under long-term contracts, as we discuss below.
 
SEMPRA RENEWABLES OPERATING FACILITIES
Capacity in Megawatts (MW) at September 30, 2012
Name
Installed Generating Capacity
 
        First
In Service
 
Location
Cedar Creek 2 Wind Farm (50% owned)
125
(1)
2011
 
New Raymer, Colorado
Fowler Ridge 2 Wind Farm (50% owned)
100
(1)
2009
 
Benton County, Indiana
Copper Mountain Solar 1
58
(2)
2010
 
Boulder City, Nevada
Copper Mountain Solar 2
64
(3)
2012
 
Boulder City, Nevada
Mesquite Solar 1
42/84
(4)
2011/2012
 
Arlington, Arizona
 
Total MW in operation
473
       
(1)
Sempra Renewables’ share.
(2)
Includes the 10-MW facility previously referred to as El Dorado Solar, which was first placed in service in 2008.
(3)
Represents only the portion of the project that was completed as of September 30, 2012. The entire 92-MW first phase of Copper Mountain Solar 2 is expected to be placed in service by the end of 2012.
(4)
Represents only the portion of the project that was completed in the year indicated. The entire 150-MW project is expected to be placed in service by December 2012.

 
We discuss these facilities in more detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our Updated Annual Report.
 
Sempra Natural Gas
 
Generation. Sempra Natural Gas sells electricity under short-term and long-term contracts and into the spot market and other competitive markets. While it may also purchase electricity in the open market to satisfy its contractual obligations, Sempra Natural Gas generally purchases natural gas to fuel its Mesquite Power natural gas-fired power plant, and, as we discuss above, Sempra Mexico’s Termoeléctrica de Mexicali plant. The Mesquite Power plant is a 1,250-MW facility located in Arlington, Arizona.
 
Sempra Natural Gas’ El Dorado natural gas-fired generation plant (excluding the solar facility) was sold to SDG&E on October 1, 2011 and was renamed Desert Star. This sale, pursuant to an option to acquire the plant that was exercised by SDG&E in 2007, coincided with the end of a contract with the California Department of Water Resources (DWR). During the first three quarters of 2011, the Mesquite Power plant and the El Dorado generation plant, along with Sempra Mexico’s Termoeléctrica de Mexicali power plant, sold the majority of their output under this long-term purchased-power contract with the DWR, which provided for 1,200 MW to be supplied during all hours and an additional 400 MW during on-peak hours and ended on September 30, 2011.
 
Sempra Natural Gas also has various power sale transactions intended to hedge its generation capacity. Power has been sold to J.P. Morgan Ventures, generally through 2012. These contracts were initially with RBS Sempra Commodities. In connection with the 2010 sale of businesses within RBS Sempra Commodities, substantially all of these transactions with RBS Sempra Commodities were assigned to J.P. Morgan Ventures by May 1, 2011. In addition, Sempra Natural Gas has power sale transactions for various quantities of power for delivery in 2013 and 2014. Finally, Sempra Natural Gas has sold certain quantities of expected future generation output under long-term contracts. The remaining output of our natural gas-fired generation facilities, including that of Sempra Mexico’s Termoeléctrica de Mexicali power plant, is available to be sold into energy markets on a day-to-day basis.
 
Transportation and Storage. Sempra Natural Gas owns and operates, or holds interests in, natural gas underground storage and related pipeline facilities in Alabama, Louisiana and Mississippi. Sempra Natural Gas provides natural gas marketing, trading and risk management activities through the utilization and optimization of contracted natural gas supply, transportation and storage capacity, as well as optimizing its assets in the short-term services market.
 
Sempra Natural Gas, Kinder Morgan Energy Partners, L.P. (KMP) and Phillips 66 jointly own, through Rockies Express Pipeline LLC (Rockies Express), the Rockies Express Pipeline (REX) that links producing areas in the Rocky Mountain region to the upper Midwest and the eastern United States. Our ownership interest in the pipeline is 25 percent. Sempra Rockies Marketing has an agreement through November 2019 with Rockies Express for 200 million cubic feet per day of capacity on REX, which has a total capacity of 1.8 Bcf per day. Sempra Rockies Marketing released a portion of its capacity to RBS Sempra Commodities, which capacity was assigned to J.P. Morgan Ventures effective January 1, 2011 in connection with the sale of businesses within RBS Sempra Commodities. This contract expires December 31, 2013.
 
In the second and third quarters of 2012, we recorded noncash impairment charges of $179 million and $60 million after-tax, respectively, to write down our investment in the partnership that operates REX. We discuss our investment in Rockies Express and the impairments in Notes 4 and 8 of the Notes to Condensed Consolidated Financial Statements herein.
 
Distribution.  Sempra Natural Gas owns and operates Mobile Gas Service Corporation (Mobile Gas) and Willmut Gas Company (Willmut Gas), regulated natural gas distribution utilities in southwest Alabama and in Mississippi, respectively. Sempra Natural Gas acquired Willmut Gas in May 2012, as we discuss in Note 3 of the Notes to Condensed Consolidated Financial Statements herein.
 
LNG. Sempra Natural Gas’ Cameron LNG terminal in Hackberry, Louisiana is capable of processing 1.5 Bcf of natural gas per day. Cameron LNG generates revenue under a capacity services agreement for approximately 600 million cubic feet of natural gas per day through 2029. The agreement allows customers to pay Sempra Natural Gas capacity reservation and usage fees to use its facilities to receive, store and regasify the customer’s LNG. Sempra Natural Gas also may enter into short-term and/or long-term supply agreements to purchase LNG to be received, stored and regasified at its terminals for sale to other parties. Sempra Natural Gas is currently taking steps towards the development of a liquefaction and exportation facility at the Cameron LNG terminal. We discuss these activities below in “Factors Influencing Future Performance.”
 
Sempra Natural Gas has an LNG purchase agreement with Tangguh PSC for the supply of the equivalent of 500 million cubic feet of natural gas per day from Tangguh PSC’s Indonesian liquefaction facility with delivery to Sempra Mexico’s Energía Costa Azul receipt terminal at a price based on the Southern California border index for natural gas. As discussed above, Sempra Natural Gas has an agreement to sell to J.P. Morgan Ventures any volumes purchased from Tangguh PSC that are not sold to the CFE or J.P. Morgan Mexico. This agreement was previously with RBS Sempra Commodities. In connection with the 2010 sale of businesses within RBS Sempra Commodities, substantially all contracts with RBS Sempra Commodities were assigned to J.P. Morgan Ventures by May 1, 2011. Sempra Natural Gas may also record revenues from non-delivery of cargoes related to this contract.
 
Sempra Natural Gas also owns property in Port Arthur, Texas, that it is evaluating for potential development.
 
 
RBS Sempra Commodities LLP
 
Prior to 2011, our Sempra Commodities segment contained our investment in RBS Sempra Commodities LLP (RBS Sempra Commodities), which held commodities-marketing businesses previously owned by us. Our investment in the partnership is reported on the equity method. We and The Royal Bank of Scotland plc (RBS), our partner in the joint venture, sold substantially all of the partnership’s businesses and assets in four separate transactions completed in July, November and December of 2010 and February of 2011. We discuss these transactions and other matters concerning the partnership in Notes 4 and 10 of the Notes to Condensed Consolidated Financial Statements herein and in Note 4 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
The activity in the partnership no longer meets the quantitative thresholds that require Sempra Commodities to be reported as a reportable segment under applicable accounting rules, and we do not consider the remaining wind-down activities of the partnership to be of continuing significance. As a result, since January 1, 2011, we have reported the former Sempra Commodities segment in Parent and Other.
 

 

RESULTS OF OPERATIONS
 

We discuss the following in Results of Operations:
 
§  
Overall results of our operations and factors affecting those results
 
§  
Our segment results
 
§  
Significant changes in revenues, costs and earnings between periods
 
Our earnings decreased by $21 million (7%) to $268 million in the three months ended September 30, 2012, and by $480 million (46%) to $566 million in the nine months ended September 30, 2012.
 
The decrease in our earnings for the three-month period was primarily due to:
 
§  
lower earnings at Sempra Natural Gas primarily due to the end of the DWR contract in September 2011; and
 
§  
a $60 million noncash impairment charge in 2012 to further write down our investment in Rockies Express; offset by
 
§  
improved results at SDG&E, Sempra Renewables, Sempra Mexico and Parent and Other.
 
The decrease in our earnings for the nine-month period was primarily due to:
 
§  
a $277 million gain resulting from the remeasurement of our equity method investments at our South American Utilities segment related to its acquisition of additional interests in Chilquinta Energía and Luz del Sur in April 2011;
 
§  
a $239 million cumulative noncash impairment charge in 2012 to write down our investment in Rockies Express; and
 
§  
lower earnings at Sempra Natural Gas primarily due to the end of the DWR contract in September 2011; offset by
 
§  
improved results at SDG&E, Sempra Renewables, Sempra Mexico and Parent and Other.
 
Diluted earnings per share for the three-month period decreased by $0.11 per share to $1.09 per share, while diluted earnings per share for the nine-month period decreased by $2.01 per share to $2.31 per share. The decreases in our diluted earnings per share were primarily due to the factors discussed above.
 
 
CHANGE IN ACCOUNTING PRINCIPLE
 
As we discuss in Note 1 of the Notes to Condensed Consolidated Financial Statements herein, effective January 1, 2012, we changed our method of accounting for investment tax credits (ITC) from the flow-through method to the deferral method. We applied this change in accounting principle by retrospectively adjusting the historical financial statement amounts for all periods presented.  The change in accounting principle has no impact on the financial results of SDG&E or SoCalGas for prior or future periods.
 
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 September 30,
   
2012 
2011 
California Utilities:
               
    SDG&E(1)
$
 174 
 65 
%
$
 113 
 39 
%
    SoCalGas(1)
 
 71 
 26 
   
 81 
 28 
 
Sempra International:
               
    Sempra South American Utilities
 
 40 
 15 
   
 50 
 17 
 
    Sempra Mexico
 
 54 
 20 
   
 47 
 16 
 
Sempra U.S. Gas & Power:
               
    Sempra Renewables
 
 13 
 5 
   
 1 
 1 
 
    Sempra Natural Gas
 
 (68)
 (25)
   
 41 
 14 
 
Parent and other(2)
 
 (16)
 (6)
   
 (44)
 (15)
 
Earnings
$
 268 
 100 
%
$
 289 
 100 
%
   
Nine months ended September 30,
   
2012 
2011 
California Utilities:
               
    SDG&E(1)
$
 374 
 66 
%
$
 273 
 26 
%
    SoCalGas(1)
 
 190 
 34 
   
 208 
 20 
 
Sempra International:
               
    Sempra South American Utilities
 
 118 
 21 
   
 386 
 37 
 
    Sempra Mexico
 
 134 
 24 
   
 121 
 12 
 
Sempra U.S. Gas & Power:
               
    Sempra Renewables
 
 47 
 8 
   
 9 
 1 
 
    Sempra Natural Gas
 
 (260)
 (46)
   
 151 
 14 
 
Parent and other(2)
 
 (37)
 (7)
   
 (102)
 (10)
 
Earnings
$
 566 
 100 
%
$
 1,046 
 100 
%
(1)
After preferred dividends.
(2)
Includes after-tax interest expense ($37 million and $34 million for the three months ended September 30, 2012 and 2011, respectively, and $110 million and $103 million for the nine months ended September 30, 2012 and 2011, 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 presented in the table above. Variance amounts are the after-tax earnings impact, unless otherwise noted.
 

EARNINGS BY SEGMENT – CALIFORNIA UTILITIES
(Dollars in millions)



[graph1.gif]


 

 
 
SDG&E
 
Our SDG&E segment recorded earnings of:
 
§  
$174 million in the three months ended September 30, 2012 ($176 million before preferred dividends)
 
§  
$113 million in the three months ended September 30, 2011 ($115 million before preferred dividends)
 
§  
$374 million for the first nine months of 2012 ($378 million before preferred dividends)
 
§  
$273 million for the first nine months of 2011 ($277 million before preferred dividends)
 
The increase of $61 million (54%) in the three months ended September 30, 2012 was primarily due to:
 
§  
$43 million reduction in 2012 income tax expense primarily due to the impact of repairs allowance deductions for 2011 and 2012, as we discuss below in “Income Taxes;”
 
§  
$7 million favorable earnings impact due to the incremental wildfire insurance premiums in 2011 not recovered in revenues until the fourth quarter of 2011;
 
§  
$7 million higher electric transmission margin (excluding Sunrise Powerlink);
 
§  
$6 million lower expense associated with the settlement of 2007 wildfire claims;
 
§  
$5 million higher earnings related to Sunrise Powerlink; and
 
§  
$5 million in earnings for Desert Star in 2012, which was acquired in October 2011; offset by
 
§  
$8 million higher interest expense; and
 
§  
$7 million higher depreciation and operation and maintenance expenses related to California Public Utilities Commission (CPUC)-regulated operations (excluding insurance premiums for wildfire coverage, litigation and Desert Star) with no corresponding increase in the CPUC-authorized margin in 2012 due to the delay in the 2012 General Rate Case (GRC) decision.
 
The increase of $101 million (37%) in the first nine months of 2012 was primarily due to:
 
§  
$37 million reduction in 2012 income tax expense primarily due to the impact of repairs allowance deductions for 2011 and 2012;
 
§  
$29 million higher earnings related to Sunrise Powerlink;
 
§  
$25 million favorable earnings impact due to the incremental wildfire insurance premiums in 2011 not recovered in revenues until the fourth quarter of 2011;
 
§  
$14 million in earnings for Desert Star in 2012, which was acquired in October 2011;
 
§  
$6 million for the recovery in 2012 of incremental costs incurred in prior years for the long-term storage of spent nuclear fuel;
 
§  
$5 million increase in allowance for funds used during construction (AFUDC) related to equity (excluding Sunrise Powerlink);
 
§  
$4 million higher electric transmission margin (excluding Sunrise Powerlink); and
 
§  
$3 million lower expense associated with the settlement of 2007 wildfire claims; offset by
 
§  
$12 million higher depreciation and operation and maintenance expenses related to CPUC-regulated operations (excluding insurance premiums for wildfire coverage, litigation and Desert Star) with no corresponding increase in the CPUC-authorized margin in 2012 due to the delay in the 2012 GRC decision; and
 
§  
$11 million higher interest expense.
 
 
SoCalGas
 
Our SoCalGas segment recorded earnings of:
 
§  
$71 million in the three months ended September 30, 2012 (both before and after preferred dividends)
 
§  
$81 million in the three months ended September 30, 2011 (both before and after preferred dividends)
 
§  
$190 million for the first nine months of 2012 ($191 million before preferred dividends)
 
§  
$208 million for the first nine months of 2011 ($209 million before preferred dividends)
 
The decrease of $10 million (12%) in the three months ended September 30, 2012 was primarily due to:
 
§  
$5 million increase in depreciation with no corresponding increase in CPUC-authorized margin in 2012 due to the delay in the 2012 GRC decision;
 
§  
$3 million due to a slightly higher effective tax rate; and
 
§  
$2 million lower regulatory awards.
 
The decrease of $18 million (9%) in the first nine months of 2012 was primarily due to:
 
§  
$13 million increase in depreciation with no corresponding increase in CPUC-authorized margin in 2012 due to the delay in the 2012 GRC decision; and
 
§  
$8 million higher income tax expense due to a higher effective tax rate; offset by
 
§  
$5 million from an increase in AFUDC related to equity.
 


EARNINGS BY SEGMENT – SEMPRA INTERNATIONAL
(Dollars in millions)



[graph2.gif]

 
 
Sempra South American Utilities
 
Our Sempra South American Utilities segment recorded earnings of:
 
§  
$40 million in the three months ended September 30, 2012
 
§  
$50 million in the three months ended September 30, 2011
 
§  
$118 million for the first nine months of 2012
 
§  
$386 million for the first nine months of 2011
 
The decrease of $10 million (20%) in the three months ended September 30, 2012 was primarily due to:
 
§  
$19 million earnings in 2011 from foreign currency rate effect for U.S. dollar monetary position in Chile; offset by
 
§  
$7 million higher earnings from operations in 2012 primarily attributable to an increase in customer base and higher consumption.
 
The decrease of $268 million in the first nine months of 2012 was primarily due to:
 
§  
a $277 million gain related to the remeasurement of the Chilquinta Energía and Luz del Sur equity method investments in April 2011; and
 
§  
$20 million earnings in 2011 from foreign currency rate effect mainly for U.S. dollar monetary position in Chile; offset by
 
§  
$21 million higher earnings in 2012 due to the acquisition of additional interests in Chilquinta Energía and Luz del Sur in April 2011; and
 
§  
$10 million higher earnings from operations in 2012 primarily attributable to an increase in customer base and higher consumption.
 
 
Sempra Mexico
 
Our Sempra Mexico segment recorded earnings of:
 
§  
$54 million in the three months ended September 30, 2012
 
§  
$47 million in the three months ended September 30, 2011
 
§  
$134 million for the first nine months of 2012
 
§  
$121 million for the first nine months of 2011
 
The increase of $7 million (15%) in the three months ended September 30, 2012 was primarily due to:
 
§  
$17 million primarily due to a prior year outage at our Mexicali power plant and an increase in equity earnings from our joint venture with PEMEX (the Mexican state-owned oil company); and
 
§  
$9 million positive translation effect on Peso-denominated receivables; offset by
 
§  
$4 million income tax expense in 2012 related to Mexican currency and inflation adjustments compared to $17 million income tax benefit in 2011.
 
The increase of $13 million (11%) in the first nine months ended September 30, 2012 was primarily due to:
 
§  
$23 million primarily due to a prior year outage at our Mexicali power plant, an increase in equity earnings from our joint venture with PEMEX and lower operating expenses at the Energía Costa Azul receipt terminal; and
 
§  
$9 million positive translation effect on Peso-denominated receivables; offset by
 
§  
$3 million income tax expense in 2012 related to Mexican currency and inflation adjustments compared to $10 million income tax benefit in 2011; and
 
§  
$8 million lower natural gas sales.
 

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


[graph3.gif]


 
 
Sempra Renewables
 
Our Sempra Renewables segment recorded earnings of:
 
§  
$13 million in the three months ended September 30, 2012
 
§  
$1 million in the three months ended September 30, 2011
 
§  
$47 million for the first nine months of 2012
 
§  
$9 million for the first nine months of 2011
 
The increase of $12 million in the three months ended September 30, 2012 was primarily due to:
 
§  
$7 million higher deferred income tax benefits as a result of increased investments in solar and wind generating assets in 2012;
 
§  
$3 million higher earnings attributable to our solar assets; and
 
§  
$2 million higher earnings attributable to our wind assets.
 
The increase of $38 million in the first nine months of 2012 was primarily due to:
 
§  
$26 million higher deferred income tax benefits as a result of increased investments in solar and wind generating assets in 2012;
 
§  
$8 million higher earnings attributable to our solar assets; and
 
§  
$6 million higher production tax credits from our wind assets.
 
 
Sempra Natural Gas
 
Our Sempra Natural Gas segment recorded (losses) earnings of:
 
§  
$(68) million in the three months ended September 30, 2012
 
§  
$41 million in the three months ended September 30, 2011
 
§  
$(260) million for the first nine months of 2012
 
§  
$151 million for the first nine months of 2011
 
The change in the three months ended September 30, 2012 was primarily due to:
 
§  
a $60 million write-down of our investment in Rockies Express in 2012;
 
§  
$47 million lower earnings from natural gas power plant operations primarily from lower natural gas and power prices, including the impact from the end of the DWR contract as of September 30, 2011; and
 
§  
$14 million lower earnings from LNG primarily due to lower natural gas prices in 2012 compared to the same period of the prior year; offset by
 
§  
$6 million operating losses in 2011 from the El Dorado power plant sold to SDG&E as of October 1, 2011.
 
The change in the first nine months of 2012 was primarily due to:
 
§  
$239 million cumulative write-down of our investment in Rockies Express in 2012;
 
§  
$169 million lower earnings from natural gas power plant operations primarily from lower natural gas and power prices, including the impact from the end of the DWR contract as of September 30, 2011;
 
§  
$20 million lower earnings from LNG primarily due to lower natural gas prices; and
 
§  
$6 million lower earnings primarily from the timing of natural gas inventory withdrawals and an increase in pipeline and storage demand charges related to an increase in natural gas inventory levels; offset by
 
§  
$23 million operating losses in 2011 from the El Dorado power plant sold to SDG&E as of October 1, 2011.
 
 
Parent and Other
 
Losses for Parent and Other were
 
§  
$16 million in the three months ended September 30, 2012
 
§  
$44 million in the three months ended September 30, 2011
 
§  
$37 million for the first nine months of 2012
 
§  
$102 million for the first nine months of 2011
 
The decrease in losses of $28 million (64%) in the three months ended September 30, 2012 was primarily due to:
 
§  
$15 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;
 
§  
$10 million write-down of our investment in the RBS Sempra Commodities joint venture in 2011; and
 
§  
$7 million higher earnings from foreign currency exchange effects mainly related to a Chilean holding company; offset by
 
§  
$6 million lower income tax benefits, net of the effects of a Mexican peso income tax hedge.
 
The decrease in losses of $65 million (64%) in the first nine months of 2012 was primarily due to:
 
§  
$54 million income tax benefit primarily associated with the decision to hold life insurance contracts to term, as we discuss below in “Income Taxes;”
 
§  
$15 million equity losses in 2011 from the RBS Sempra Commodities joint venture, including the $10 million write-down of the investment; and
 
§  
$12 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;
 
§  
$8 million higher earnings from foreign currency exchange effects mainly related to a Chilean holding company; offset by
 
§  
$25 million lower income tax benefits, net of the effects of a Mexican peso income tax hedge and excluding the $54 million income tax benefit discussed above.
 
 
CHANGES IN REVENUES, COSTS AND EARNINGS
 
This section contains a discussion of the differences between periods in specific line items of the Condensed Consolidated Statements of Operations for Sempra Energy, SDG&E and SoCalGas.
 
 
Utilities Revenues
 
Our utilities revenues include
 
Natural gas revenues at:
 
§  
SDG&E
 
§  
SoCalGas
 
§  
Sempra Natural Gas’ Mobile Gas and Willmut Gas, regulated natural gas distribution utilities
 
§  
Sempra Mexico’s Ecogas
 
Electric revenues at:
 
§  
SDG&E
 
§  
Sempra South American Utilities’ Chilquinta Energía and Luz del Sur
 
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 on to customers substantially as incurred. However, SoCalGas’ Gas Cost Incentive Mechanism provides SoCalGas the opportunity to share in the savings and/or costs from buying natural gas for its core customers at prices below or above monthly market-based benchmarks. This mechanism permits full recovery of costs incurred when average purchase costs are within a price range around the benchmark price. Any higher costs incurred or savings realized outside this range are shared between the core customers and SoCalGas. We provide further discussion in Note 9 of the Notes to Condensed Consolidated Financial Statements herein.
 
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 the next year 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 September 30,
Nine months ended September 30,
   
2012 
2011 
2012 
2011 
Electric revenues:
               
  SDG&E
$
 998 
$
 763 
$
 2,349 
$
 2,011 
  Sempra South American Utilities
 
 335 
 
 335 
 
 997 
 
 659 
  Eliminations and adjustments
 
 (1)
 
 (2)
 
 (5)
 
 (5)
 
Total
 
 1,332 
 
 1,096 
 
 3,341 
 
 2,665 
Natural gas revenues:
               
  SoCalGas
 
 728 
 
 844 
 
 2,328 
 
 2,776 
  SDG&E
 
 94 
 
 105 
 
 357 
 
 394 
  Sempra Mexico
 
 17 
 
 20 
 
 55 
 
 70 
  Sempra Natural Gas
 
 17 
 
 14 
 
 67 
 
 67 
  Eliminations and adjustments
 
 (18)
 
 (14)
 
 (49)
 
 (39)
 
Total
 
 838 
 
 969 
 
 2,758 
 
 3,268 
    Total utilities revenues
$
 2,170 
$
 2,065 
$
 6,099 
$
 5,933 
Cost of electric fuel and purchased power:
               
  SDG&E
$
 301 
$
 207 
$
 604 
$
 534 
  Sempra South American Utilities
 
 212 
 
 201 
 
 647 
 
 442 
  Eliminations and adjustments
 
 2 
 
 ― 
 
 1 
 
 ― 
 
Total
$
 515 
$
 408 
$
 1,252 
$
 976 
Cost of natural gas:
               
  SoCalGas
$
 175 
$
 267 
$
 703 
$
 1,133 
  SDG&E
 
 29 
 
 40 
 
 130 
 
 175 
  Sempra Mexico
 
 10 
 
 15 
 
 32 
 
 49 
  Sempra Natural Gas
 
 4 
 
 5 
 
 16 
 
 23 
  Eliminations and adjustments
 
 (6)
 
 (5)
 
 (17)
 
 (13)
 
Total
$
 212 
$
 322 
$
 864 
$
 1,367 
 
Sempra Energy Consolidated
 
Electric Revenues
 
During the three months ended September 30, 2012, our electric revenues increased by $236 million (22%) to $1.3 billion primarily due to:
 
§  
$235 million increase at SDG&E, which we discuss below; and
 
§  
$31 million increase at Luz del Sur primarily due to higher commodity prices and volume; offset by
 
§  
$31 million decrease at Chilquinta Energía mainly due to lower commodity prices.
 
Our utilities’ cost of electric fuel and purchased power increased by $107 million (26%) to $515 million in the three months ended September 30, 2012 primarily due to:
 
§  
$94 million increase at SDG&E, which we discuss below; and
 
§  
$11 million increase at our South American utilities due to higher commodity prices and volume at Luz del Sur, offset by lower commodity prices at Chilquinta Energía.
 
During the nine months ended September 30, 2012, our electric revenues increased by $676 million (25%) to $3.3 billion primarily due to:
 
§  
$338 million increase at our South American utilities, primarily from the consolidation of Chilquinta Energía and Luz del Sur acquired in April 2011. In addition, during the second and third quarters of 2012, electric revenues increased due to higher commodity prices and volume at Luz del Sur, offset by lower commodity prices at Chilquinta Energía; and
 
§  
$338 million increase at SDG&E, which we discuss below.
 
Our utilities’ cost of electric fuel and purchased power increased by $276 million (28%) to $1.3 billion in the nine months ended September 30, 2012 primarily due to:
 
§  
$205 million increase at Chilquinta Energía and Luz del Sur associated with the higher revenues; and
 
§  
$70 million increase at SDG&E, which we discuss below.
 
Natural Gas Revenues
 
During the three months ended September 30, 2012, Sempra Energy’s natural gas revenues decreased by $131 million (14%) to $838 million, and the cost of natural gas decreased by $110 million (34%) to $212 million. The decrease in natural gas revenues included $116 million at SoCalGas and $11 million at SDG&E, primarily due to decreases in commodity costs in 2012.
 
During the nine months ended September 30, 2012, Sempra Energy’s natural gas revenues decreased by $510 million (16%) to $2.8 billion, and the cost of natural gas decreased by $503 million (37%) to $864 million. The decrease in natural gas revenues included $448 million at SoCalGas and $37 million at SDG&E.
 
We discuss the changes in natural gas revenues and the 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 nine-month periods ended September 30, 2012 and 2011. Because the cost of electricity is substantially recovered in rates, changes in the cost are reflected in the changes in revenues.
 

SDG&E
ELECTRIC DISTRIBUTION AND TRANSMISSION
(Volumes in millions of kilowatt-hours, dollars in millions)
   
Nine months ended
September 30, 2012
Nine months ended
September 30, 2011
Customer class
Volumes
Revenue
Volumes
Revenue
Residential
 5,650 
$
 907 
 5,552 
$
 916 
Commercial
 5,157 
 
 753 
 5,068 
 
 760 
Industrial
 1,529 
 
 184 
 1,525 
 
 187 
Direct access
 2,473 
 
 110 
 2,427 
 
 109 
Street and highway lighting
 70 
 
 9 
 76 
 
 11 
   
 14,879 
 
 1,963 
 14,648 
 
 1,983 
Other revenues
   
 125 
   
 84 
Balancing accounts
   
 261 
   
 (56)
    Total(1)
 
$
 2,349 
 
$
 2,011 
(1)
Includes sales to affiliates of $5 million in both 2012 and 2011.

During the three months ended September 30, 2012, electric revenues increased by $235 million (31%) to $998 million at SDG&E, primarily due to:
 
§  
an increase in cost of electric fuel and purchased power in 2012;
 
§  
$62 million higher authorized revenues from electric transmission;
 
§  
$44 million higher recoverable expenses that are fully offset in operation and maintenance expenses;
 
§  
$35 million higher authorized revenues from electric generation, primarily due to the acquisition of the Desert Star generation facility in October 2011; and
 
§  
$15 million revenues associated with incremental wildfire insurance premiums.
 
SDG&E’s cost of electric fuel and purchased power increased by $94 million (45%) to $301 million in the three months ended September 30, 2012 primarily due to the cost of power generated and purchased to replace the loss of SONGS-produced power.
 
During the nine months ended September 30, 2012, electric revenues increased by $338 million (17%) to $2.3 billion at SDG&E, primarily due to:
 
§  
an increase in cost of electric fuel and purchased power in 2012;
 
§  
$94 million higher authorized revenues from electric generation, primarily due to the acquisition of the Desert Star generation facility in October 2011;
 
§  
$69 million higher authorized revenues from electric transmission;
 
§  
$67 million higher recoverable expenses that are fully offset in operation and maintenance expenses; and
 
§  
$47 million revenues associated with incremental wildfire insurance premiums.
 
SDG&E’s cost of electric fuel and purchased power increased by $70 million (13%) to $604 million in the nine months ended September 30, 2012 primarily due to the cost of power generated and purchased to replace the loss of SONGS-produced power.
 
We do not include in the Condensed Consolidated Statements of Operations the commodity costs (and the revenues to recover those costs) associated with long-term contracts that are allocated to SDG&E by the California DWR. However, we do include the associated volumes and distribution revenues in the table above. We provide further discussion of these contracts in Note 1 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
 
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 nine-month periods ended September 30, 2012 and 2011. 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 Updated Annual Report.
 

SDG&E
NATURAL GAS SALES AND TRANSPORTATION
(Volumes in billion cubic feet, dollars in millions)
   
Natural Gas Sales
Transportation
Total
Customer class
Volumes
Revenue
Volumes
Revenue
Volumes
Revenue
Nine months ended September 30, 2012:
                 
    Residential
 24 
$
 210 
 ― 
$
 1 
 24 
$
 211 
    Commercial and industrial
 11 
 
 58 
 7 
 
 7 
 18 
 
 65 
    Electric generation plants
 ― 
 
 ― 
 26 
 
 7 
 26 
 
 7 
   
 35 
$
 268 
 33 
$
 15 
 68 
 
 283 
    Other revenues
               
 30 
    Balancing accounts
               
 44 
        Total(1)
             
$
 357 
Nine months ended September 30, 2011:
                 
    Residential
 24 
$
 261 
 ― 
$
 ― 
 24 
$
 261 
    Commercial and industrial
 11 
 
 80 
 6 
 
 7 
 17 
 
 87 
    Electric generation plants
 ― 
 
 ― 
 20 
 
 6 
 20 
 
 6 
   
 35 
$
 341 
 26 
$
 13 
 61 
 
 354 
    Other revenues
               
 26 
    Balancing accounts
               
 14 
        Total(1)
             
$
 394 
(1)
Includes sales to affiliates of $1 million in both 2012 and 2011.

During the three months ended September 30, 2012, SDG&E’s natural gas revenues decreased by $11 million (10%) to $94 million, and the cost of natural gas sold decreased by $11 million (28%) to $29 million. During the nine months ended September 30, 2012, SDG&E’s natural gas revenues decreased by $37 million (9%) to $357 million, and the cost of natural gas decreased by $45 million (26%) to $130 million.
 
SDG&E’s average cost of natural gas for the three months ended September 30, 2012 was $3.90 per thousand cubic feet (Mcf) compared to $5.30 per Mcf for the corresponding period in 2011, a 26-percent decrease of $1.40 per Mcf, resulting in lower revenues and cost of $10 million. For the first nine months of 2012, SDG&E’s average cost of natural gas was $3.66 per Mcf compared to $4.96 per Mcf for the corresponding period in 2011, a 26-percent decrease of $1.30 per Mcf, resulting in lower revenues and cost of $46 million.
 

SOCALGAS
NATURAL GAS SALES AND TRANSPORTATION
(Volumes in billion cubic feet, dollars in millions)
   
Natural Gas Sales
Transportation
Total
Customer class
Volumes
Revenue
Volumes
Revenue
Volumes
Revenue
Nine months ended September 30, 2012:
                 
    Residential
 168 
$
 1,382 
 1 
$
 6 
 169 
$
 1,388 
    Commercial and industrial
 75 
 
 438 
 212 
 
 181 
 287 
 
 619 
    Electric generation plants
 ― 
 
 ― 
 180 
 
 34 
 180 
 
 34 
    Wholesale
 ― 
 
 ― 
 129 
 
 18 
 129 
 
 18 
   
 243 
$
 1,820 
 522 
$
 239 
 765 
 
 2,059 
    Other revenues
               
 74 
    Balancing accounts
               
 195 
        Total(1)
             
$
 2,328 
Nine months ended September 30, 2011:
                 
    Residential
 175 
$
 1,678 
 1 
$
 2 
 176 
$
 1,680 
    Commercial and industrial
 75 
 
 566 
 204 
 
 163 
 279 
 
 729 
    Electric generation plants
 ― 
 
 ― 
 127 
 
 35 
 127 
 
 35 
    Wholesale
 ― 
 
 ― 
 107 
 
 14 
 107 
 
 14 
   
 250 
$
 2,244 
 439 
$
 214 
 689 
 
 2,458 
    Other revenues
               
 71 
    Balancing accounts
               
 247 
        Total(1)
             
$
 2,776 
(1)
Includes sales to affiliates of $48 million in 2012 and $38 million in 2011.

During the three months ended September 30, 2012, SoCalGas’ natural gas revenues decreased by $116 million (14%) to $728 million, and the cost of natural gas sold decreased by $92 million (34%) to $175 million. During the nine months ended September 30, 2012, SoCalGas’ natural gas revenues decreased by $448 million (16%) to $2.3 billion, and the cost of natural gas sold decreased by $430 million (38%) to $703 million.
 
SoCalGas’ average cost of natural gas for the three months ended September 30, 2012 was $3.26 per Mcf compared to $4.80 per Mcf for the corresponding period in 2011, a 32-percent decrease of $1.54 per Mcf, resulting in lower revenues and cost of $83 million.
 
For the first nine months of 2012, SoCalGas’ average cost of natural gas was $2.90 per Mcf compared to $4.53 per Mcf for the corresponding period in 2011, a 36-percent decrease of $1.63 per Mcf, resulting in lower revenues and cost of $394 million. The decrease in the cost of natural gas sold was also attributable to lower demand for natural gas from a warmer winter in 2012.
 
 
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 basis for the tariffs do not meet the requirement necessary for treatment under GAAP for regulatory accounting. We discuss revenue recognition further for Chilquinta Energía and Luz del Sur in Note 1 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
Operations of Mobile Gas, Willmut Gas and Ecogas qualify for regulatory accounting treatment under applicable GAAP, similar to the California Utilities.
 
The table below summarizes natural gas and electric revenues for our other utilities for the nine months ended September 30, 2012 and 2011:
 

OTHER UTILITIES
NATURAL GAS AND ELECTRIC REVENUES
           
(Dollars in millions)
   
Nine months ended
September 30, 2012
Nine months ended
September 30, 2011
 
Volumes
Revenue
Volumes
Revenue
Natural Gas Sales (billion cubic feet):
           
Sempra Natural Gas:
           
 
Mobile Gas
 30 
$
 62 
 29 
$
 67 
 
Willmut Gas(1)
 8 
 
 5 
 ― 
 
 ― 
Sempra Mexico - Ecogas
 17 
 
 55 
 16 
 
 70 
 
Total
 55 
$
 122 
 45 
$
 137 
               
Electric Sales (million kilowatt hours)(2):
           
Sempra South American Utilities:
           
 
Luz del Sur
 4,996 
$
 563 
 3,118 
$
 317 
 
Chilquinta Energía
 2,015 
 
 393 
 1,201 
 
 315 
   
 7,011 
 
 956 
 4,319 
 
 632 
Other service revenues
   
 41 
   
 27 
 
Total
 
$
 997 
 
$
 659 
(1)
We acquired Willmut Gas in May 2012.
           
(2)
We accounted for Luz del Sur and Chilquinta Energía under the equity method until April 6, 2011, when they became consolidated entities upon our acquisition of additional ownership interests.
 

 
 
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 September 30,
Nine months ended September 30,
   
2012 
2011 
2012 
2011 
Energy-related businesses revenues:
               
  Sempra South American Utilities
$
 21 
$
 10 
$
 64 
$
 47 
  Sempra Mexico
 
 164 
 
 163 
 
 379 
 
 491 
  Sempra Renewables
 
 27 
 
 7 
 
 49 
 
 17 
  Sempra Natural Gas
 
 277 
 
 441 
 
 694 
 
 1,273 
  Intersegment revenues, adjustments and eliminations(1)
 
 (152)
 
 (110)
 
 (306)
 
 (329)
       Total energy-related businesses revenues
$
 337 
$
 511 
$
 880 
$
 1,499 
Cost of natural gas, electric fuel and purchased power(2):
               
  Sempra Mexico
$
 72 
$
 82 
$
 145 
$
 253 
  Sempra Renewables
 
 2 
 
 ― 
 
 2 
 
 ― 
  Sempra Natural Gas
 
 215 
 
 283 
 
 504 
 
 774 
  Adjustments and eliminations(1)
 
 (153)
 
 (113)
 
 (305)
 
 (333)
       Total cost of natural gas, electric fuel
               
         and purchased power
$
 136 
$
 252 
$
 346 
$
 694 
Other cost of sales(2):
               
  Sempra South American Utilities
$
 20 
$
 45 
$
 48 
$
 54 
  Sempra Mexico
 
 1 
 
 1 
 
 3 
 
 3 
  Sempra Natural Gas
 
 22 
 
 23 
 
 66 
 
 66 
  Adjustments and eliminations(1)
 
 ― 
 
 (1)
 
 ― 
 
 ― 
       Total other cost of sales
$
 43 
$
 68 
$
 117 
$
 123 
(1)
Includes eliminations of intercompany activity.
       
(2)
Excludes depreciation and amortization, which are shown separately on the Condensed Consolidated Statements of Operations.
           

During the three months ended September 30, 2012, revenues from our energy-related businesses decreased by $174 million (34%) to $337 million. The decrease included
 
§  
$164 million decrease at Sempra Natural Gas due to decreased power sales primarily from the end of the DWR contract as of September 30, 2011. Part of the decrease was offset by higher merchant sales in 2012; and
 
§  
$42 million higher intercompany eliminations primarily associated with sales between Sempra Mexico and Sempra Natural Gas; offset by
 
§  
$20 million increase at Sempra Renewables mainly from revenues generated by our solar assets.
 
During the three months ended September 30, 2012, the cost of natural gas, electric fuel and purchased power for our energy-related businesses decreased by $116 million (46%) to $136 million. The decrease was primarily due to:
 
§  
$68 million decrease at Sempra Natural Gas primarily associated with the lower revenues; and
 
§  
$40 million higher intercompany eliminations primarily associated with sales between Sempra Mexico and Sempra Natural Gas.
 
During the nine months ended September 30, 2012, revenues from our energy-related businesses decreased by $619 million (41%) to $880 million. The decrease included
 
§  
$579 million decrease at Sempra Natural Gas due to decreased power sales primarily from the end of the DWR contract, and lower natural gas revenues from its LNG operations as a result of lower natural gas prices and volumes. Part of the decrease was offset by higher merchant sales in 2012; and
 
§  
$112 million decrease at Sempra Mexico mainly from lower natural gas prices and lower LNG volumes sold; offset by
 
§  
$32 million increase at Sempra Renewables mainly from revenues generated by our solar assets; and
 
§  
$23 million lower intercompany eliminations primarily associated with sales between Sempra Mexico and Sempra Natural Gas.
 
During the nine months ended September 30, 2012, the cost of natural gas, electric fuel and purchased power for our energy-related businesses decreased by $348 million (50%) to $346 million. The decrease was primarily due to:
 
§  
$270 million decrease at Sempra Natural Gas primarily associated with the lower revenues; and
 
§  
$108 million decrease at Sempra Mexico associated with the lower revenues; offset by
 
§  
$28 million lower intercompany eliminations primarily associated with sales between Sempra Mexico and Sempra Natural Gas.
 
 
Operation and Maintenance
 
Sempra Energy Consolidated
 
For the three months ended September 30, 2012, our operation and maintenance expenses increased by $41 million (6%) to $732 million primarily due to:
 
§  
$54 million increase at SDG&E, which we discuss below; offset by
 
§  
$15 million decrease at SoCalGas, primarily due to lower recoverable expenses in 2012.
 
For the nine months ended September 30, 2012, our operation and maintenance expenses increased by $120 million (6%) to $2.1 billion. The increase included
 
§  
$96 million increase at SDG&E, which we discuss below; and
 
§  
$57 million increase at Sempra South American Utilities primarily from the consolidation of expenses in Chile and Peru; offset by
 
§  
$15 million decrease at Parent and Other, mainly due to lower general and administrative costs, including amounts in 2011 related to the dissolution of our former commodities-marketing businesses; and
 
§  
$13 million decrease at SoCalGas, primarily due to $34 million lower recoverable expenses, offset by $20 million higher other operation and maintenance costs.
 
SDG&E
 
For the three months ended September 30, 2012, SDG&E’s operation and maintenance expenses increased by $54 million (21%) to $309 million. The increase was primarily due to:
 
§  
$43 million higher recoverable expenses primarily due to an increase in transmission-related operating expenses;
 
§  
$18 million higher other operation and maintenance costs, including
 
o  
$5 million associated with the Desert Star generation facility acquired by SDG&E in October 2011, and
 
o  
$4 million increase in liability insurance premiums for wildfire coverage; and
 
§  
$3 million higher operation and maintenance expenses at Otay Mesa VIE; offset by
 
§  
$10 million lower litigation expenses from wildfire claims.
 
For the nine months ended September 30, 2012, SDG&E’s operation and maintenance expenses increased by $96 million (13%) to $852 million. The increase was due to:
 
§  
$69 million higher recoverable expenses primarily due to an increase in transmission-related operating expenses; and
 
§  
$40 million higher other operation and maintenance costs, including
 
o  
$21 million associated with the Desert Star generation facility acquired by SDG&E in October 2011 and from increased costs from the operations of other electric generating facilities,
 
o  
$10 million of costs associated with the continued roll-out of the advanced meters, and
 
o  
$5 million increase in liability insurance premiums for wildfire coverage, offset by
 
o  
$10 million recovery in 2012 of incremental costs incurred in prior years for the long-term storage of spent nuclear fuel; offset by
 
§  
$8 million lower operation and maintenance expenses at Otay Mesa VIE; and
 
§  
$5 million lower litigation expenses from wildfire claims.
 
 
Equity (Losses) Earnings, Before Income Tax
 
Equity losses from our investment in Rockies Express were $87 million and $366 million in the three months and nine months ended September 30, 2012, respectively, compared to equity earnings of $10 million and $29 million in the three months and nine months ended September 30, 2011, respectively. Equity losses in the three months and nine months ended September 30, 2012 included write-downs of our investment in Rockies Express of $100 million and $400 million, respectively.
 
Equity losses before income taxes from our other investments decreased by $15 million and $24 million in the three months and nine months ended September 30, 2012, respectively, primarily due to a $16 million pretax write-down in the third quarter of 2011 of our investment in RBS Sempra Commodities.
 
 
Other Income, Net
 
Sempra Energy Consolidated
 
In the three months ended September 30, 2012, other income, net, increased by $32 million to $44 million primarily due to:
 
§  
$17 million gains from investment activity related to our executive retirement and deferred compensation plans in 2012 compared to $6 million losses in 2011; and
 
§  
$26 million losses on interest rate and foreign exchange instruments in 2011; offset by
 
§  
$13 million decrease in AFUDC primarily due to completion of construction on the Sunrise Powerlink project in June 2012 at SDG&E.
 
In the nine months ended September 30, 2012, other income, net, increased by $51 million (59%) to $137 million primarily due to:
 
§  
$11 million gains on interest rate and foreign exchange instruments in 2012 compared to $14 million losses in 2011;
 
§  
$14 million higher gains from investment activity related to our executive retirement and deferred compensation plans in 2012; and
 
§  
$13 million increase in AFUDC at the California Utilities, including $7 million increase at SDG&E due to construction on the Sunrise Powerlink project.
 
SDG&E
 
In the three months ended September 30, 2012, other income, net, decreased by $21 million (81%) to $5 million mainly due to a decrease in AFUDC related to equity primarily due to completion of construction on the Sunrise Powerlink project in June 2012. In the nine months ended September 30, 2012, other income, net, increased by $4 million (7%) to $59 million primarily due to an increase in AFUDC related to equity from construction on the Sunrise Powerlink project.
 
 
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)
     
Three months ended September 30,
     
2012 
 
2011 
         
Effective
       
Effective
 
     
Income Tax
 
Income
   
Income Tax
 
Income
 
     
Expense
 
Tax Rate
   
Expense
 
Tax Rate
 
Sempra Energy Consolidated
$
 49 
 
 15 
%
$
 75 
 
 19 
%
SDG&E
 
 38 
 
 17 
   
 63 
 
 32 
 
SoCalGas
 
 37 
 
 34 
   
 41 
 
 34 
 
     
Nine months ended September 30,
     
2012 
 
2011 
         
Effective
       
Effective
 
     
Income Tax
 
Income
   
Income Tax
 
 Income
 
     
Expense
 
Tax Rate
   
Expense
 
Tax Rate
 
Sempra Energy Consolidated
$
 48 
 
 8 
%
$
 289 
 
 22 
%
SDG&E
 
 151 
 
 27 
   
 154 
 
 35 
 
SoCalGas
 
 105 
 
 35 
   
 106 
 
 34 
 
                       
                       
 
 
Sempra Energy Consolidated
 
The decrease in income tax expense in the three months ended September 30, 2012 was due to lower pretax income and a lower effective income tax rate. The lower effective income tax rate in the three months ended September 30, 2012 was primarily due to:
 
§  
$38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012. The change in income tax treatment was made pursuant to an Internal Revenue Service Revenue Procedure allowing certain capitalized repair costs for electric transmission and distribution assets to be deducted from taxable income when incurred for tax years beginning on or after January 1, 2011; and
 
§  
higher planned renewable energy income tax credits and deferred income tax benefits related to renewable energy projects; offset by
 
§  
higher income tax expense in 2012 due to Mexican currency translation and inflation adjustments; and
 
§  
higher income tax expense due to unfavorable resolution of prior years’ income tax items.
 
In the nine months ended September 30, 2012, Sempra Energy’s income tax expense decreased due to significantly lower pretax income (due to the write-down of our investment in Rockies Express in 2012 and the remeasurement gain in 2011 related to our acquisition of controlling interests in Chilquinta Energía and Luz del Sur) and a lower effective income tax rate. The lower effective income tax rate was primarily due to:
 
§  
$54 million income tax benefit primarily associated with our decision to hold life insurance contracts kept in support of certain benefit plans to term. Previously, we took the position that we might cash in or sell these contracts before maturity, which required that we record deferred income taxes on unrealized gains on investments held within the insurance contracts;
 
§  
$38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012, as discussed above; and
 
§  
higher planned renewable energy income tax credits and deferred income tax benefits related to renewable energy projects; offset by
 
§  
lower income in 2012 in countries with lower statutory income tax rates; such income was higher in 2011 due to the $277 million non-taxable gain discussed above;
 
§  
higher income tax expense in 2012 due to Mexican currency translation and inflation adjustments;
 
§  
higher income tax expense due to unfavorable resolution of prior years’ income tax items; and
 
§  
higher U.S. income tax on non-U.S. non-operating activity due to the expiration of the look-through rule, as we discuss below.
 
As we discuss in Note 5 of the Notes to Condensed Consolidated Financial Statements herein, 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. We also discuss renewable energy income tax credits and deferred income tax benefits related to renewable energy projects in Notes 1 and 5 of the Notes to Condensed Consolidated Financial Statements herein.
 
As discussed above under “Change in Accounting Principle,” through December 31, 2011, Sempra Renewables used what is referred to as the flow-through method of accounting in which the investment tax credits associated with a project are recognized as a reduction of tax expense in the year in which capacity is placed in service. Starting in the first quarter of 2012, Sempra Renewables adopted the deferral method of accounting for these projects. Under this methodology, instead of recognizing the investment tax credit, Sempra Renewables reduced the book basis of the asset by the amount of the tax credit. This resulted in lower book depreciation, but higher income tax expense. Therefore, over time total earnings will be equal under the deferred method when compared to the flow-through method. This change in accounting principle was applied retrospectively in the first quarter of 2012.
 
We have used grant accounting for certain assets placed into service in 2012, including assets that were under construction in 2011, in anticipation of applying for cash grants. Grant accounting for cash grants is very similar to the deferral method of accounting for investment tax credits, the primary difference being the recording of a grant receivable instead of an income tax receivable.
 
In 2012, we anticipate that our effective income tax rate will be approximately 26% compared to 30% in 2011, excluding income tax and pretax items that cannot be reliably forecasted, as discussed in Note 5 of the Notes to Condensed Consolidated Financial Statements herein. This decrease is primarily as a result of higher planned renewable income tax credits, higher deferred income tax benefits related to renewable energy projects, and higher income tax benefits due to the change for income tax purposes allowing certain capitalized utility plant fixed asset repairs to be deducted from taxable income when incurred; offset by decreased favorable income tax deductions for self-developed software costs and higher U.S. income tax on non-U.S. non-operating activity due to the expiration of the look-through rule, as we discuss below.
 
In the years 2013 through 2016, we are currently projecting that our effective income tax rate will be, excluding income tax items that cannot be reliably forecasted, approximately 30% to 32%. This increase in effective income tax rates is primarily due to projected increases in pretax income, decreases in favorable income tax deductions for self-developed software costs, increases in the amount by which book depreciation exceeds normalized tax depreciation, and lower exclusions from income for the equity portion of AFUDC.
 
The projected effective tax rates above do not include any impact from a possible repatriation of future earnings from our Mexican and Peruvian subsidiaries. If we were to repatriate future non-U.S. earnings, as we discuss below, the rates would increase accordingly.
 
SDG&E
 
SDG&E’s income tax expense decreased in the three months ended September 30, 2012 primarily due to a lower effective income tax rate. The lower effective tax rate was primarily due to:
 
§  
$38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012.  The change in income tax treatment was made pursuant to an Internal Revenue Service Revenue Procedure allowing certain capitalized repair costs for electric transmission and distribution assets to be deducted from taxable income when incurred for tax years beginning on or after January 1, 2011; and
 
§  
higher favorable resolutions of prior years' income tax items; offset by
 
§  
the impact of Otay Mesa VIE, as we discuss below; and
 
§  
lower exclusions from taxable income of the equity portion of AFUDC.
 
SDG&E’s income tax expense decreased in the nine months ended September 30, 2012 when compared to the same period in 2011 primarily due to a lower effective income tax rate. The lower effective tax rate was primarily due to:
 
§  
$38 million income tax benefit in 2012 due to a change in the income tax treatment of certain repairs that are capitalized for book purposes, including $22 million benefit related to the 2011 U.S. federal income tax return filed in the third quarter of 2012, as discussed above;
 
§  
the impact of Otay Mesa VIE, as we discuss below;
 
§  
lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; and
 
§  
higher favorable resolutions of prior years’ income tax items; offset by
 
§  
lower exclusions from taxable income of the equity portion of AFUDC.
 
Results for Sempra Energy Consolidated and SDG&E include Otay Mesa VIE, which is consolidated, and therefore, their effective income tax rates are impacted by the VIE’s stand-alone effective income tax rate.
 
In 2012, we anticipate that SDG&E’s effective income tax rate will be approximately 33% compared to 34% in 2011, excluding income tax and pretax items that cannot be reliably forecasted. This decrease is due to higher income tax benefits due to a change for income tax purposes allowing certain capitalized utility plant fixed asset repairs to be deducted from taxable income when incurred; and lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; offset by a projected rise in pretax income, combined with lower exclusions from income for the equity portion of AFUDC (due to the completion of construction on the Sunrise Powerlink electric transmission line). In the years 2013 through 2016, we are currently projecting that SDG&E’s effective income tax rate will be approximately 37%, excluding income tax items that cannot be reliably forecasted, due to projected increases in pretax income.
 
 
SoCalGas
 
SoCalGas’ income tax expense decreased in the three months ended September 30, 2012 primarily due to lower pretax income. While the effective tax rate for 2012 did not change significantly from 2011, it was impacted by:
 
§  
lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; and
 
§  
higher exclusions from taxable income of the equity portion of AFUDC; offset by
 
§  
lower deductions for cost of removal of utility plant fixed assets.
 
In the nine months ended September 30, 2012, income tax expense decreased at SoCalGas primarily due to lower pretax income, offset by a higher effective income tax rate. The higher effective tax rate was primarily due to:
 
§  
lower deductions for self-developed software costs; offset by
 
§  
lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets; and
 
§  
higher exclusions from taxable income of the equity portion of AFUDC.
 
In 2012, we anticipate that SoCalGas’ effective income tax rate will be approximately 35% compared to 33% in 2011, excluding income tax and pretax items that cannot be reliably forecasted. This increase is due to a projected rise in pretax income, combined with a decrease in favorable income tax deductions for self-developed software costs, offset by lower book depreciation over income tax depreciation related to a certain portion of utility plant fixed assets. In the years 2013 through 2016, we are currently projecting that SoCalGas’ effective income tax rate, excluding income tax items that cannot be reliably forecasted, will be approximately 40% to 42%. This expected increase is primarily due to projected increases in pretax income, combined with a decrease in favorable income tax deductions for self-developed software costs, and an increase in the amount by which book depreciation exceeds normalized tax depreciation. 
 
In general, the following items are subject to flow-through treatment at the California Utilities:
 
§  
repairs to a certain portion of utility plant fixed assets
 
§  
the equity portion of AFUDC
 
§  
cost of removal of utility plant assets
 
§  
self-developed software costs
 
§  
depreciation on a certain portion of utility plant fixed assets
 
We discuss the impact of items subject to flow-through treatment on our effective income tax rates in Note 5 of the Notes to Condensed Consolidated Financial Statements herein.
 
In December 2010, the Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 (2010 Tax Act) was signed into law. The 2010 Tax Act included the extension of bonus depreciation for U.S. federal income tax purposes for years 2010 through 2012 and an increase in the rate of bonus depreciation from 50 percent to 100 percent. This increased rate only applies to certain investments made after September 8, 2010 through December 31, 2012. Self-constructed property, where the construction period exceeds one year, construction starts between December 31, 2007 and January 1, 2013, and the property is placed in service by December 31, 2013, will qualify for bonus depreciation in 2013 at either the original or increased rate.
 
Due to the extension of bonus depreciation, Sempra Energy generated a large U.S. federal NOL in 2011 and is currently projecting a large U.S. federal NOL in 2012. We currently project that the total NOL will not be fully utilized until approximately 2016. Because of these projected NOLs, and the carryforward of U.S. federal income tax credits discussed below, Sempra Energy expects no U.S. federal income tax payments in years 2012 through 2015. However, because bonus depreciation only creates a temporary difference, versus a permanent difference, between Sempra Energy’s U.S. federal income tax return and its U.S. GAAP financial statements, it does not impact Sempra Energy’s effective income tax rate. We expect larger U.S. federal income tax payments in the future as these temporary differences reverse.
 
SDG&E and SoCalGas both generated a large U.S. federal NOL in 2011, also due to bonus depreciation. In 2012, SoCalGas will be able to, on a stand-alone basis, carry back its 2011 NOL to 2009 and 2010 to offset taxable income in those years. Therefore, SoCalGas’ 2011 NOL is recorded as current income tax receivable. SDG&E will be able to, on a stand-alone basis, carry back a majority of its 2011 NOL to 2009 and 2010 to offset taxable income in those years, which portion is recorded as current income tax receivable. The remaining portion of SDG&E’s 2011 NOL is recorded as a deferred income tax asset.
 
SDG&E is currently projecting a large U.S. federal NOL in 2012. However, SoCalGas is not projecting a U.S. federal NOL in 2012. SDG&E’s 2012 NOL is currently projected to be carried forward, and is therefore recorded as a deferred income tax asset. We currently project that SDG&E’s carryforward NOL, on a stand-alone basis, will be fully utilized by 2014. Because of this projected 2012 NOL, and the carryforward of U.S. federal income tax credits discussed below, SDG&E expects no U.S. federal income tax payments in 2012. However, because bonus depreciation only creates a temporary difference between SDG&E’s and SoCalGas’ U.S. federal income tax returns and U.S. GAAP financial statements, it does not impact SDG&E’s and SoCalGas’ effective income tax rates. We expect larger U.S. federal income tax payments in the future as these temporary differences reverse.
 
Bonus depreciation, in addition to impacting Sempra Energy’s and SDG&E’s U.S. federal income tax payments, will also have a temporary impact on Sempra Energy’s and SDG&E’s ability to utilize their U.S. federal income tax credits, which primarily are investment tax credits and production tax credits generated by Sempra Energy’s and SDG&E’s current and future renewable energy investments. However, based on current projections, Sempra Energy and SDG&E do not expect, based on more-likely-than-not criteria required under U.S. GAAP, any of these income tax credits to expire prior to the end of their 20-year carryforward period, as allowed under current U.S. federal income tax law. We also expect bonus depreciation to increase the deferred tax component of SDG&E’s and SoCalGas’ rate base, which reduces rate base.
 
We are currently considering the potential repatriation of future earnings beginning in 2013 from certain of our non-U.S. subsidiaries in Mexico and Peru. However, we expect to continue to indefinitely reinvest future earnings from our Chilean subsidiaries. Currently, all future repatriated earnings would be subject to U.S. income tax (with a credit for foreign income taxes), and future repatriations from Peru would be subject to local country withholding tax. Because this potential repatriation would only be from future earnings, it does not change our current assertion, as we discuss in Note 7 of the Notes to Consolidated Financial Statements in the Updated Annual Report, that we intend to continue to indefinitely reinvest, for the foreseeable future, our cumulative undistributed non-U.S. earnings as of September 30, 2012. The forward-looking statements above on income tax matters do not include any impact from potential repatriation of future non-U.S. earnings.
 
Additionally, the 2010 Tax Act extended for years 2010 and 2011 the U.S. federal income tax law known as the look-through rule. This rule allows, under certain situations, for certain non-operating activity (e.g., dividend income, royalty income, interest income, rental income, etc.), of a greater than 50-percent owned non-U.S. subsidiary, to not be taxed under U.S. federal income tax law. As of September 30, 2012, this rule has not yet been extended beyond 2011, therefore, Sempra Energy’s effective income tax rate is currently unfavorably impacted for 2012 and could potentially increase, over the amounts projected above, in subsequent years. However, for years 2013-2016, we currently do not believe the lack of the extension of this rule will cause the effective income tax rate to be outside the estimated range provided above. It is generally thought that this rule will be extended beyond 2011. However, until the extension of the rule is enacted into law, U.S. GAAP accounting rules preclude us from reflecting its favorable impact in our financial results for 2012. If, starting in 2013, we were to repatriate future earnings from Mexico and Peru, as discussed above, the loss of the look-through rule will not result in additional U.S. federal income tax.
 
Mexican Currency Exchange Rate and Inflation Impact on Income Taxes and Related Economic Hedging Activity
 
Our Mexican subsidiaries have U.S. dollar denominated receivables and payables (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 that are denominated in the Mexican peso, which must be translated to U.S. dollars for financial reporting purposes. In addition, monetary assets and liabilities are adjusted for Mexican inflation for Mexican income tax purposes.
 
The fluctuations in both the currency exchange rate for the Mexican peso against the U.S. dollar, with regard to Mexican monetary assets and liabilities, and Mexican inflation are subject to Mexican income tax and thus expose us to significant fluctuations in our income tax expense.  The income tax expense of Sempra Mexico is impacted by these factors. Parent and Other is also impacted due to a Mexican holding company. The impacts of these fluctuations may offset to some extent at the consolidated level.
 
For Sempra Energy Consolidated, the impacts on the three months and nine months ended September 30, 2012 and 2011 related to the factors described above are as follows:
 

MEXICAN CURRENCY IMPACT ON INCOME TAXES AND RELATED ECONOMIC HEDGING ACTIVITY
(Dollars in millions)
       
     
Three months ended September 30,
Nine months ended September 30,
     
2012 
2011 
2012 
2011 
Income tax (expense) benefit on currency exchange
               
 
rate movement of monetary assets and liabilities
 
$
 (5)
$
 14 
$
 (7)
$
 8 
Translation of non-U.S. deferred income tax balances
 
 (7)
 
 17 
 
 (7)
 
 10 
Income tax expense on inflation
   
 (1)
 
 (1)
 
 (2)
 
 (1)
 
Total impact on income taxes
   
 (13)
 
 30 
 
 (16)
 
 17 
After-tax (losses) gains on Mexican peso exchange rate
                 
 
instruments (included in Other Income, Net)
   
 ― 
 
 (16)
 
 6 
 
 (9)
Net impacts on Sempra Energy Condensed
                 
 
Consolidated Statements of Operations
 
$
 (13)
$
 14 
$
 (10)
$
 8 

 
Equity Earnings, Net of Income Tax
 
In the nine months ended September 30, 2012, equity earnings of unconsolidated subsidiaries, net of income tax, were $29 million compared to $45 million for the corresponding period in 2011. The change in the nine months ended September 30, 2012 was primarily due to lower earnings related to equity method investments in Chile and Peru, for entities that are now consolidated, offset by higher earnings from Sempra Mexico’s pipeline assets.
 
 
Earnings Attributable to Noncontrolling Interests
 
Sempra Energy Consolidated
 
Earnings attributable to noncontrolling interests decreased by $9 million for the three months ended September 30, 2012 due to lower earnings attributable to the noncontrolling interest at Otay Mesa VIE.
 
Earnings attributable to noncontrolling interests increased by $23 million for the nine months ended September 30, 2012 primarily due to:
 
§  
$17 million higher earnings attributable to noncontrolling interest in 2012 at Otay Mesa VIE; and
 
§  
$4 million higher earnings at Sempra South American Utilities primarily from noncontrolling interests at Luz del Sur in 2012.
 
For both the three months and the nine months ended September 30, 2012, the changes in earnings attributable to noncontrolling interest at Otay Mesa VIE were due to changes in operating income.
 
 
Earnings
 
We discuss variations in earnings by segment above in “Segment Results.”
 

 

CAPITAL RESOURCES AND LIQUIDITY
 

We expect our cash flows from operations to fund a substantial portion of our capital expenditures and dividends.  In addition, we may meet our cash requirements through the issuance of short-term and long-term debt and distributions from our equity method investments.
 
Our committed lines of credit provide liquidity and support commercial paper.  As we discuss in Note 6 of the Notes to Condensed Consolidated Financial Statements herein, in March 2012, Sempra Energy, Sempra Global (the holding company for our subsidiaries not subject to California utility regulation) and the California Utilities each entered into new five-year revolving credit facilities, expiring in 2017, which replaced the previous principal credit agreements that were scheduled to expire in 2014. At Sempra Energy and the California Utilities, the agreements are syndicated broadly among 24 different lenders and at Sempra Global, among 25 different lenders.  No single lender has greater than a 7-percent share in any agreement.
 
The table below shows the amount of available funds at September 30, 2012:
 

AVAILABLE FUNDS AT SEPTEMBER 30, 2012
(Dollars in millions)
   
Sempra Energy
   
   
Consolidated
SDG&E
SoCalGas
Unrestricted cash and cash equivalents
$
 530 
$
 22 
$
 257 
Available unused credit(1)
 
 3,539 
 
 656 
 
 658 
(1)
Borrowings on the shared line of credit at SDG&E and SoCalGas, discussed in Note 6 of the Notes to Condensed Consolidated Financial Statements herein, are limited to $658 million for each utility and $877 million in total. SDG&E’s available funds reflect commercial paper outstanding of $2 million, supported by the line.
 
 
Sempra Energy Consolidated
 
We believe that these available funds and cash flows from operations, distributions from equity method investments and security issuances, combined with current cash balances, will be adequate to:
 
§  
finance capital expenditures
 
§  
meet liquidity requirements
 
§  
fund shareholder dividends
 
§  
fund new business acquisitions or start-ups
 
§  
repay maturing long-term debt
 
In September 2012, Sempra Energy publicly offered and sold $500 million of 2.875-percent notes maturing in 2022, and SoCalGas publicly offered and sold $350 million of 3.75-percent first mortgage bonds maturing in 2042. In March 2012, Sempra Energy publicly offered and sold $600 million of 2.30-percent notes maturing in 2017, and SDG&E publicly offered and sold $250 million of 4.30-percent first mortgage bonds maturing in 2042. Sempra Energy and SDG&E issued long-term debt in 2011 in the aggregate principal amounts of $800 million and $600 million, respectively. Changing economic conditions could affect the availability and cost of both short-term and long-term financing. 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 & Power businesses before we would reduce funds necessary for the ongoing needs of the California Utilities, and secondarily our South American utilities. We continuously 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 three separate transactions during 2010 and one in early 2011, we and RBS sold substantially all of the businesses and assets of our joint-venture partnership that comprised our commodities-marketing businesses. Distributions from the partnership in 2011 were $623 million. The investment balance of $126 million at September 30, 2012 reflects remaining distributions expected to be received from the partnership as it is dissolved. The timing and amount of distributions may be impacted by the matters we discuss related to RBS Sempra Commodities in Note 10 of the Notes to Condensed Consolidated Financial Statements herein under “Other Litigation.”  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. We are providing transitional back-up guarantees, a few of which may continue for a prolonged period of time. Either RBS or JP Morgan Chase & Co., one of the buyers’ parties in the sales transactions, has fully indemnified us for any claims or losses in connection with the related transactions.
 
We provide additional information about RBS Sempra Commodities and the sales transactions and guarantees in Notes 4, 6 and 10 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 3, 4, 5 and 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
At September 30, 2012, our cash and cash equivalents held in foreign jurisdictions that are unavailable to fund domestic operations unless repatriated were approximately $240 million. We intend for funds associated with accumulated foreign earnings through September 30, 2012 to remain indefinitely in our foreign subsidiaries to fund their operations. We are currently considering a plan to repatriate future earnings from certain foreign operations beginning in 2013.
 
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, but may impact funding requirements for pension and other postretirement benefit plans. At the California Utilities, funding requirements are generally recoverable in rates.
 
We discuss our principal credit agreements more fully in Note 6 of the Notes to Condensed Consolidated Financial Statements herein.
 
 
California Utilities
 
SDG&E and SoCalGas expect that cash flows from operations and debt issuances will continue to be adequate to meet their working capital and capital expenditure requirements. In March 2011, Sempra Energy made a $200 million capital contribution to SDG&E.
 
SoCalGas declared and paid a $100 million common dividend in the second quarter of 2012 and a $50 million common dividend in the first quarter of both 2012 and 2011. SoCalGas also declared and paid a $100 million common dividend in October 2012. However, as a result of the increase in SoCalGas’ capital investment programs over the next few years, management expects that SoCalGas’ dividends on common stock will be reduced, when compared to the dividends on common stock declared on an annual basis historically, or temporarily suspended over the next few years to maintain SoCalGas’ authorized capital structure during the periods of high capital investments.
 
As a result of SDG&E’s large capital investment program over the past few years and the level of capital investment in 2012, SDG&E does not expect to pay common dividends to Sempra Energy in 2012. However, due to the completion of construction of the Sunrise Powerlink transmission power line in June 2012, SDG&E expects to be able to resume the declaration and payment of dividends on its common stock in 2013.
 
 
Sempra South American Utilities
 
We expect projects at Chilquinta Energía and Luz del Sur to be funded by external borrowings and funds internally generated by Chilquinta Energía and Luz del Sur.
 
 
Sempra Mexico
 
We expect projects in Mexico to be funded through a combination of funds internally generated by the Mexico businesses, project financing, raising other external capital, and partnering in joint ventures.
 
 
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, low-cost financing from the U.S. Department of Energy (DOE), U.S. Treasury Department cash grants, funds from the parent, and partnering in joint ventures. The Sempra Renewables projects have planned in-service dates ranging from 2012 to 2016. In November 2012, Sempra Renewables received $253 million in funding from the DOE related to Mesquite Solar 1, at an interest rate of 2.262 percent.
 
 
Sempra Natural Gas
 
We expect Sempra Natural Gas to require funding from the parent and external sources to fund projects and investments, including development and expansion of its natural gas storage projects.
 
Cash flows from operations at Sempra Natural Gas are expected to decrease substantially since its contract with the DWR expired in September 2011, due to less favorable pricing on any replacement contracts obtained, and the sale of its El Dorado natural gas generation plant to SDG&E in 2011.  Also, Sempra Natural Gas may not be able to replace all of the lost revenue due to decreased market demand. Sales to the DWR comprised six percent of Sempra Energy’s revenues in 2011.
 
Some of Sempra Natural Gas’ long-term power sale contracts contain collateral requirements which require its affiliates and/or the counterparty to post cash, guarantees or letters of credit to the other party for exposure in excess of established thresholds. Sempra Natural Gas may be required to provide collateral when market price movements adversely affect the counterparty’s cost of replacement energy supplies if Sempra Natural Gas fails to deliver the contracted amounts. We have neither collateral posted nor owed to counterparties at September 30, 2012 pursuant to these requirements.
 
Sempra Natural Gas plans to develop a natural gas liquefaction export facility at its Cameron LNG terminal. Sempra Natural Gas expects the majority of the project to be project-financed and the balance provided by project partners in a joint venture agreement.
 
 
CASH FLOWS FROM OPERATING ACTIVITIES
 

CASH PROVIDED BY OPERATING ACTIVITIES
(Dollars in millions)
 
2012 
2012 Change
2011 
Sempra Energy Consolidated
$
 1,688 
$
 45 
 3 
%
$
 1,643 
SDG&E
 
 770 
 
 (49)
 (6)
   
 819 
SoCalGas
 
 746 
 
 251 
 51 
   
 495 
 
Sempra Energy Consolidated
 
Cash provided by operating activities at Sempra Energy increased in 2012 primarily due to:
 
§  
$130 million settlement payment in 2011 related to energy crisis litigation;
 
§  
an $85 million payment received from Citizens Sunrise Transmission, LLC (Citizens) in July 2012, as discussed in Note 10 of the Notes to Condensed Consolidated Financial Statements herein;
 
§  
$67 million higher net income, adjusted for noncash items included in earnings, in 2012 compared to 2011;
 
§  
a $265 million decrease in accounts receivable in 2012 compared to a $218 million decrease in 2011; and
 
§  
a $52 million increase in inventory in 2012 compared to a $93 million increase in 2011; offset by
 
§  
$300 million of funds received in 2011 as compared to $190 million received in 2012 from wildfire litigation settlements; and
 
§  
an increase of $220 million in net undercollected regulatory balancing accounts in 2012 compared to a decrease of $18 million in net overcollected regulatory balancing accounts in 2011. 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 explanation for changes in regulatory balances at SDG&E and SoCalGas below.
 
 
SDG&E
 
Cash provided by operating activities at SDG&E decreased in 2012 primarily due to:
 
§  
$300 million of funds received in 2011 as compared to $190 million received in 2012 from wildfire litigation settlements; and
 
§  
an increase of $220 million in net undercollected regulatory balancing accounts in 2012 as compared to an increase of $84 million in net overcollected regulatory balancing accounts in 2011, as follows:
 
o  
the increase in net undercollected regulatory balancing accounts in 2012 was primarily due to:
 
§ undercollection of electric resource costs of $141 million and
 
§ undercollection of advanced metering infrastructure costs of $119 million;
 
o  
the increase in net overcollected regulatory balancing accounts in 2011 was primarily due to:
 
§ overcollection of electric resource costs of $41 million and
 
§ overcollection of advanced metering infrastructure costs of $21 million; offset by
 
§  
$189 million higher net income, adjusted for noncash items included in earnings, in 2012 compared to 2011;
 
§  
an $85 million payment received from Citizens in July 2012; and
 
§  
a $52 million increase in income taxes receivable in 2012 compared to a $130 million increase in 2011.
 
 
SoCalGas
 
Cash provided by operating activities at SoCalGas increased in 2012 primarily due to:
 
§  
a $286 million decrease in accounts receivable in 2012 compared to a $221 million decrease in 2011;
 
§  
a $16 million increase in inventory in 2012 compared to an $80 million increase in 2011;
 
§  
a $33 million decrease in accounts payable in 2012 compared to an $83 million decrease in 2011; and
 
§  
a decrease of $102 million in net overcollected regulatory balancing accounts in 2011, primarily due to:
 
o  
overcollection of California alternate rates for energy (CARE) program costs of $27 million,
 
o  
overcollection of direct assistance program costs of $27 million, and
 
o  
overcollection of self-generation program costs of $26 million; offset by
 
§  
$41 million lower net income, adjusted for noncash items included in earnings, in 2012 compared to 2011.
 
The table below shows the contributions to pension and other postretirement benefit plans for the nine months ended September 30, 2012.
 

   
Other
 
Pension
Postretirement
(Dollars in millions)
Benefits
Benefits
Sempra Energy Consolidated
$
 111 
$
 32 
SDG&E
 
 36 
 
 10 
SoCalGas
 
 45 
 
 19 
 
 
CASH FLOWS FROM INVESTING ACTIVITIES
 

CASH USED IN INVESTING ACTIVITIES
(Dollars in millions)
 
2012 
2012 Change
2011 
Sempra Energy Consolidated
$
 (2,576)
$
 272 
 12 
%
$
 (2,304)
SDG&E
 
 (992)
 
 (191)
 (16)
   
 (1,183)
SoCalGas
 
 (719)
 
 124 
 21 
   
 (595)
 
Sempra Energy Consolidated
 
Cash used in investing activities at Sempra Energy increased in 2012 primarily due to:
 
§  
a $210 million increase in capital expenditures;
 
§  
$374 million in distributions received from RBS Sempra Commodities in 2011;
 
§  
$249 million invested in Flat Ridge 2 in 2012; and
 
§  
$30 million invested in Auwahi Wind in 2012; offset by
 
§  
$611 million in cash used to fund Sempra South American Utilities’ purchase of South American entities in 2011.
 
 
SDG&E
 
Cash used in investing activities at SDG&E decreased in 2012 primarily due to a $164 million decrease in capital expenditures, primarily due to the completion of the Sunrise Powerlink project in June 2012.
 
 
SoCalGas
 
Cash used in investing activities at SoCalGas increased in 2012 due to:
 
§  
a $161 million higher increase in the amount advanced to Sempra Energy in 2012 as compared to 2011; offset by
 
§  
a $37 million decrease in capital expenditures.
 
 
ANNUAL CONSTRUCTION EXPENDITURES AND INVESTMENTS
 
The amounts and timing of capital expenditures are generally subject to approvals by the CPUC, the Federal Energy Regulatory Commission (FERC) and other regulatory bodies. However, in 2012, we expect to make annual capital expenditures and investments of approximately $3.3 billion. These expenditures include
 
§  
$1.9 billion at the California Utilities for capital projects and plant improvements ($1.2 billion at SDG&E and $670 million at SoCalGas)
 
§  
$1.4 billion at our other subsidiaries for capital projects in South America, renewable energy generation projects, and development of natural gas infrastructure
 
In 2012, the California Utilities expect their annual capital expenditures to include
 
§  
$550 million for improvements to SDG&E’s natural gas and electric distribution systems
 
§  
$200 million at SDG&E for the Sunrise Powerlink transmission line and substation expansions
 
§  
$300 million for improvements to SDG&E’s electric transmission systems
 
§  
$150 million for SDG&E’s electric generation plants and equipment
 
§  
$670 million at SoCalGas for improvements to distribution and transmission systems and storage facilities, and for advanced metering infrastructure
 
The California Utilities expect to finance these expenditures with cash flows from operations, cash on hand and debt issuances.
 
In July 2012, SDG&E received $85 million from Citizens Sunrise Transmission, LLC, a subsidiary of Citizens Energy Corporation, pursuant to an agreement to provide access to a segment of the Sunrise Powerlink transmission line. The expected 2012 capital expenditure above for the Sunrise Powerlink is net of Citizens’ July 2012 payment. We discuss this agreement further in Note 10 of the Notes to Condensed Consolidated Financial Statements herein.
 
For 2012, the expected annual capital expenditures and investments of $1.4 billion at our other subsidiaries, net of anticipated project financing and joint venture structures, include
 
 
Sempra South American Utilities
 
§  
approximately $100 million to $200 million for capital projects in South America, including approximately $70 million for the Santa Teresa hydroelectric power plant at Luz del Sur
 
 
Sempra Mexico
 
§  
approximately $170 million to $200 million for capital projects in Mexico, including approximately $150 million for the development of natural gas pipeline projects
 
 
Sempra Renewables
 
§  
approximately $400 million for investment in the first phase (150 MW) of Mesquite Solar, a solar project at our Mesquite Power plant near Arlington, Arizona
 
§  
approximately $350 million for investment in the second phase (150 MW) of Copper Mountain Solar, a solar project located near Boulder City, Nevada
 
§  
approximately $150 million for investment in other renewable energy projects
 
 
Sempra Natural Gas
 
§  
approximately $100 million for development of natural gas storage projects at Bay Gas Storage, LLC (Bay Gas) and Mississippi Hub, LLC (Mississippi Hub)
 
§  
approximately $50 million to $100 million for other natural gas projects
 
Our level of capital expenditures and investments in the next few years may vary substantially and will depend on the cost and availability of financing, regulatory approvals, changes in U.S. federal tax law and business opportunities providing desirable rates of return.  We intend to finance our capital expenditures in a manner that will maintain our strong investment-grade credit ratings and capital structure.
 
 
CASH FLOWS FROM FINANCING ACTIVITIES
 

CASH FLOWS FROM FINANCING ACTIVITIES
(Dollars in millions)
 
2012 
2012 Change
2011 
Sempra Energy Consolidated
$
 1,157 
$
 753 
 
$
 404 
SDG&E
 
 215 
 
 (325)
   
 540 
SoCalGas
 
 194 
 
 495 
   
 (301)
 

 
 
Sempra Energy Consolidated
 
Cash provided by financing activities at Sempra Energy increased in 2012 primarily due to:
 
§  
$769 million higher issuances of debt, primarily due to an increase in issuances of long-term debt of $614 million ($1,910 million in 2012, compared to $1,296 million in 2011);
 
§  
$158 million lower decrease in short-term debt; and
 
§  
$80 million for the redemption of subsidiary preferred stock in 2011; offset by
 
§  
$197 million higher debt payments, including $455 million higher payments of commercial paper with maturities greater than 90 days, offset by $258 million lower payments on long-term debt; and
 
§  
an $80 million increase in common dividends paid.
 
 
SDG&E
 
Cash provided by financing activities at SDG&E decreased in 2012 primarily due to:
 
§  
a $200 million capital contribution from Sempra Energy in 2011; and
 
§  
$99 million lower issuances of long-term debt.
 
 
SoCalGas
 
SoCalGas financing activities provided cash in 2012 compared to using cash in 2011, primarily due to:
 
§  
$348 million issuances of long-term debt in 2012; and
 
§  
$250 million payment of long-term debt in 2011; offset by
 
§  
a $100 million increase in common dividends paid.
 
 
COMMITMENTS
 
We discuss significant changes to contractual commitments at Sempra Energy, SDG&E and SoCalGas in Note 10 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 nine months of 2012.
 
Our credit ratings may affect the rates at which borrowings bear interest and of 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” in the Updated Annual Report.
 

 

FACTORS INFLUENCING FUTURE PERFORMANCE
 

 
SEMPRA ENERGY OVERVIEW
 
 
California Utilities
 
The California Utilities’ operations have historically provided relatively stable earnings and liquidity. However, for the next few years, SoCalGas intends to limit its common stock dividends to reinvest its earnings in significant capital projects.
 
The California Utilities’ performance will depend primarily on the ratemaking and regulatory process, environmental regulations, economic conditions, actions by the California legislature to address the state budget crisis and the changing energy marketplace. Their performance will also depend on the successful completion of capital projects that we discuss in various sections of this report and below. We discuss certain regulatory matters below and in Note 9 of the Notes to Condensed Consolidated Financial Statements herein and in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
SDG&E may also be significantly impacted by matters at San Onofre Nuclear Generating Station (SONGS). We discuss SONGS below and in Notes 9 and 10 of the Notes to Condensed Consolidated Financial Statements herein, in Notes 6, 14 and 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report, in Item 1A. Risk Factors in Part II herein, and in Risk Factors in our Form 10-K.
 
 
Sempra South American Utilities
 
In April 2011, Sempra South American Utilities increased its investment in two utilities in South America. As anticipated, the acquisition continues to be accretive to our earnings per share. However, in connection with our increased interests in Chilquinta Energía and Luz del Sur, Sempra Energy has $1 billion in goodwill on its Consolidated Balance Sheet as of September 30, 2012. Goodwill is subject to impairment testing, annually and under other potential circumstances, which may cause its fair value to vary if differing estimates and assumptions are used in the valuation techniques applied as indicated by changing market or other conditions.
 
We discuss the acquisition in Note 3 of the Notes to Consolidated Financial Statements in the Updated Annual Report. Sempra South American Utilities is also expected to provide earnings from construction projects when completed and other investments, but will require substantial funding for these investments.
 
In late 2011, Chilquinta Energía initiated the process to establish their distribution rates for the period from November 2012 to October 2016. Revenues at Chilquinta Energía are based on tariffs set by the National Energy Commission (Comisión Nacional de Energía, or CNE) every four years. We expect a final decision in the fourth quarter with the new distribution rates becoming effective in November 2012.
 
 
Sempra Renewables
 
Sempra Renewables is developing and investing in renewable energy generation projects that have long-term contracts with utilities. The renewable energy projects have planned in-service dates ranging from 2012 to 2016. These projects require construction financing which may come from a variety of sources including operating cash flow, project financing, low-cost financing procured under the DOE’s loan guaranty program, U.S. Treasury Department cash grants, funds from the parent, partnering in joint ventures and, potentially, other forms of equity sales. The varying costs of these alternative financing sources impact the projects’ returns.
 
Sempra Renewables expects that its Mehoopany Wind Farm and Flat Ridge 2 Wind Farm projects will be placed in service in 2012. If all or any portion of these projects are not placed in service during 2012, Sempra Renewables’ cash flows and earnings within the next 10 years will be adversely affected as wind projects must be placed in service during 2012 in order to claim production tax credits.
 
Sempra Renewables’ future performance and the demand for renewable energy is impacted by various market factors, most notably state mandated requirements to deliver a portion of total energy load from renewable energy sources. The rules governing these requirements are generally known as Renewables Portfolio Standards (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.
 
 
Sempra Natural Gas
 
Current energy market prices are significantly lower than those under Sempra Natural Gas’ former contract with the DWR, which ended on September 30, 2011 and had provided a significant portion of Sempra Natural Gas’ revenues. Revenues from Sempra Natural Gas’ generation plants are also expected to be lower due to a decline in market demand and the sale of Sempra Natural Gas’ El Dorado natural gas generation plant to SDG&E on October 1, 2011. Based on current market prices for electricity, contracts that Sempra Natural Gas enters into at its natural gas-fired plant to replace the DWR contract, if obtained, or merchant (daily) sales will provide substantially lower earnings. Because Sempra Mexico sells power from its Mexicali plant to Sempra Natural Gas, its earnings from generation have decreased and may remain at lower levels due to the completion of the DWR contract.
 
In June 2011, Sempra Natural Gas entered into a 25-year contract with various members of Southwest Public Power Resources Group (SPPR Group), an association of 40 not-for-profit utilities in Arizona and southern Nevada, for 240 MW of electricity. Under the terms of the agreement, Sempra Natural Gas will provide 21 participating SPPR Group members with firm, day-ahead dispatchable power delivered to the Palo Verde hub beginning in January 2015.
 
At Sempra Natural Gas, until there are firm LNG supply or capacity services contracts from third parties that would subscribe to 100 percent of the capacity of Sempra Natural Gas’ Cameron terminal, Sempra Natural Gas will seek to purchase short-term LNG supplies and sell short-term capacity, which may result in greater variability in revenues and earnings. Sempra Natural Gas is currently evaluating opportunities to utilize its assets to support the liquefaction and exportation of LNG. The objective is to obtain a long-term contract and fully utilize our existing infrastructure while minimizing our future additional capital investment. In January 2012, the DOE approved Cameron LNG’s application for an LNG export license to Free Trade Act countries. The authorization to export LNG to countries with which the U.S. does not have a Free Trade Agreement is pending review by the DOE.
 
In April and May 2012, Sempra Natural Gas signed commercial development agreements with Mitsubishi Corporation, Mitsui & Co., Ltd., and a subsidiary of GDF SUEZ S.A. (GDF SUEZ) to develop a natural gas liquefaction export facility at the Cameron LNG terminal. The completed liquefaction facility is expected to be comprised of three liquefaction trains with a total export capability of 12 million tonnes per annum (Mtpa) of LNG, or approximately 1.7 Bcf per day. Sempra Natural Gas expects to receive the required permits from the FERC and enter into a turnkey contract in 2013 for engineering and construction services for the project. Pending regulatory approvals and the achievement of other key milestones, construction on the project is planned to start in 2013 and begin operations in 2017. The liquefaction facility will utilize Cameron LNG’s existing facilities, including two marine berths, three LNG storage tanks, and vaporization capability for regasification services of 1.5 Bcf per day. The anticipated incremental investment in the three-train liquefaction project is estimated to be approximately $6 billion, excluding capitalized interest, the majority of which will be project-financed and the balance provided by the project partners in a joint-venture arrangement.
 
The commercial development agreements bind the parties to fund all development expenses, including design, permitting and engineering, as well as to negotiate 20-year tolling agreements, based on agreed-upon key terms outlined in the commercial development agreements. Each tolling agreement would be for 4 Mtpa.
 
As we discuss above under “Overview–Sempra Natural Gas,” Sempra Natural Gas, KMP and Phillips 66 jointly own REX. We have recorded noncash, after-tax impairment charges of $179 million and $60 million in the second and third quarters of 2012, respectively, to write down our investment in the partnership that operates REX. We discuss our investment in Rockies Express and the impairment in Notes 4 and 8 of the Notes to Condensed Consolidated Financial Statements herein.
 
 
Sempra Commodities
 
In three separate transactions in 2010 and one in early 2011, we and RBS sold substantially all of the businesses and assets of our commodities-marketing partnership. The investment balance of $126 million at September 30, 2012 reflects remaining distributions expected to be received from the partnership as it is dissolved. The timing and amount of distributions may be impacted by the matters we discuss related to RBS Sempra Commodities in Note 10 of the Notes to Condensed Consolidated Financial Statements herein under “Other Litigation.” 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. We provide additional information in Notes 4, 6 and 10 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 3, 4, 5 and 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
 
CALIFORNIA UTILITIES
 
 
Joint Matters
 
General Rate Case (GRC)
 
Both SDG&E and SoCalGas have their 2012 General Rate Case (GRC) applications pending at the CPUC. The California Utilities filed their initial applications for the 2012 GRC in December 2010 to establish their authorized 2012 revenue requirements and the ratemaking mechanisms by which those requirements will change on an annual basis over the subsequent three-year (2013-2015) period. In July 2011, SDG&E and SoCalGas filed revised applications and in February 2012, SDG&E and SoCalGas filed amendments to update the July 2011 filing. The 2012 amendments revised the requested increases to their authorized revenue requirements, as compared to their 2011 authorized revenues, to $235 million at SDG&E, of which $67 million is for the cost recovery of incremental wildfire insurance premiums, and to $268 million at SoCalGas. The Division of Ratepayer Advocates is recommending that the CPUC reduce the utilities’ revenue requirements in 2012 by approximately 5 percent compared to 2011.
 
Evidentiary hearings were completed in January 2012 and final briefs reflecting the results from these hearings were filed with the CPUC in May 2012. The current CPUC schedule indicates a final decision for the 2012 GRC, which will be made effective retroactive to January 1, 2012, by the end of 2012. However, until such time as a final decision for the 2012 GRC is issued, the California Utilities are recording revenues in 2012 based on levels authorized in 2011 plus, for SDG&E, consistent with the recent CPUC decisions for cost recovery for SDG&E’s incremental wildfire insurance premiums, an amount for the recovery of 2012 wildfire insurance premiums. The timing of the CPUC decision and the outcome from these proceedings will have an impact on the financial condition, operating results and cash flows of the California Utilities. If the CPUC’s final decision grants a significantly lower authorized revenue requirement, it could have a material adverse effect on the California Utilities’ cash flows, financial position and results of operations starting in 2012 as compared to 2011. Also, if the CPUC does not issue a final decision for the 2012 GRC by December 31, 2012, Sempra Energy and the California Utilities will not be able to record the retroactive impact to January 1, 2012 of the final decision in their 2012 financial results, but would reflect the impact in 2013 financial results in the period in which such final decision is issued. We provide additional information regarding the 2012 GRC in Note 9 of the Notes to Condensed Consolidated Financial Statements herein and in Note 14 of the Notes to the Consolidated Financial Statements in the Updated Annual Report.
 
Cost of Capital
 
SDG&E and SoCalGas filed separate applications with the CPUC in April 2012 to update their cost of capital effective January 1, 2013. SDG&E proposes to adjust its authorized capital structure by increasing the amount of its common equity from 49.0 percent to 52.0 percent. SDG&E also proposes to lower its authorized return on equity (ROE) from 11.1 percent to 11.0 percent and, as reflected in its supplemental filing with the CPUC in October 2012, to lower its authorized return on rate base (ROR) from 8.40 percent to 8.15 percent. SoCalGas proposes to adjust its authorized capital structure by increasing the amount of its common equity from 48.0 percent to 52.0 percent. SoCalGas proposes to increase its authorized ROE from 10.82 percent to 10.9 percent and, as reflected in its supplemental filing with the CPUC in October 2012, to lower its authorized ROR from 8.68 percent to 8.44 percent.
 
The proposed change in SDG&E’s capital structure and resulting ROR would result in a decrease in its 2013 authorized revenue of approximately $9.1 million if approved by the CPUC. The proposed change in SoCalGas’ capital structure and resulting ROR would result in a decrease in its 2013 authorized revenue of approximately $0.8 million if approved by the CPUC.
 
If the CPUC were to approve a capital structure in the cost of capital proceedings that resulted in either SDG&E’s or SoCalGas’ ROR being significantly lower than what was proposed, it could materially adversely affect the respective company’s cash flows, financial position and results of operations starting in 2013.
 
SDG&E proposes to continue its currently approved cost of capital adjustment mechanism, which uses a utility bond benchmark. SoCalGas proposes to switch from its current cost of capital adjustment mechanism, which is based on U.S. Treasury Bonds, to a mechanism which uses a utility bond benchmark similar to SDG&E, Southern California Edison (Edison) and Pacific Gas and Electric Company (PG&E). We provide more information about the cost of capital proceedings in Note 9 of the Notes to Condensed Consolidated Financial Statements herein.
 
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 its natural gas pipeline operations and investments. In August 2011, SoCalGas, SDG&E, PG&E and Southwest Gas filed implementation plans with the CPUC to test or replace all natural gas transmission pipelines that have not been pressure tested, as we discuss in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report. The California Utilities are currently estimating that the total cost for Phase 1 of the two-phase plan is $3.1 billion over a 10-year period. 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 are outside the scope of the 2012 GRC proceedings discussed above. If the CPUC were to decide that the incremental capital investment not be considered as incremental rate base outside the GRC process or that this incremental capital investment earn an ROR lower than what is otherwise authorized, it could materially adversely affect the respective company’s cash flows, financial position and results of operations upon commencement of this program. We provide additional information in Note 9 of the Notes to Condensed Consolidated Financial Statements herein.
 
 
SDG&E Matters
 
2007 Wildfire Litigation
 
In regard to the 2007 wildfire litigation, SDG&E’s settlement of claims and the estimate of outstanding claims and legal fees is approximately $2.3 billion, which is in excess of the $1.1 billion of liability insurance coverage and the approximately $824 million received or receivable from third parties. However, SDG&E has concluded that it is probable that it will be permitted to recover from its utility customers substantially all reasonably incurred costs of resolving wildfire claims in excess of its liability insurance coverage and amounts recovered from other responsible parties. Consequently, Sempra Energy and SDG&E expect no significant earnings impact from the resolution of the remaining wildfire claims. As of September 30, 2012, Sempra Energy’s and SDG&E’s Condensed Consolidated Balance Sheets reflect $326 million in Regulatory Assets Arising From Wildfire Litigation Costs, including $292 million related to CPUC operations, for costs incurred and the estimated settlement of pending claims. However, SDG&E’s cash flow may be materially adversely affected by timing differences between the resolution of claims and recoveries from utility customers, which may extend over a number of years. In addition, recovery from customers will require future regulatory actions, and a failure to obtain substantial or full recovery, 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.
 
SDG&E will continue to gather information to evaluate and assess the remaining wildfire claims and the likelihood, amount and timing of recoveries from utility customers and will make appropriate adjustments to wildfire reserves and the related regulatory assets as additional information becomes available.
 
Should SDG&E conclude that the amount of recovery of excess wildfire costs from utility customers is no longer reasonably estimable or that recovery is no longer probable, at that time SDG&E will record a charge against earnings. In addition, in periods following any such conclusion by SDG&E that recovery is no longer probable, Sempra Energy’s and SDG&E’s earnings will be adversely impacted by increases in the estimated costs to settle pending wildfire claims.
 
We provide additional information concerning these matters in Notes 9 and 10 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
SONGS
 
As a result of the extended outage at SONGS, the CPUC has issued an Order Instituting Investigation (OII) to determine whether SDG&E should remove from customer rates some or all revenue requirement associated with the portion of the facility that is out of service. This OII will consolidate all SONGS issues from related regulatory proceedings and consider the appropriate cost recovery for SONGS, including among other costs, the cost of the steam generator replacement project, replacement power costs, capital expenditures, operation and maintenance costs and seismic study costs. The OII requires that all costs related to SONGS incurred since January 1, 2012 be tracked in a separate memorandum account, with all revenues collected in recovery of such costs subject to refund, and will address the extent to which such revenues, if any, will be required to be refunded to customers.
 
Currently, SDG&E is collecting in customer rates its share of the operating costs, depreciation and return on its investment in SONGS. For the nine-month period ended September 30, 2012, SDG&E has recognized (and collected through customer rates) an estimated $153 million of revenue associated with its investment in SONGS and operating costs. At September 30, 2012, SDG&E’s weighted average rate base investment in SONGS was approximately $220 million and its net book investment, including construction work in progress and nuclear fuel was $485 million. If the CPUC were to order SDG&E to remove all or most of the authorized revenue requirement associated with SONGS from customer rates, refund all or most of the revenue from its investment in SONGS charged to customers since January 1, 2012, or remove all or most of SDG&E’s rate base investment in SONGS from its rate base, it would likely have a material adverse effect on Sempra Energy’s and SDG&E’s financial condition, cash flows and results of operations.
 
We provide additional information concerning SONGS in Notes 9 and 10 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 6, 14 and 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
 
OTHER SEMPRA ENERGY MATTERS
 
We discuss additional potential and expected impacts of the 2010 Tax Act on our income tax expense, earnings and cash flows in “Results of Operations – Changes in Revenues, Costs and Earnings – Income Taxes” above.
 
We may be further impacted by depressed and rapidly changing economic conditions. Moreover, the dollar has fluctuated significantly compared to some foreign currencies, especially in Mexico and South America where we have significant operations. We discuss foreign currency rate risk further under “Market Risk – Foreign Currency Rate Risk” in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Updated Annual Report. North American natural gas prices, which affect profitability at Sempra Renewables and Sempra Natural Gas, are currently significantly below Asian and European prices. These factors could, if they remain unchanged, adversely affect profitability. However, management expects that future export capability at Sempra Natural Gas’ Cameron LNG facility would benefit from lower gas prices in North America compared to other regions.
 
We discuss additional matters that could affect our future performance in Notes 9 and 10 of the Notes to Condensed Consolidated Financial Statements herein and in Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
 
FINANCIAL DERIVATIVES REFORMS
 
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 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 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 of our hedging programs, because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to mitigate.
 
 
LITIGATION
 
We describe legal proceedings which could adversely affect our future performance in Note 10 of the Notes to Condensed Consolidated Financial Statements herein.
 
 
CALIFORNIA UTILITIES – INDUSTRY DEVELOPMENTS AND CAPITAL PROJECTS
 
We describe capital projects, electric and natural gas regulation and rates, and other pending proceedings and investigations that affect our business in Note 9 of the Notes to Condensed Consolidated Financial Statements herein and in Note 14 of the Notes to Consolidated Financial Statements in the Updated Annual Report.
 
 
SEMPRA INTERNATIONAL AND SEMPRA U.S. GAS & POWER INVESTMENTS
 
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 “Capital Resources and Liquidity” and “Factors Influencing Future Performance” in the Updated Annual Report.
 
 
Sempra South American Utilities
 
Santa Teresa
 
In May 2011, groundbreaking took place for Santa Teresa, a project at Luz del Sur to build a 98-MW hydroelectric power plant in Peru’s Cusco region. It is planned to be completed in 2014.
 
Transmission Projects
 
In May 2012, Chilquinta Energía, in a joint venture with Sociedad Austral de Electricidad Sociedad Anonima (SAESA), was awarded two 220-kilovolt (kV) transmission lines in Chile. The transmission lines will extend 150 miles, and we estimate it will cost approximately $160 million and be completed in 2017.
 
 
Sempra Mexico
 
Energía Sierra Juárez
 
In April 2011, SDG&E entered into a 20-year contract for up to 156 MW of renewable power supplied from the first phase of Sempra Mexico’s Energía Sierra Juárez wind project in Baja California, Mexico. The contract was approved by the CPUC in March 2012 and by the FERC in July 2012. We expect construction on the project to begin in 2013, and the project to be fully operational in 2014.
 
Sempra Mexico intends to develop the project within the framework of a joint venture, and is working on an agreement for the sale of a 50-percent partnership interest in the current phase of the project to BP Wind Energy.
 
Pipeline Projects
 
In October 2012, Sempra Mexico was awarded two contracts by CFE to build and operate an approximately 500-mile pipeline network to transport natural gas from the US-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 and be completed by the second half of 2016. The capacity is fully contracted by CFE under two 25-year contracts denominated in U.S. dollars. Our ability to secure rights of way and construct the lines within budgeted amounts will impact future performance.
 
 
Sempra Renewables
 
Copper Mountain Solar
 
Copper Mountain Solar is a photovoltaic generation facility operated and under development by Sempra Renewables in Boulder City, Nevada. If fully developed, the project will be capable of producing up to approximately 450 MW of solar power; it is being developed in multiple phases as contracted. Copper Mountain Solar is comprised of two separate projects. Copper Mountain Solar 1 is a 58-MW photovoltaic generation facility currently in operation, and now includes the 10-MW facility previously referred to as El Dorado Solar.
 
Copper Mountain Solar 2 (CMS 2) began construction in December 2011 and will total 150 MW when completed. CMS 2 is divided into two phases, with the first phase of 92 MW planned to be placed in service by the end of 2012 and the remaining 58 MW planned to be placed in service in 2015. PG&E has contracted for all of the solar power at CMS 2 for 25 years.
 
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. Construction on the first phase (Mesquite Solar 1) of 150 MW began in June 2011 and is expected to be placed in service by the end of 2012. In December 2011, Mesquite Solar 1 began delivering 42 MW of electricity to the grid. At September 30, 2012, the project is at 126 MW of capacity. PG&E has contracted for all of the solar power at Mesquite Solar 1 for 20 years.
 
Auwahi Wind
 
The Auwahi Wind project, in the southeastern region of Maui, is a joint venture with BP Wind Energy. The project has a 20-year contract with Maui Electric Company to provide 21 MW of wind energy. Significant project costs were incurred during late 2011, and physical construction began on the project in March 2012. We expect the project to be placed in service by the end of 2012.
 
Mehoopany Wind Farm
 
In December 2011, Sempra Renewables entered into a joint venture with BP Wind Energy to develop the Mehoopany Wind Farm in Wyoming County, Pennsylvania, which is expected to generate up to 141 MW of energy. The power output from the wind farm has been sold under 20-year contracts to Old Dominion Electric Cooperative and Southern Maryland Electric Cooperative Inc. The wind farm is in full construction and we expect the project to be placed in service by the end of 2012.
 
Flat Ridge 2 Wind Farm
 
In December 2011, Sempra Renewables entered into a joint venture with BP Wind Energy to develop the Flat Ridge 2 Wind Farm near Wichita, Kansas, which is expected to generate up to 419 MW of energy. The power output from the wind farm has been sold under three contracts for 20 to 25 year terms, including contracts with Associated Electric Cooperative, Inc. and Southwestern Electric Power Company, and construction began in April 2012. In June 2012, Sempra Renewables entered into an agreement with BP Wind Energy for a 51-MW expansion of Flat Ridge 2, the power output of which has been sold under a purchase power agreement with Arkansas Electric Cooperative approved by the Rural Utilities Service in April 2012. We expect both the original 419-MW and 51-MW expansion of Flat Ridge 2 to be placed in service by the end of 2012.
 
 
Sempra Natural Gas
 
Natural Gas Storage
 
Currently, Sempra Natural Gas has 30 Bcf of operational working natural gas storage capacity. We are currently developing another 13 Bcf of capacity with planned in-service dates through 2013 and may, over the long term, develop as much as 76 Bcf of total storage capacity.
 
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, previously referred to as Liberty natural gas storage expansion, a salt cavern development project in Cameron Parish, Louisiana. Sempra Natural Gas owns 75 percent of the project and ProLiance Transportation LLC owns the remaining 25 percent. The project’s location provides access to several LNG facilities in the area.
 

Cameron LNG
 
In April and May 2012, Sempra Natural Gas signed commercial development agreements with Mitsubishi Corporation, Mitsui & Co., Ltd., and GDF SUEZ to develop a natural gas liquefaction export facility at the site of its Cameron LNG terminal in Hackberry, Louisiana. We discuss these agreements above in “Factors Influencing Future Performance Sempra Energy Overview.”
 


 

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 Updated Annual Report.
 
We describe our significant accounting policies in Note 1 of the Notes to Consolidated Financial Statements in the Updated Annual Report. We follow the same accounting policies for interim reporting purposes.
 

 

NEW ACCOUNTING STANDARDS
 

We discuss the relevant pronouncements that have recently 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 Discussion and Analysis of Financial Condition and Results of Operations" in the Updated Annual Report.
 
 
INTEREST RATE RISK
 
The table below shows the nominal amount and the one-year VaR for long-term debt, excluding commercial paper classified as long-term debt, capital lease obligations and interest rate swaps, and before reductions for unamortized discount, at September 30, 2012 and December 31, 2011:
 

 
Sempra Energy
       
 
Consolidated
SDG&E
SoCalGas
 
Nominal
One-Year
Nominal
One-Year
Nominal
One-Year
(Dollars in millions)
Debt
VaR(1)
Debt
VaR(1)
Debt
VaR(1)
At September 30, 2012:
                       
    California Utilities fixed-rate
$
 5,452 
$
 830 
$
 3,790 
$
 622 
$
 1,662 
$
 208 
    California Utilities variable-rate
 
 347 
 
 18 
 
 347 
 
 18 
 
 ― 
 
 ― 
    All other, fixed-rate and variable-rate
 
 5,906 
 
 387 
 
 ― 
 
 ― 
 
 ― 
 
 ― 
At December 31, 2011:
                       
    California Utilities fixed-rate
$
 4,617 
$
 782 
$
 3,304 
$
 623 
$
 1,313 
$
 159 
    California Utilities variable-rate
 
 591 
 
 25 
 
 591 
 
 25 
 
 ― 
 
 ― 
    All other, fixed-rate and variable-rate
 
 4,602 
 
 377 
 
 ― 
 
 ― 
 
 ― 
 
 ― 
(1) After the effects of interest rate swaps.

At September 30, 2012, the net notional amount of interest rate swap transactions ranged from $6 million to $369 million at Sempra Energy (ranges relate to the tenor of the various hedging instruments).  We provide additional information about interest rate swap transactions in Note 7 of the Notes to Condensed Consolidated Financial Statements herein.
 

 
FOREIGN CURRENCY RATE RISK
 
We discuss our foreign currency rate risk in detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the Updated Annual Report. At September 30, 2012, there were no significant changes to our exposure to foreign currency rate risk since December 31, 2011.

 
 

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 Officer and Chief 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 Officers and Chief 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 September 30, 2012, the end of the period covered by this report. Based on these evaluations, the Chief Executive Officers and Chief 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
 
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.
 
 
 
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 and 10 of the Notes to Condensed Consolidated Financial Statements herein and Notes 14 and 15 of the Notes to Consolidated Financial Statements in the Updated Annual Report, or 2) referred to in “Management's Discussion and Analysis of Financial Condition and Results of Operations” herein and in the Updated Annual Report.
 

 

ITEM 1A. RISK FACTORS
 

The following supplements the risk factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2011.

Recovery of 2007 Wildfire Litigation Costs

SDG&E is subject to numerous lawsuits arising out of the San Diego County wildfires in 2007. To date, SDG&E’s costs to settle these claims and its estimated future settlement costs and defense costs have exceeded its $1.1 billion of liability insurance coverage and the approximately $824 million received or receivable from other responsible parties. SDG&E is seeking to recover from its utility customers substantially all of its reasonably incurred costs of resolving 2007 wildfire claims in excess of its liability insurance coverage and amounts recovered from other responsible parties. SDG&E has concluded that it is probable that SDG&E will be permitted to recover these excess costs from its utility customers, and at September 30, 2012, Sempra Energy’s and SDG&E’s Condensed Consolidated Balance Sheets include assets of $326 million in Regulatory Assets Arising From Wildfire Litigation Costs, of which $292 million is related to CPUC operations, with respect to these excess costs. However, recovery of these amounts from utility customers will require future regulatory actions.
 
In August 2009, SDG&E and SoCalGas filed an application with the CPUC proposing a new mechanism for the future recovery of all wildfire-related expenses for claims, litigation expenses and insurance premiums that are in excess of amounts authorized by the CPUC for recovery in distribution rates. In October 2012, the Administrative Law Judge’s draft decision (the Proposed Decision or PD) and the Assigned Commissioner’s alternate draft decision (the Alternate Decision or AD) in this proceeding were issued. The PD rejects SDG&E’s and SoCalGas’ request for a new balancing account and cost recovery mechanism. The AD approves SDG&E’s and SoCalGas’ request for a new balancing account and cost recovery mechanism, but only for wildfire events that occur after July 2010 and only for wildfires for which the utility is found not to be at fault. The AD also directs SDG&E to remove any amounts recorded in the balancing account associated with the 2007 wildfires. Following the issuance of the PD and the AD and consistent with CPUC rules and procedures, SDG&E requested an ex parte meeting with the Assigned Commissioner and staff. The request was granted, and the ex parte meeting was held on October 29, 2012. At the meeting, SDG&E provided information to the Assigned Commissioner addressing key issues from the AD that SDG&E believes contradict prior CPUC rulings and decisions. While there can be no assurance that the Assigned Commissioner will amend the AD, given the relevant regulatory and statutory standards and the issues discussed at the ex parte meeting, SDG&E has concluded that it remains probable that SDG&E will be permitted to recover from ratepayers substantially all of its reasonably incurred costs associated with the 2007 wildfires that exceed the amounts recovered from its insurance coverage and other responsible third parties. For a description of this proceeding and information about 2007 wildfire litigation costs and their recovery, see Notes 9 and 10 of the Notes to Condensed Consolidated Financial Statements included in Part I—Item 1 of this report.
 
SDG&E will continue to assess the recovery of these excess wildfire costs from ratepayers. Should SDG&E conclude that the amount of the recovery from ratepayers is no longer reasonably estimable or that recovery 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 such recovery was no longer probable or reasonably estimable as of September 30, 2012, the resulting after-tax charge against earnings would have been approximately $175 million. In addition, in periods following any such conclusion, SDG&E’s earnings will be adversely impacted by increases in the estimated costs to settle pending wildfire claims.
 
As noted above, recovery from customers will require future regulatory actions, and a failure to obtain all or a significant portion of the expected recovery, or a conclusion that recovery from ratepayers is no longer probable, would likely have a material adverse effect on Sempra Energy’s and SDG&E’s cash flows, financial condition and results of operations. In addition, if recovery is permitted, Sempra Energy’s and SDG&E’s cash flows may be materially adversely affected due to the timing differences between resolution of claims and the recovery from utility customers, which may extend over a number of years.
 

Ongoing regulatory and maintenance issues at San Onofre Nuclear Generating Station (SONGS)

SDG&E has a 20-percent ownership interest in SONGS, a 2,150-MW nuclear generating facility near San Clemente, California operated by Southern California Edison. As discussed in Note 9 of the Notes to Condensed Consolidated Financial Statements herein, SONGS’s Units 2 and 3 are offline. The timing of the restart of either of these Units is dependent upon approval by the Nuclear Regulatory Commission, which could result in substantial additional expenditures that may not be recoverable, in whole or in part, in customer rates. If one or both of these Units were to be offline for more than nine consecutive months (November 2012 for Unit 3 and December 2012 for Unit 2), the CPUC will be notified of such fact. In November 2012, the CPUC issued an Order Instituting Investigation (OII) into the SONGS outage to determine whether SDG&E should remove from customer rates some or all revenue requirement associated with the portion of the facility that is out of service. This OII will consolidate all SONGS issues from related regulatory proceedings and consider the appropriate cost recovery for SONGS, including among other costs, the cost of the steam generator replacement project, replacement power costs, capital expenditures, operation and maintenance costs and seismic study costs. The OII requires all costs related to SONGS incurred since January 1, 2012 be tracked in a separate memorandum account, with all revenues collected in recovery of such costs subject to refund, and will address the extent to which such revenues, if any, will be required to be refunded to customers.  Any extended shut down of one or both of these Units and the costs required to bring those Units back online could materially adversely affect SDG&E’s and Sempra Energy’s businesses, results of operations, cash flows, and financial condition.  In addition, any decision by the CPUC to require SDG&E to refund some or all of the revenues collected in recovery of the costs described above could materially adversely affect SDG&E’s and Sempra Energy’s businesses, results of operations, cash flows, and financial condition.
 


 

ITEM 6. EXHIBITS
 

The following exhibits relate to each registrant as indicated.
 
 
 
EXHIBIT 3 -- BYLAWS AND ARTICLES OF INCORPORATION
 
 
 
Sempra Energy
 
3.1  
Amended Bylaws of Sempra Energy effective September 13, 2012 (Sempra Energy Form 8-K filed on September 17, 2012, Exhibit 3(ii)).
 
 
 
EXHIBIT 10 -- MATERIAL CONTRACTS
 
 
 
Sempra Energy / Southern California Gas Company
 
10.1  
Severance Pay Agreement between Sempra Energy and Dennis Arriola.
 
 
 
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  
Statement of Sempra Energy’s Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
 
   
31.2  
Statement 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
 
31.3  
Statement 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.
 
   
31.4  
Statement 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
 
31.5  
Statement of Southern California Gas Company’s Chief Executive Officer pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
 
   
31.6  
Statement 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
 
32.1  
Statement of Sempra Energy’s Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.
 
   
32.2  
Statement of Sempra Energy’s Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
 
 
 
San Diego Gas & Electric Company
 
32.3  
Statement of San Diego Gas & Electric Company’s Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.
 
   
32.4  
Statement of San Diego Gas & Electric Company’s Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
 
 
 
Southern California Gas Company
 
32.5  
Statement of Southern California Gas Company’s Chief Executive Officer pursuant to 18 U.S.C. Sec. 1350.
 
   
32.6  
Statement of Southern California Gas Company’s Chief Financial Officer pursuant to 18 U.S.C. Sec. 1350.
 
 
 
EXHIBIT 101 -- INTERACTIVE DATA FILE
 
   
101.INS  
XBRL Instance Document
   
101.SCH  
XBRL Taxonomy Extension Schema Document
   
101.CAL  
XBRL Taxonomy Extension Calculation Linkbase Document
   
101.DEF  
XBRL Taxonomy Extension Definition Linkbase Document
   
101.LAB  
XBRL Taxonomy Extension Label Linkbase Document
   
101.PRE  
XBRL Taxonomy Extension Presentation Linkbase Document
 
 
 
 
 
 
 
 
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: November 6, 2012
By:  /s/ Trevor I. Mihalik
 
Trevor I. Mihalik
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: November 6, 2012
By:  /s/ Robert M. Schlax
 
Robert M. Schlax
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: November 6, 2012
By:  /s/ Robert M. Schlax
 
Robert M. Schlax
Vice President, Controller, Chief Financial Officer and Chief Accounting Officer

Exhibit 10.1

SEMPRA ENERGY
SEVERANCE PAY AGREEMENT

THIS AGREEMENT (this “Agreement”), dated as of August 4, 2012 (the “Effective Date”), is made by and between SEMPRA ENERGY, a California corporation (“Sempra Energy”), and Dennis Arriola (the “Executive”).

WHEREAS, the  Executive is currently employed by Sempra Energy or a direct or indirect subsidiary of Sempra Energy (Sempra Energy and its subsidiaries are hereinafter collectively referred to as the “Company”) as President & Chief Operating Officer for Southern California Gas Company; and

WHEREAS, Sempra Energy and the Executive desire to enter into this Agreement; and

WHEREAS, the Board of Directors of Sempra Energy (the “Board”) has authorized this Agreement.

NOW, THEREFORE, in consideration of the premises and mutual covenants herein contained, the Company and the  Executive hereby agree as follows:

Section 1.

Definitions.  For purposes of this Agreement, the following capitalized terms have the meanings set forth below:

Accounting Firm” has the meaning assigned thereto in Section 9(b) hereof.

Act” has the meaning assigned thereto in Section 2 hereof.

Additional Post-Change in Control Severance Payment” has the meaning assigned thereto in Section 6(a) hereof.

Affiliate” has the meaning set forth in Rule 12b-2 promulgated under the Exchange Act.

Annual Base Salary” means the  Executive’s annual base salary from the Company.

Asset Purchaser” has the meaning assigned thereto in Section 16(e).

Asset Sale” has the meaning assigned thereto in Section 16(e).

Average Annual Bonus” means the average of the annual bonuses from the Company earned by the Executive with respect to the three (3) fiscal years of the Company immediately preceding the Date of Termination (the “Bonus Fiscal Years”); provided, however, that, if the Executive was employed by the Company during all or any portion of one or two of the Bonus Fiscal Years (but not three of the Bonus Fiscal Years), “Average Annual Bonus” means the average of the annual bonuses (if any) from the Company earned by the Executive with respect to the Bonus Fiscal Years during all or any portion of which the Executive was employed by the Company; and, provided, further, that, if the Executive was not employed by the Company during all or any portion of any of the Bonus Fiscal Years, “Average Annual Bonus” means zero.

Beneficial Owner” has the meaning set forth in Rule 13d-3 promulgated under the Exchange Act.

Cause” means:  

(a)

Prior to a Change in Control, (i) the willful failure by the  Executive to substantially perform the  Executive’s duties with the Company (other than any such failure resulting from the  Executive’s incapacity due to physical or mental illness, (ii) the grossly negligent performance of such obligations referenced in clause (i) of this definition, (iii) the  Executive’s gross insubordination; and/or (iv) the  Executive’s commission of one or more acts of moral turpitude that constitute a violation of applicable law (including but not limited to a felony) which have or result in an adverse effect on the Company, monetarily or otherwise, or one or more significant acts of dishonesty.  For purposes of clause (i) of this subsection (a), no act, or failure to act, on the  Executive’s part shall be deemed “willful” unless done, or omitted to be done, by the  Executive not in good faith and without reasonable belief that the  Executive’s act, or failure to act, was in the best interests of the Company.  

(b)

From and after a Change in Control, (i) the willful and continued failure by the  Executive to substantially perform the  Executive’s duties with the Company (other than any such failure resulting from the  Executive’s incapacity due to physical or mental illness or any such actual or anticipated failure after the issuance of a Notice of Termination for Good Reason by the  Executive pursuant to Section 3 hereof) and/or (ii) the  Executive’s commission of one or more acts of moral turpitude that constitute a violation of applicable law (including but not limited to a felony) which have or result in an adverse effect on the Company, monetarily or otherwise, or one or more significant acts of dishonesty.  For purposes of clause (i) of this subsection (b), no act, or failure to act, on the  Executive’s part shall be deemed “willful” unless done, or omitted to be done, by the  Executive not in good faith and without reasonable belief that the  Executive’s act, or failure to act, was in the best interests of the Company.  Notwithstanding the foregoing, the  Executive shall not be deemed terminated for Cause pursuant to clause (i) of this subsection (b) unless and until the  Executive shall have been provided with reasonable notice of and, if possible, a reasonable opportunity to cure the facts and circumstances claimed to provide a basis for termination of the  Executive’s employment for Cause.

Change in Control” shall be deemed to have occurred on the date that a change in the ownership of Sempra Energy, a change in the effective control of Sempra Energy, or a change in the ownership of a substantial portion of assets of Sempra Energy occurs (each, as defined in subsection (a) below), except as otherwise provided in subsections (b), (c) and (d) below:

(a)

(i)

a “change in the ownership of Sempra Energy” occurs on the date that any one person, or more than one person acting as a group, acquires ownership of stock of Sempra Energy that, together with stock held by such person or group, constitutes more than fifty percent (50%) of the total fair market value or total voting power of the stock of Sempra Energy,

(ii)

a “change in the effective control of Sempra Energy” occurs only on either of the following dates:

(A)

the date any one person, or more than one person acting as a group, acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by such person or persons) ownership of stock of Sempra Energy possessing thirty percent (30%) or more of the total voting power of the stock of Sempra Energy, or

(B)

the date a majority of the members of the Board is replaced during any twelve (12) month period by directors whose appointment or election is not endorsed by a majority of the members of the Board before the date of appointment or election, and

(iii)

a “change in the ownership of a substantial portion of assets of Sempra Energy” occurs on the date any one person, or more than one person acting as a group, acquires (or has acquired during the twelve (12) month period ending on the date of the most recent acquisition by such person or persons) assets from Sempra Energy that have a total gross fair market value equal to or more than eighty-five percent (85%) of the total gross fair market value of all of the assets of Sempra Energy immediately before such acquisition or acquisitions.

(b)

A “change in the ownership of Sempra Energy” or “a change in the effective control of Sempra Energy” shall not occur under clause (a)(i) or (a)(ii) by reason of any of the following:

(i)

an acquisition of ownership of stock of Sempra Energy directly from Sempra Energy or its Affiliates other than in connection with the acquisition by Sempra Energy or its Affiliates of a business,

(ii)

a merger or consolidation which would result in the voting securities of Sempra Energy outstanding immediately prior to such merger or consolidation continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof), in combination with the ownership of any trustee or other fiduciary holding securities under an employee benefit plan of the Company, at least sixty percent (60%) of the combined voting power of the securities of Sempra Energy or such surviving entity or any parent thereof outstanding immediately after such merger or consolidation, or

(iii)

a merger or consolidation effected to implement a recapitalization of Sempra Energy (or similar transaction) in which no Person is or becomes the Beneficial Owner, directly or indirectly, of securities of Sempra Energy (not including the securities beneficially owned by such Person any securities acquired directly from Sempra Energy or its Affiliates other than in connection with the acquisition by Sempra Energy or its Affiliates of a business) representing twenty percent (20%) or more of the combined voting power of Sempra Energy’s then outstanding securities.

(c)

A “change in the ownership of a substantial portion of assets of Sempra Energy” shall not occur under clause (a)(iii) by reason of a sale or disposition by Sempra Energy of the assets of Sempra Energy to an entity, at least sixty percent (60%) of the combined voting power of the voting securities of which are owned by shareholders of Sempra Energy in substantially the same proportions as their ownership of Sempra Energy immediately prior to such sale.

(d)

This definition of “Change in Control” shall be limited to the definition of a “change in control event” relating to Sempra Energy under Treasury Regulation Section 1.409A-3(i)(5).  A “Change in Control” shall only occur if there is a “change in control event” relating to Sempra Energy under Treasury Regulation Section 1.409A-3(i)(5) with respect to the Executive.

Change in Control Date” means the date on which a Change in Control occurs.

Code” means the Internal Revenue Code of 1986, as amended.

Compensation Committee” means the compensation committee of the Board.

Consulting Period” has the meaning assigned thereto in Section 14(e) hereof.

Date of Termination” has the meaning assigned thereto in Section 3(b) hereof.

Deferred Compensation Plan” has the meaning assigned thereto in Section 5(f) hereof.

Disability” has the meaning set forth in the Company’s long-term disability plan or its successor; provided, however, that the Board may not terminate the  Executive’s employment hereunder by reason of Disability unless (i) at the time of such termination there is no reasonable expectation that the  Executive will return to work within the next ninety (90) day period and (ii) such termination is permitted by all applicable disability laws.  

Exchange Act” means the Securities Exchange Act of 1934, as amended, and the applicable rulings and regulations thereunder.

Excise Tax” has the meaning assigned thereto in Section 9(a) hereof.

Good Reason” means:

(a)

Prior to a Change in Control, the occurrence of any of the following without the prior written consent of the  Executive, unless such act or failure to act is corrected by the Company prior to the Date of Termination specified in the Notice of Termination (as required under Section 3 hereof):

(i)

the assignment to the  Executive of any duties materially inconsistent with the range of duties and responsibilities appropriate to a senior Executive within the Company (such range determined by reference to past, current and reasonable practices within the Company);

(ii)

a material reduction in the  Executive’s overall standing and responsibilities within the Company, but not including (A) a mere change in title or (B) a transfer within the Company, which, in the case of both (A) and (B), does not adversely affect the  Executive’s overall status within the Company;

(iii)

a material reduction by the Company in the  Executive’s aggregate annualized compensation and benefits opportunities, except for across-the-board reductions (or modifications of benefit plans) similarly affecting all similarly situated executives (both of the Company and of any Person then in control of the Company) of comparable rank with the  Executive;

(iv)

the failure by the Company to pay to the  Executive any portion of the  Executive’s current compensation and benefits or any portion of an installment of deferred compensation under any deferred compensation program of the Company within thirty (30) days of the date such compensation is due;

(v)

any purported termination of the  Executive’s employment that is not effected pursuant to a Notice of Termination satisfying the requirements of Section 3 hereof; for purposes of this Agreement, no such purported termination shall be effective;

(vi)

the failure by Sempra Energy to perform its obligations under Section 16(c), (d) or (e) hereof;

(vii)

the failure by the Company to provide the indemnification and D&O insurance protection Section 11 of this Agreement requires it to provide; or

(viii)

the failure by Sempra Energy to comply with any material provision of this Agreement.

(b)

From and after a Change in Control, the occurrence of any of the following without the prior written consent of the  Executive, unless such act or failure to act is corrected by the Company prior to the Date of Termination specified in the Notice of Termination (as required under Section 3 hereof):

(i)

an adverse change in the  Executive’s title, authority, duties, responsibilities or reporting lines as in effect immediately prior to the Change in Control;

(ii)

a reduction by the Company in the  Executive’s aggregate annualized compensation opportunities, except for across-the-board reductions in base salaries, annual bonus opportunities or long-term incentive compensation opportunities of less than ten percent (10%) similarly affecting all similarly situated executives (both of the Company and of any Person then in control of the Company) of comparable rank with the  Executive; or the failure by the Company to continue in effect any material benefit plan in which the  Executive participates immediately prior to the Change in Control, unless an equitable arrangement (embodied in an ongoing substitute or alternative plan) has been made with respect to such plan, or the failure by the Company to continue the  Executive's participation therein (or in such substitute or alternative plan) on a basis not materially less favorable, both in terms of the amount of benefits provided and the level of the  Executive's participation relative to other participants, as existed at the time of the Change in Control;

(iii)

the relocation of the  Executive’s principal place of employment immediately prior to the Change in Control Date (the “Principal Location”) to a location which is both further away from the  Executive’s residence and more than thirty (30) miles from such Principal Location, or the Company’s requiring the  Executive to be based anywhere other than such Principal Location (or permitted relocation thereof), or a substantial increase in the  Executive’s business travel obligations outside of the Southern California area as of the Effective Date other than any such increase that (A) arises in connection with extraordinary business activities of the Company of limited duration and (B) is understood not to be part of the  Executive’s regular duties with the Company;

(iv)

the failure by the Company to pay to the  Executive any portion of the  Executive’s current compensation and benefits or any portion of an installment of deferred compensation under any deferred compensation program of the Company within thirty (30) days of the date such compensation is due;

(v)

any purported termination of the  Executive’s employment that is not effected pursuant to a Notice of Termination satisfying the requirements of Section 3 hereof; for purposes of this Agreement, no such purported termination shall be effective;

(vi)

the failure by Sempra Energy to perform its obligations under Section 16(c), (d) or (e) hereof;

(vii)

the failure by the Company to provide the indemnification and D&O insurance protection Section 11 of this Agreement requires it to provide; or

(viii)

the failure by Sempra Energy to comply with any material provision of this Agreement.

Following a Change in Control, the  Executive’s determination that an act or failure to act constitutes Good Reason shall be presumed to be valid unless such determination is deemed to be unreasonable by an arbitrator pursuant to the procedure described in Section 13 hereof.  The  Executive’s right to terminate the  Executive’s employment for Good Reason shall not be affected by the  Executive’s incapacity due to physical or mental illness.  The  Executive’s continued employment shall not constitute consent to, or a waiver of rights with respect to, any act or failure to act constituting Good Reason hereunder.

Incentive Compensation Awards” means awards granted under Incentive Compensation Plans providing the  Executive with the opportunity to earn, on a year-by-year basis, annual and long-term incentive compensation.

Incentive Compensation Plans” means annual incentive compensation plans and long-term incentive compensation plans of the Company, which long-term incentive compensation plans may include plans offering stock options, restricted stock and other long-term incentive compensation.

Involuntary Termination” means (a) the  Executive’s Separation from Service by reason of a termination of employment by the Company other than for Cause, death, or Disability, or (b) the  Executive’s Separation from Service by reason of resignation of employment with the Company for Good Reason.    

JAMS Rules” has the meaning assigned thereto in Section 13 hereof.

Notice of Termination” has the meaning assigned thereto in Section 3(a) hereof.

Payment” has the meaning assigned thereto in Section 9(a) hereof.

Payment in Lieu of Notice” has the meaning assigned thereto in Section 3(b) hereof.

Person” has the meaning set forth in section 3(a)(9) of the Exchange Act, as modified and used in sections 13(d) and 14(d) thereof, except that such term shall not include (i) the Company or any of its Affiliates, (ii) a trustee or other fiduciary holding securities under an employee benefit plan of the Company or any of its Affiliates, (iii) an underwriter temporarily holding securities pursuant to an offering of such securities, (iv) a corporation owned, directly or indirectly, by the shareholders of the Company in substantially the same proportions as their ownership of stock of the Company, or (v) a person or group as used in Rule 13d-1(b) promulgated under the Exchange Act.

Post-Change in Control Accrued Obligations” has the meaning assigned thereto in Section 6(a) hereof.

Post-Change in Control Severance Payment” has the meaning assigned thereto in Section 6 hereof.

Pre-Change in Control Accrued Obligations” has the meaning assigned thereto in Section 5(a) hereof.

Pre-Change in Control Severance Payment” has the meaning assigned thereto in Section 5 hereof.

Principal Location” has the meaning assigned thereto in clause (b)(iii) of the definition of Good Reason, above.

Proprietary Information” has the meaning assigned thereto in Section 14(a) hereof.

Release” has the meaning assigned thereto in Section 14(d) hereof.

Section 409A Payments” means any of the following:  (a) the Payment in Lieu of Notice; (b) the Pre-Change in Control Severance Payment; (c) the Post-Change in Control Severance Payment; (d) the Additional Post-Change in Control Severance Payment; (e) the Consulting Payment; (f) the payment under Section 6(b) (but only to the extent such payment or portion thereof is subject to Section 409A of the Code); (g) the financial planning services and the related payments provided under Sections 5(e) and 6(f); and (h) the legal fees and expenses reimbursed under Section 15.

Sempra Energy Control Group” means Sempra Energy and all persons with whom Sempra Energy would be considered a single employer under Section 414(b) or 414(c) of the Code, as determined from time to time.

Separation from Service”, with respect to the  Executive (or another Service Provider), means the  Executive’s (or such Service Provider’s) (a) termination of employment or (b) other termination or reduction in services, provided that such termination or reduction in clause (a) or (b) constitutes a “separation from service,” as defined in Treasury Regulation Section 1.409A-1(h), with respect to the Service Recipient.

SERP” has the meaning assigned thereto in Section 6(b) hereof.

Service Provider” means the  Executive or any other “service provider,” as defined in Treasury Regulation Section 1.409A-1(f).

Service Recipient,” with respect to the  Executive, means Sempra Energy (if the Executive is employed by Sempra Energy), or the subsidiary of Sempra Energy employing the Executive, whichever is applicable, and all persons considered part of the “service recipient,” as defined in Treasury Regulation Section 1.409A-1(g), as determined from time to time.  As provided in Treasury Regulation Section 1.409A-1(g), the “Service Recipient” shall mean the person for whom the services are performed and with respect to whom the legally binding right to compensation arises, and all persons with whom such person would be considered a single employer under Section 414(b) or 414(c) of the Code.

Specified Employee” means a Service Provider who, as of the date of the Service Provider’s Separation from Service is a “Key Employee” of the Service Recipient any stock of which is publicly traded on an established securities market or otherwise.  For purposes of this definition, a Service Provider is a “Key Employee” if the Service Provider meets the requirements of Section 416(i)(1)(A)(i), (ii) or (iii) of the Code (applied in accordance with the Treasury Regulations thereunder and disregarding Section 416(i)(5) of the Code) at any time during the Testing Year.  If a Service Provider is a “Key Employee” (as defined above) as of a Specified Employee Identification Date, the Service Provider shall be treated as “Key Employee” for the entire twelve (12) month period beginning on the Specified Employee Effective Date.  For purposes of this definition, a Service Provider’s compensation for a Testing Year shall mean such Service Provider’s compensation, as determined under Treasury Regulation Section 1.415(c)-2(a) (and applied as if the Service Recipient were not using any safe harbor provided in Treasury Regulation Section 1.415(c)-2(d), were not using any of the elective special timing rules provided in Treasury Regulation Section 1.415(c)-2(e), and were not using any of the elective special rules provided in Treasury Regulation Section 1.415(c)-2(g)), from the Service Recipient for such Testing Year.  The “Specified Employees” shall be determined in accordance with Section 409A(a)(2)(B)(i) of the Code and Treasury Regulation Section 1.409A-1(i).

Specified Employee Effective Date” means the first day of the fourth month following the Specified Employee Identification Date.  The Specified Employee Effective Date may be changed by Sempra Energy, in its discretion, in accordance with Treasury Regulation Section 1.409A-1(i)(4).

Specified Employee Identification Date”, for purposes of Treasury Regulation Section 1.409A-1(i)(3), shall mean December 31.  The “Specified Employee Identification Date” shall apply to all “nonqualified deferred compensation plans” (as defined in Treasury Regulation Section 1.409A-1(a)) of the Service Recipient and all affected Service Providers.  The “Specified Employee Identification Date” may be changed by Sempra Energy, in its discretion, in accordance with Treasury Regulation Section 1.409A-1(i)(3).

Testing Year” shall mean the twelve (12) month period ending on the Specified Employee Identification Date, as determined from time to time.

Underpayment” has the meaning assigned thereto in Section 9(b) hereof.

For purposes of this Agreement, references to any “Treasury Regulation” shall mean such Treasury Regulation as in effect on the date hereof.

Section 2.

Sarbanes-Oxley Act of 2002.  Notwithstanding anything herein to the contrary, if the Company determines, in its good faith judgment, that any provision of this Agreement is likely to be interpreted as a personal loan prohibited by the Sarbanes-Oxley Act of 2002 and the rules and regulations promulgated thereunder (the “Act”), then such provision shall be modified as necessary or appropriate so as to not violate the Act; and if this cannot be accomplished, then the Company shall use its reasonable efforts to provide the  Executive with similar, but lawful, substitute benefit(s) at a cost to the Company not to significantly exceed the amount the Company would have otherwise paid to provide such benefit(s) to the  Executive.  In addition, if the  Executive is required to forfeit or to make any repayment of any compensation or benefit(s) to the Company under the Act or any other law, such forfeiture or repayment shall not constitute Good Reason.

Section 3.

Notice and Date of Termination.  

(a)

Any termination of the  Executive’s employment by the Company or by the  Executive shall be communicated by a written notice of termination to the other party (the “Notice of Termination”).  Where applicable, the Notice of Termination shall indicate the specific termination provision in this Agreement relied upon and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of the  Executive’s employment under the provision so indicated.  Unless the Board determines otherwise, a Notice of Termination by the  Executive alleging a termination for Good Reason must be made within 180 days of the act or failure to act that the  Executive alleges to constitute Good Reason.  

(b)

The date of the  Executive’s termination of employment with the Company (the “Date of Termination”) shall be determined as follows:  (i) if the  Executive has a Separation from Service by reason of the Company terminating his or her employment, either with or without Cause, the Date of Termination shall be the date specified in the Notice of Termination (which, in the case of a termination by the Company other than for Cause, shall not be less than two (2) weeks from the date such Notice of Termination is given unless the Company elects to pay the  Executive, in addition to any other amounts payable hereunder, an amount (the “Payment in Lieu of Notice”) equal to two (2) weeks of the  Executive’s Annual Base Salary in effect on the Date of Termination), and (ii) if the basis for the  Executive’s Involuntary Termination is his resignation for Good Reason, the Date of Termination shall be determined by the  Executive and specified in the Notice of Termination, but shall not in any event be less than fifteen (15) days nor more than sixty (60) days after the date such Notice of Termination is given.   The Payment in Lieu of Notice shall be paid on such date as is determined by the Company within thirty (30) days after the date of the Executive’s Separation from Service; provided, however, that if the Executive is a Specified Employee on the date of his or her Separation from Service, such Payment in Lieu of Notice shall be paid as provided in Section 10 hereof.

Section 4.

Termination from the Board.  Upon the termination of the  Executive’s employment for any reason, the  Executive’s membership on the Board, the board of directors of any of the Company’s Affiliates, any committees of the Board and any committees of the board of directors of any of the Company’s Affiliates, if applicable, shall be automatically terminated.

Section 5.

Severance Benefits upon Involuntary Termination Prior to Change in Control.  Except as provided in Section 6 and Section 19(i) hereof, in the event of the Involuntary Termination of the  Executive prior to a Change in Control, the Company shall pay the  Executive, in one lump sum cash payment, an amount (the “Pre-Change in Control Severance Payment”) equal to one-half (0.5) times the greater of:  (X) 160% of the Executive’s Annual Base Salary as in effect on the Date of Termination, and (Y) the Executive’s Annual Base Salary as in effect on the Date of Termination, plus the Executive’s Average Annual Bonus.  In addition to the Pre-Change in Control Severance Payment, the  Executive shall be entitled to the following additional benefits specified in subsections (a) through (e).  Except as provided in Section 5(f), the Pre-Change in Control Severance Payment and the payment under Section 5(a) shall be paid on such date as is determined by the Company within thirty (30) days after the date of the Involuntary Termination; provided, however, that, if the  Executive is a Specified Employee on the date of the  Executive’s Involuntary Termination, the Pre-Change in Control Severance Payment and the financial planning services and the related payments provided under Section 5(e) shall be paid as provided in Section 10 hereof.  

(a)

Accrued Obligations.  The Company shall pay the  Executive a lump sum amount in cash equal to the sum of (A) the  Executive’s Annual Base Salary through the Date of Termination to the extent not theretofore paid, (B) an amount equal to any annual Incentive Compensation Awards earned with respect to fiscal years ended prior to the year that includes the Date of Termination to the extent not theretofore paid, (C) any accrued and unpaid vacation, if any, and (D) reimbursement for unreimbursed business expenses, if any, properly incurred by the  Executive in the performance of his duties in accordance with policies established from time to time by the Board, in each case to the extent not theretofore paid.  (The amounts specified in clauses (A), (B), (C) and (D) shall be hereinafter referred to as the “Pre-Change in Control Accrued Obligations”).

(b)

Equity Based Compensation.  The  Executive shall retain all rights to any equity-based compensation awards to the extent set forth in the applicable plan and/or award agreement.

(c)

Welfare Benefits.  Subject to Section 12 below, for a period of six (6) months following the date of the Involuntary Termination (and an additional twelve (12) months if the  Executive provides consulting services under Section 14(e) hereof), the  Executive and his dependents shall be provided with health insurance benefits substantially similar to those provided to the  Executive and his dependents immediately prior to the date of the Involuntary Termination; provided, however, that such benefits shall be provided on substantially the same terms and conditions and at the same cost to the  Executive as in effect immediately prior to the date of the Involuntary Termination.  Such benefits shall be provided through insurance maintained by the Company under the Company’s benefit plans.  Such benefits shall be provided in a manner that complies with Treasury Regulation Section 1.409A-1(a)(5).

(d)

Outplacement Services.  The  Executive shall receive reasonable outplacement services, on an in-kind basis, suitable to his position and directly related to the  Executive’s Involuntary Termination, for a period of eighteen (18) months following the date of the Involuntary Termination, in an aggregate amount of cost to the Company not to exceed $50,000.  Notwithstanding the foregoing, the  Executive shall cease to receive outplacement services on the date the  Executive accepts employment with a subsequent employer.  Such outplacement services shall be provided in a manner that complies with Treasury Regulation Section 1.409A-1(b)(9)(v)(A).

(e)

Financial Planning Services.  The  Executive shall receive financial planning services, on an in-kind basis, for a period of eighteen (18) months following the Date of Termination.  Such financial planning services shall include expert financial and legal resources to assist the Executive with financial planning needs and shall be limited to (i) current investment portfolio management, (ii) tax planning, (iii) tax return preparation, and (iv) estate planning advice and document preparation (including wills and trusts); provided, however, that the Company shall provide such financial planning services during any taxable year of the Executive only to the extent the cost to the Company for such taxable year does not exceed $25,000.  The Company shall provide such financial planning services through a financial planner selected by the Company, and shall pay the fees for such financial planning services.  The financial planning services provided during any taxable year of the  Executive shall not affect the financial planning services provided in any other taxable year of the  Executive.  The  Executive’s right to financial planning services shall not be subject to liquidation or exchange for any other benefit.  Such financial planning services shall be provided in a manner that complies with Treasury Regulation Section 1.409A-3(i)(1)(iv).  

(f)

Deferral of Payments.  The  Executive shall have the right to elect to defer the Pre-Change in Control Severance Payment to be received by the  Executive pursuant to this Section 5 under the terms and conditions of the Sempra Energy Employee and Director Savings Plan (the “Deferred Compensation Plan”).  Any such deferral election shall be made in accordance with Section 18(b) hereof.

Section 6.

Severance Benefits upon Involuntary Termination in Connection with and after Change in Control.  Notwithstanding the provisions of Section 5 above, and except as provided in Section 19(i) hereof, in the event of the Involuntary Termination of the Executive on or within two (2) years following a Change in Control, in lieu of the payments described in Section 5 above, the Company shall pay the  Executive, in one lump sum cash payment, an amount (the “Post-Change in Control Severance Payment”) equal to the greater of:  (X)  160% of the Executive’s Annual Base Salary as in effect immediately prior to the Change in Control or the Date of Termination, whichever is greater, and (Y) the Executive’s Annual Base Salary as in effect immediately prior to the Change in Control or on the Date of Termination, whichever is greater, plus the Executive’s Average Annual Bonus.  In addition to the Post-Change in Control Severance Payment, the  Executive shall be entitled to the following additional benefits specified in subsections (a) through (f).  Except as provided in Sections 6(g) and 6(h), the Post-Change in Control Severance Payment and the payments under Sections 6(a) and (b) shall be paid on such date as is determined by the Company within thirty (30) days after the date of the Involuntary Termination; provided, however, that, if the Executive is a Specified Employee on the date of the Executive’s Involuntary Termination, the Post-Change in Control Severance Payment, the Additional Post-Change in Control Severance Payment under Section 6(a)(E), the payment under Section 6(b) (but only to the extent such payment or portion thereof is subject to Section 409A of the Code), and the financial planning services and the related payments provided under Section 6(f) shall be paid as provided in Section 10 hereof.

(a)

Accrued Obligations.  The Company shall pay the  Executive a lump sum amount in cash equal to the sum of (A) the  Executive’s Annual Base Salary through the Date of Termination to the extent not theretofore paid, (B) an amount equal to any annual Incentive Compensation Awards earned with respect to fiscal years ended prior to the year that includes the Date of Termination to the extent not theretofore paid, (C) any accrued and unpaid vacation, if any, (D) reimbursement for unreimbursed business expenses, if any, properly incurred by the  Executive in the performance of his duties in accordance with policies established from time to time by the Board, and (E) an amount (the “Additional Post-Change in Control Severance Payment”) equal to:  (i) the greater of:  (X) 60% of the Executive’s Annual Base Salary as in effect immediately prior to the Change in Control or on the Date of Termination, whichever is greater, or (Y) the Executive’s Average Annual Bonus, multiplied by (ii) a fraction, the numerator of which shall be the number of days from the beginning of such fiscal year to and including the Date of Termination and the denominator of which shall be 365, in the case of each amount described in clause (A), (B), (C) or (D) to the extent not theretofore paid.  (The amounts specified in clauses (A), (B), (C), (D) and (E) shall be hereinafter referred to as the “Post-Change in Control Accrued Obligations”).

(b)

Pension Supplement.  The  Executive shall be entitled to receive a Supplemental Retirement Benefit under the Sempra Energy Supplemental Executive Retirement Plan, as in effect from time to time (“SERP”), determined in accordance with this Section 6(b), in the event that the Executive is a “Participant” (as defined in the SERP) as of the Date of Termination.  Such Supplemental Retirement Benefit shall be determined by crediting the Executive with additional months of Service (if any) equal to the number of full calendar months from the Date of Termination to the date on which the Executive would have attained age 62.  The Executive shall be entitled to receive such Supplemental Retirement Benefit without regard to whether the Executive has attained age 55 or completed five years of “Service” (as defined in the SERP) as of the Date of Termination.  The Executive shall be treated as qualified for “Retirement” (as defined in the SERP) as of the Date of Termination, and the Executive’s Vesting Factor with respect to the Supplemental Retirement Benefit shall be 100%.  The Executive’s Supplemental Retirement Benefit shall be calculated based on the Executive’s actual age as of the date of commencement of payment of such Supplemental Retirement Benefit (the “SERP Distribution Date”), and by applying the applicable early retirement factors under the SERP, if the Executive has not attained age 62 but has attained age 55 as of the SERP Distribution Date.  If the Executive has not attained age 55 as of the SERP Distribution Date, the Executive’s Supplemental Retirement Benefit shall be calculated by applying the applicable early retirement factor under the SERP for age 55, and the Supplemental Retirement Benefit otherwise payable at age 55 shall be actuarially adjusted to the Executive’s actual age as of the SERP Distribution Date using the following actuarial assumptions:  (i) the applicable mortality table promulgated by the Internal Revenue Service under Section 417(e)(3) of the Code, as in effect on the first day of the calendar year in which the SERP Distribution Date occurs, and (ii) the applicable interest rate promulgated by the Internal Revenue Service under Section 417(a)(3) of the Code for the November next preceding the first day of the calendar year in which the SERP Distribution Date occurs.  The Executive’s Supplemental Retirement Benefit shall be determined in accordance with this Section 6(b), notwithstanding any contrary provisions of the SERP and, to the extent subject to Section 409A of the Code, shall be paid in accordance with Treasury Regulation Section 1.409A-3(c)(1).  The Supplemental Retirement Benefit paid to or on behalf of the Executive in accordance with this Section 6(b) shall be in full satisfaction of any and all of the benefits payable to or on behalf of the Executive under the SERP.  

(c)

Equity-Based Compensation.  Notwithstanding the provisions of any applicable equity-compensation plan or award agreement to the contrary, all equity-based Incentive Compensation Awards (including, without limitation, stock options, stock appreciation rights, restricted stock awards, restricted stock units, performance share awards, awards covered under Section 162(m) of the Code, and dividend equivalents) held by the  Executive shall immediately vest and become exercisable or payable, as the case may be, as of the Date of Termination, to be exercised or paid, as the case may be, in accordance with the terms of the applicable Incentive Compensation Plan and Incentive Compensation Award agreement, and any restrictions on any such Incentive Compensation Awards shall automatically lapse; provided, however, that any such stock option or stock appreciation rights awards granted on or after June 26, 1998 shall remain outstanding and exercisable until the earlier of (A) the later of eighteen  (18) months following the Date of Termination or the period specified in the applicable Incentive Compensation Award agreements or (B) the expiration of the original term of such Incentive Compensation Award (or, if earlier, the tenth anniversary of the original date of grant) (it being understood that all Incentive Compensation Awards granted prior to or after June 26, 1998 shall remain outstanding and exercisable for a period that is no less than that provided for in the applicable agreement in effect as of the date of grant).

(d)

Welfare Benefits.  Subject to Section 12 below, for a period of twelve (12) months following the date of Involuntary Termination (and an additional twelve (12) months if the  Executive provides consulting services under Section 14(e) hereof), the  Executive and his dependents shall be provided with life, disability, accident and health insurance benefits substantially similar to those provided to the  Executive and his dependents immediately prior to the date of Involuntary Termination or the Change in Control Date, whichever is more favorable to the  Executive; provided, however, that such benefits shall be provided on substantially the same terms and conditions and at the same cost to the  Executive as in effect immediately prior to the date of Involuntary Termination or the Change in Control Date, whichever is more favorable to the  Executive.  Such benefits shall be provided through insurance maintained by the Company under the Company benefit plans.  Such benefits shall be provided in a manner that complies with Treasury Regulation Section 1.409A-1(a)(5).

(e)

Outplacement Services.  The  Executive shall receive reasonable outplacement services, on an in-kind basis, suitable to his position and directly related to the  Executive’s Involuntary Termination, for a period of twenty-four (24) months following the date of Involuntary Termination (but in no event beyond the last day of the  Executive’s second taxable year following the  Executive’s taxable year in which the Involuntary Termination occurs), in the aggregate amount of cost to the Company not to exceed $50,000.  Notwithstanding the foregoing, the  Executive shall cease to receive outplacement services on the date the  Executive accepts employment with a subsequent employer.  Such outplacement services shall be provided in a manner that complies with Treasury Regulation Section 1.409A-1(b)(9)(v)(A).

(f)

Financial Planning Services.  The  Executive shall receive financial planning services, on an in-kind basis, for a period of twenty-four (24) months following the date of Involuntary Termination.  Such financial planning services shall include expert financial and legal resources to assist the Executive with financial planning needs and shall be limited to (i) current investment portfolio management, (ii) tax planning, (iii) tax return preparation, and (iv) estate planning advice and document preparation (including wills and trusts); provided, however, that the Company shall provide such financial services during any taxable year of the Executive only to the extent the cost to the Company for such taxable year does not exceed $25,000.  The Company shall provide such financial planning services through a financial planner selected by the Company, and shall pay the fees for such financial planning services.  The financial planning services provided during any taxable year of the  Executive shall not affect the financial planning services provided in any other taxable year of the  Executive.  The  Executive’s right to financial planning services shall not be subject to liquidation or exchange for any other benefit.  Such financial planning services shall be provided in a manner that complies with Section 1.409A-3(i)(1)(iv).  

(g)

Involuntary Termination in Connection with a Change in Control.  Notwithstanding anything contained herein, in the event of an Involuntary Termination prior to a Change in Control, if the Involuntary Termination (1) was at the request of a third party who has taken steps reasonably calculated to effect such Change in Control or (2) otherwise arose in connection with or in anticipation of such Change in Control, then the  Executive shall, in lieu of the payments described in Section 5 hereof, be entitled to the Post-Change in Control Severance Payment and the additional benefits described in this Section 6 as if such Involuntary Termination had occurred within two (2) years following the Change in Control.  The amounts specified in Section 6 that are to be paid under this Section 6(g) shall be reduced by any amount previously paid under Section 5.  The amounts to be paid under this Section 6(g) shall be paid within thirty (30) days after the Change in Control Date of such Change in Control.

(h)

Deferral of Payments.  The  Executive shall have the right to elect to defer the Post-Change in Control Severance Payment to be received by the  Executive pursuant to this Section 6 under the terms and conditions of the Deferred Compensation Plan.  Any such deferral election shall be made in accordance with Section 18(b) hereof.

Section 7.

Severance Benefits upon Termination by the Company for Cause or by the  Executive Other than for Good Reason.  If the  Executive’s employment shall be terminated for Cause, or if the  Executive terminates employment other than for Good Reason, the Company shall have no further obligations to the  Executive under this Agreement other than the Pre-Change in Control Accrued Obligations and any amounts or benefits described in Section 11 hereof.

Section 8.

Severance Benefits upon Termination due to Death or Disability.  If the  Executive has a Separation from Service by reason of death or Disability, the Company shall pay the  Executive or his estate, as the case may be, the Post-Change in Control Accrued Obligations (without regard to whether a Change in Control has occurred) and any amounts or benefits described in Section 11 hereof.  Such payments shall be in addition to those rights and benefits to which the  Executive or his estate may be entitled under the relevant Company plans or programs.  Such payments shall be paid on such date as determined by the Company within thirty (30) days after the date of the Separation from Service; provided, however, that if the  Executive is a Specified Employee on the date of the  Executive’s Separation from Service by reason of Disability, the Additional Post-Change in Control Severance Payment under Section 6(a)(E) shall be paid as provided in Section 10 hereof.

Section 9.

Limitations on Payments by the Company.  

(a)

Anything in this Agreement to the contrary notwithstanding and except as set forth in this Section 9 below, in the event it shall be determined that any payment or distribution in the nature of compensation (within the meaning of Section 280G(b)(2) of the Code) to or for the benefit of the  Executive, whether paid or payable pursuant to this Agreement or otherwise (the “Payment”) would be subject (in whole or in part) to the excise tax imposed by Section 4999 of the Code, (the “Excise Tax”), then, subject to subsection (b), the Pre-Change in Control Severance Benefit or the Post-Change in Control Severance Payment (whichever is applicable) payable under this Agreement shall be reduced under this subsection (a) to the amount equal to the Reduced Payment.  For such Payment payable under this Agreement, the “Reduced Payment” shall be the amount equal to the greatest portion of the Payment (which may be zero)  that, if paid, would result in no portion of any Payment being subject to the Excise Tax.  

(b)

The Pre-Change in Control Severance Benefit or the Post-Change in Control Severance Payment (whichever is applicable) payable under this Agreement shall not be reduced under subsection (a) if:  

(i)

such reduction in such Payment is not sufficient to cause no portion of any Payment to be subject to the Excise Tax, or

(ii)

the Net After-Tax Unreduced Payments (as defined below) would equal or exceed one hundred and five percent (105%) of the Net After-Tax Reduced Payments (as defined below).  

For purposes of determining the amount of any Reduced Payment under subsection (a), and the Net-After Tax Reduced Payments and the Net After-Tax Unreduced Payments, the Executive shall be considered to pay federal, state and local income and employment taxes at the Executive’s applicable marginal rates taking into consideration any reduction in federal income taxes which could be obtained from the deduction of state and local income taxes, and any reduction or disallowance of itemized deductions and personal exemptions under applicable tax law).  The applicable federal, state and local income and employment taxes and the Excise Tax (to the extent applicable) are collectively referred to as the “Taxes”.

(c)

The following definitions shall apply for purposes of this Section 9:

(i)

“Net After-Tax Reduced Payments” shall mean the total amount of all Payments that the Executive would retain, on a Net After-Tax Basis, in the event that the Payments payable under this Agreement are reduced pursuant to subsection (a).

(ii)

“Net After-Tax Unreduced Payments” shall mean the total amount of all Payments that the Executive would retain, on a Net After-Tax Basis, in the event that the Payments payable under this Agreement are not reduced pursuant to subsection (a).

(iii)

“Net After-Tax Basis” shall mean, with respect to the Payments, either with or without reduction under subsection (a) (as applicable), the amount that would be retained by the Executive from such Payments after the payment of all Taxes.

(d)

All determinations required to be made under this Section 9 and the assumptions to be utilized in arriving at such determinations, shall be made by a nationally recognized accounting firm as may be agreed by the Company and the Executive (the “Accounting Firm”); provided, that the Accounting Firm’s determination shall be made based upon “substantial authority” within the meaning of Section 6662 of the Code.  The Accounting Firm shall provide detailed supporting calculations to both the Company and the Executive within fifteen (15) business days of the receipt of notice from the Executive that there has been a Payment or such earlier time as is requested by the Company.  All fees and expenses of the Accounting Firm shall be borne solely by the Company.  Any determination by the Accounting Firm shall be binding upon the Company and the Executive.  For purposes of determining whether and the extent to which the Payments will be subject to the Excise Tax, (i) no portion of the Payments the receipt or enjoyment of which the Executive shall have waived at such time and in such manner as not to constitute a “payment” within the meaning of Section 280G(b) of the Code shall be taken into account, (ii) no portion of the Payments shall be taken into account which, in the written opinion of the Accounting Firm, does not constitute a “parachute payment” within the meaning of Section 280G(b)(2) of the Code (including by reason of Section 280G(b)(4)(A) of the Code) and, in calculating the Excise Tax, no portion of such Payments shall be taken into account which, in the opinion of the Accounting Firm, constitutes reasonable compensation for services actually rendered, within the meaning of Section 280G(b)(4)(B) of the Code, in excess of the base amount (as defined in Section 280G(b)(3) of the Code) allocable to such reasonable compensation, and (iii) the value of any non-cash benefit or any deferred payment or benefit included in the Payments shall be determined by the Accounting Firm in accordance with the principles of Sections 280G(d)(3) and (4) of the Code.

Section 10.

Delayed Distribution under Section 409A of the Code.  If the  Executive is a Specified Employee on the date of the  Executive’s Involuntary Termination (or on the date of the Executive’s Separation from Service by reason of Disability), the Section 409A Payments, and any other payments or benefits under this Agreement subject to Section 409A of the Code, shall be delayed in order to avoid a prohibited distribution under Section 409A(a)(2)(B)(i) of the Code, and such payments or benefits shall be paid or distributed to the  Executive during the thirty (30) day period commencing on the earlier of (a) the expiration of the six-month period measured from the date of the  Executive’s Separation from Service or (b) the date of the Executive’s death.  Upon the expiration of the applicable six-month period under Section 409A(a)(2)(B)(i) of the Code, all payments deferred pursuant to this Section 10 (excluding in-kind benefits) shall be paid in a lump sum payment to the  Executive, plus interest thereon from the date of the  Executive’s Involuntary Termination through the payment date at an annual rate equal to Moody’s Rate.  The “Moody’s Rate” shall mean the average of the daily Moody’s Corporate Bond Yield Average – Monthly Average Corporates as published by Moody’s Investors Service, Inc. (or any successor) for the month next preceding the Date of Termination.  Any remaining payments due under the Agreement shall be paid as otherwise provided herein.

Section 11.

Nonexclusivity of Rights.  Nothing in this Agreement shall prevent or limit the  Executive’s continuing or future participation in any benefit, plan, program, policy or practice provided by the Company and for which the  Executive may qualify (except with respect to any benefit to which the  Executive has waived his rights in writing), including, without limitation, any and all indemnification arrangements in favor of the  Executive (whether under agreements or under the Company’s charter documents or otherwise), and insurance policies covering the  Executive, nor shall anything herein limit or otherwise affect such rights as the  Executive may have under any other contract or agreement entered into after the Effective Date with the Company.  Amounts which are vested benefits or which the  Executive is otherwise entitled to receive under any benefit, plan, policy, practice or program of, or any contract or agreement entered into with, the Company shall be payable in accordance with such benefit, plan, policy, practice or program or contract or agreement except as explicitly modified by this Agreement.  At all times during the  Executive’s employment with the Company and thereafter, the Company shall provide (to the extent permissible under applicable law) the  Executive with indemnification and D&O insurance insuring the  Executive against insurable events which occur or have occurred while the  Executive was a director or the Executive officer of the Company, on terms and conditions that are at least as generous as that then provided to any other current or former director or the Executive officer of the Company or any Affiliate.  Such indemnification and D&O insurance shall be provided in a manner that complies with Treasury Regulation Section 1.409A-1(b)(10).

Section 12.

Full Settlement; Mitigation.  The Company’s obligation to make the payments provided for in this Agreement and otherwise to perform its obligations hereunder shall not be affected by any set-off, counterclaim, recoupment, defense or other claim, right or action which the Company may have against the  Executive or others, provided that nothing herein shall preclude the Company from separately pursuing recovery from the  Executive based on any such claim.  In no event shall the  Executive be obligated to seek other employment or take any other action by way of mitigation of the amounts (including amounts for damages for breach) payable to the  Executive under any of the provisions of this Agreement, and such amounts shall not be reduced whether or not the  Executive obtains other employment.

Section 13.

Dispute Resolution.

Any disagreement, dispute, controversy or claim arising out of or relating to this Agreement or the interpretation of this Agreement or any arrangements relating to this Agreement or contemplated in this Agreement or the breach, termination or invalidity thereof shall be settled by final and binding arbitration administered by JAMS in San Diego, California in accordance with the then existing JAMS arbitration rules applicable to employment disputes (the “JAMS Rules”); provided that, notwithstanding any provision in such rules to the contrary, in all cases the parties shall be entitled to reasonable discovery.  In the event of such an arbitration proceeding, the  Executive and the Company shall select a mutually acceptable neutral arbitrator from among the JAMS panel of arbitrators.  In the event the  Executive and the Company cannot agree on an arbitrator, the arbitrator shall be selected in accordance with the then existing JAMS Rules.  Neither the  Executive nor the Company nor the arbitrator shall disclose the existence, content or results of any arbitration hereunder without the prior written consent of all parties, except to the extent necessary to enforce any arbitration award in a court of competent jurisdiction.  Except as provided herein, the Federal Arbitration Act shall govern the interpretation of, enforcement of and all proceedings under this agreement to arbitrate.  The arbitrator shall apply the substantive law (and the law of remedies, if applicable) of the state of California, or federal law, or both, as applicable, and the arbitrator is without jurisdiction to apply any different substantive law.  The arbitrator shall have the authority to entertain a motion to dismiss and/or a motion for summary judgment by any party and shall apply the standards governing such motions under the Federal Rules of Civil Procedure.  The arbitrator shall render an award and a written, reasoned opinion in support thereof.  Judgment upon the award may be entered in any court having jurisdiction thereof.  The  Executive shall not be required to pay any arbitration fee or cost that is unique to arbitration or greater than any amount he would be required to pay to pursue his claims in a court of competent jurisdiction.

Section 14.

Executive’s Covenants.    

(a)

Confidentiality.  The  Executive acknowledges that in the course of his employment with the Company, he has acquired non-public privileged or confidential information and trade secrets concerning the operations, future plans and methods of doing business (“Proprietary Information”) of the Company and its Affiliates; and the  Executive agrees that it would be extremely damaging to the Company and its Affiliates if such Proprietary Information were disclosed to a competitor of the Company and its Affiliates or to any other person or corporation.  The  Executive understands and agrees that all Proprietary Information has been divulged to the  Executive in confidence and further understands and agrees to keep all Proprietary Information secret and confidential (except for such information which is or becomes publicly available other than as a result of a breach by the  Executive of this provision or information the  Executive is required by any governmental, administrative or court order to disclose) without limitation in time.  In view of the nature of the  Executive’s employment and the Proprietary Information the  Executive has acquired during the course of such employment, the  Executive likewise agrees that the Company and its Affiliates would be irreparably harmed by any disclosure of Proprietary Information in violation of the terms of this paragraph and that the Company and its Affiliates shall therefore be entitled to preliminary and/or permanent injunctive relief prohibiting the  Executive from engaging in any activity or threatened activity in violation of the terms of this paragraph and to any other relief available to them.  Inquiries regarding whether specific information constitutes Proprietary Information shall be directed to the Company’s Senior Vice President, Public Policy (or, if such position is vacant, the Company’s then Chief Executive Officer); provided, that the Company shall not unreasonably classify information as Proprietary Information.

(b)

Non-Solicitation of Employees.  The  Executive recognizes that he possesses and will possess confidential information about other employees of the Company and its Affiliates relating to their education, experience, skills, abilities, compensation and benefits, and inter-personal relationships with customers of the Company and its Affiliates.  The  Executive recognizes that the information he possesses and will possess about these other employees is not generally known, is of substantial value to the Company and its Affiliates in developing their business and in securing and retaining customers, and has been and will be acquired by him because of his business position with the Company and its Affiliates.  The  Executive agrees that at all times during the  Executive’s employment with the Company and for a period of one (1) year thereafter, he will not, directly or indirectly, solicit or recruit any employee of the Company or its Affiliates for the purpose of being employed by him or by any competitor of the Company or its Affiliates on whose behalf he is acting as an agent, representative or employee and that he will not convey any such confidential information or trade secrets about other employees of the Company and its Affiliates to any other person; provided, however, that it shall not constitute a solicitation or recruitment of employment in violation of this paragraph to discuss employment opportunities with any employee of the Company or its Affiliates who has either first contacted the  Executive or regarding whose employment the  Executive has discussed with and received the written approval of the Company’s Vice President, Human Resources (or, if such position is vacant, the Company’s then Chief Executive Officer), prior to making such solicitation or recruitment.  In view of the nature of the  Executive’s employment with the Company, the  Executive likewise agrees that the Company and its Affiliates would be irreparably harmed by any solicitation or recruitment in violation of the terms of this paragraph and that the Company and its Affiliates shall therefore be entitled to preliminary and/or permanent injunctive relief prohibiting the  Executive from engaging in any activity or threatened activity in violation of the terms of this paragraph and to any other relief available to them.

(c)

Survival of Provisions.  The obligations contained in Section 14(a) and Section 14(b) above shall survive the termination of the  Executive’s employment within the Company and shall be fully enforceable thereafter.  If it is determined by a court of competent jurisdiction in any state that any restriction in Section 14(a) or Section 14(b) above is excessive in duration or scope or is unreasonable or unenforceable under the laws of that state, it is the intention of the parties that such restriction may be modified or amended by the court to render it enforceable to the maximum extent permitted by the law of that state.

(d)

Release; Lump Sum Payment.  In the event of the  Executive’s Involuntary Termination,  if the  Executive (i) agrees to the covenants described in Section 14(a) and Section 14(b) above, (ii) executes a release (the “Release”) of all claims substantially in the form attached hereto as Exhibit A within fifty (50) days after the date of Involuntary Termination and does not revoke such Release in accordance with the terms thereof, and (iii) agrees to provide the consulting services described in Section 14(e) below, then in consideration for such covenants, the Company shall pay the  Executive, in one cash lump sum, an amount (the “Consulting Payment”) in cash equal to the greater of:  (X) 160% of the Executive’s Annual Base Salary as in effect on the Date of Termination, and (Y) the Executive’s Annual Base Salary as in effect on the Date of Termination, plus the Executive’s Average Annual Bonus.  Except as provided in this subsection, the Consulting Payment shall be paid on such date as is determined by the Company within the ten (10) day period commencing on the 60th day after the date of the Executive’s Involuntary Termination; provided, however, that if the  Executive is a Specified Employee on the date of the  Executive’s Involuntary Termination, the Consulting Payment shall be paid as provided in Section 10 hereof.  The  Executive shall have the right to elect to defer the Consulting Payment under the terms and conditions of the Company’s Deferred Compensation Plan.  Any such deferral election shall be made in accordance with Section 18(b) hereof.

(e)

Consulting.  If the  Executive agrees to the covenants described in Section 14(d) above,  then the  Executive shall have the obligation to provide consulting services to the Company as an independent contractor, commencing on the Date of Termination and ending on the second anniversary of the Date of Termination (the “Consulting Period”).  The  Executive shall hold himself available at reasonable times and on reasonable notice to render such consulting services as may be so assigned to him by the Board or the Company’s then Chief Executive Officer; provided, however, that unless the parties otherwise agree, the consulting services rendered by the  Executive during the Consulting Period shall not exceed twenty (20) hours each month; and, provided, further, that the consulting services rendered by the  Executive during the Consulting Period shall in no event exceed twenty percent (20%) of the average level of services performed by the  Executive for the Company over the thirty-six (36) month period immediately preceding the  Executive’s Separation from Service (or the full period of services to the Company, if the  Executive has been providing services to the Company for less than thirty-six (36) months).  The Company agrees to use its best efforts during the Consulting Period to secure the benefit of the  Executive’s consulting services so as to minimize the interference with the  Executive’s other activities, including requiring the performance of consulting services at the Company’s offices only when such services may not be reasonably performed off-site by the  Executive.

Section 15.

Legal Fees.  

(a)

Reimbursement of Legal Fees.  Subject to subsection (b), in the event of the Executive’s Separation from Service either (1) prior to a Change in Control, or (2) on or within two (2) years following a Change in Control, the Company shall reimburse the  Executive for all legal fees and expenses (including but not limited to fees and expenses in connection with any arbitration) incurred by the  Executive in disputing any issue arising under this Agreement relating to the  Executive’s Separation from Service or in seeking to obtain or enforce any benefit or right provided by this Agreement.  

(b)

Requirements for Reimbursement.  The Company shall reimburse the  Executive’s legal fees and expenses pursuant to subsection (a) above only to the extent the arbitrator or court determines the following:  (i) the  Executive disputed such issue, or sought to obtain or enforce such benefit or right, in good faith, (ii) the  Executive had a reasonable basis for such claim, and (iii) in the case of subsection (a)(1) above, the  Executive is the prevailing party.  In addition, the Company shall reimburse such legal fees and expenses, only if such legal fees and expenses are incurred during the twenty (20) year period beginning on the date of the Executive’s Separation from Service.   The legal fees and expenses paid to the  Executive for any taxable year of the  Executive shall not affect the legal fees and expenses paid to the  Executive for any other taxable year of the  Executive.  The legal fees and expenses shall be paid to the Executive on or before the last day of the Executive’s taxable year following the taxable year in which the fees or expenses are incurred.  The  Executive’s right to reimbursement of legal fees and expenses shall not be subject to liquidation or exchange for any other benefit.  Such right to reimbursement of legal fees and expenses shall be provided in a manner that complies with Treasury Regulation Section 1.409A-3(i)(1)(iv).  If the Executive is a Specified Employee on the date of the Executive’s Separation from Service, such right to reimbursement of legal fees and expenses shall be paid as provided in Section 10 hereof.

Section 16.

Successors.

(a)

Assignment by the Executive.  This Agreement is personal to the  Executive and without the prior written consent of Sempra Energy shall not be assignable by the  Executive otherwise than by will or the laws of descent and distribution.  This Agreement shall inure to the benefit of and be enforceable by the  Executive’s legal representatives.

(b)

Successors and Assigns of Sempra Energy.  This Agreement shall inure to the benefit of and be binding upon Sempra Energy, its successors and assigns.  Sempra Energy may not assign this Agreement to any person or entity (except for a successor described in Section 16(c), (d) or (e) below) without the  Executive’s written consent.

(c)

Assumption.  Sempra Energy shall require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of Sempra Energy to assume expressly and agree to perform the obligations and satisfy and discharge the liabilities of this Agreement in the same manner and to the same extent that Sempra Energy would have been required to perform the obligations and satisfy and discharge the liabilities under this Agreement if no such succession had taken place, and Sempra Energy shall have no further obligations and liabilities under this Agreement.  Upon such assumption, references to Sempra Energy in this Agreement shall be replaced with references to such successor.

(d)

Sale of Subsidiary.  In the event that (i) the Executive is employed by a direct or indirect subsidiary of Sempra Energy that is a member of the Sempra Energy Control Group, (ii) Sempra Energy, directly or indirectly through one or more intermediaries, sells or otherwise disposes of such subsidiary, and (iii) such subsidiary ceases to be a member of the Sempra Energy Control Group, then if, on the date such subsidiary ceases to be a member of the Sempra Energy Control Group, the Executive continues in employment with such subsidiary and the Executive does not have a Separation from Service, Sempra Energy shall require such subsidiary or any successor (whether direct or indirect, by purchase merger, consolidation or otherwise) to such subsidiary, or the parent thereof, to assume expressly and agree to perform the obligations and satisfy and discharge the liabilities under this Agreement in the same manner and to the same extent that Sempra Energy would have been required to perform the obligations and satisfy and discharge the liabilities under this Agreement, if such subsidiary had not ceased to be part of the Sempra Energy Control Group, and, upon such assumption, Sempra Energy shall have no further obligations and liabilities under the Agreement.  Upon such assumption, (i) references to Sempra Energy in this Agreement shall be replaced with references to such subsidiary, or such successor or parent thereof, assuming this Agreement, and (ii) subsection (b) of the definition of “Cause” and subsection (b) of the definition of “Good Reason” shall apply thereafter, as if a Change in Control had occurred on the date of such cessation.

(e)

Sale of Assets of Subsidiary.  In the event that (i) the Executive is employed by a direct or indirect subsidiary of Sempra Energy, and (ii) such subsidiary sells or otherwise disposes of substantial assets of such subsidiary to an unrelated service recipient, as determined under Treasury Regulation Section 1.409A-1(f)(2)(ii) (the “Asset Purchaser”), in a transaction described in Treasury Regulation Section 1.409A-1(h)(4) (an “Asset Sale”), then if, on the date of such Asset Sale, the Executive becomes employed by the Asset Purchaser, Sempra Energy and the Asset Purchaser shall specify, in accordance with Treasury Regulation Section 1.409A-1(h)(4), that the Executive shall not be treated as having a Separation from Service, and Sempra Energy shall require such Asset Purchaser, or the parent thereof, to assume expressly and agree to perform the obligations and satisfy and discharge the liabilities under this Agreement in the same manner and to the same extent that Sempra Energy would have been required to perform the obligations and satisfy and discharge the liabilities under this Agreement, if the Asset Sale had not taken place, and, upon such assumption, Sempra Energy shall have no further obligations and liabilities under the Agreement.  Upon such assumption, (i) references to Sempra Energy in this Agreement shall be replaced with references to the Asset Purchaser or the parent thereof, as applicable, and (ii) subsection (b) of the definition of “Cause” and subsection (b) of the definition of “Good Reason” shall apply thereafter, as if a Change in Control had occurred on the date of the Asset Sale.

Section 17.

Administration Prior to Change in Control.  Prior to a Change in Control, the Compensation Committee shall have full and complete authority to construe and interpret the provisions of this Agreement, to determine an individual’s entitlement to benefits under this Agreement, to make in its sole and absolute discretion all determinations contemplated under this Agreement, to investigate and make factual determinations necessary or advisable to administer or implement this Agreement, and to adopt such rules and procedures as it deems necessary or advisable for the administration or implementation of this Agreement.  All determinations made under this Agreement by the Compensation Committee shall be final and binding on all interested persons.  Prior to a Change in Control, the Compensation Committee may delegate responsibilities for the operation and administration of this Agreement to one or more officers or employees of the Company.  The provisions of this Section 17 shall terminate and be of no further force and effect upon the occurrence of a Change in Control.   

Section 18.

Section 409A of the Code.

(a)

Compliance with and Exemption from Section 409A of the Code.  Certain payments and benefits payable under this Agreement (including, without limitation, the Section 409A Payments) are intended to comply with the requirements of Section 409A of the Code.  Certain payments and benefits payable under this Agreement are intended to be exempt from the requirements of Section 409A of the Code.  This Agreement shall be interpreted in accordance with the applicable requirements of, and exemptions from, Section 409A of the Code and the Treasury Regulations thereunder.  To the extent the payments and benefits under this Agreement are subject to Section 409A of the Code, this Agreement shall be interpreted, construed and administered in a manner that satisfies the requirements of Sections 409A(a)(2), (3) and (4) of the Code and the Treasury Regulations thereunder (subject to the transitional relief under Internal Revenue Service Notice 2005-1, the Proposed Regulations under Section 409A of the Code, Internal Revenue Service Notice 2006-79, Internal Revenue Service Notice 2007-78, Internal Revenue Service Notice 2007-86 and other applicable authority issued by the Internal Revenue Service).  As provided in Internal Revenue Notice 2007-86, notwithstanding any other provision of this Agreement, with respect to an election or amendment to change a time or form of payment under this Agreement made on or after January 1, 2008 and on or before December 31, 2008, the election or amendment shall apply only with respect to payments that would not otherwise be payable in 2008, and shall not cause payments to be made in 2008 that would not otherwise be payable in 2008.  If the Company and the  Executive determine that any compensation, benefits or other payments that are payable under this Agreement and intended to comply with Sections 409A(a)(2), (3) and (4) of the Code do not comply with Section 409A of the Code, the Treasury Regulations thereunder and other applicable authority issued by the Internal Revenue Service, to the extent permitted under Section 409A of the Code, the Treasury Regulations thereunder and any applicable authority issued by the Internal Revenue Service, the Company and the  Executive agree to amend this Agreement, or take such other actions as the Company and the  Executive deem reasonably necessary or appropriate, to cause such compensation, benefits and other payments to comply with the requirements of Section 409A of the Code, the Treasury Regulations thereunder and other applicable authority issued by the Internal Revenue Service, while providing compensation, benefits and other payments that are, in the aggregate, no less favorable than the compensation, benefits and other payments provided under this Agreement.  In the case of any compensation, benefits or other payments that are payable under this Agreement and intended to comply with Sections 409A(a)(2), (3) and (4) of the Code, if any provision of the Agreement would cause such compensation, benefits or other payments to fail to so comply, such provision shall not be effective and shall be null and void with respect to such compensation, benefits or other payments to the extent such provision would cause a failure to comply, and such provision shall otherwise remain in full force and effect.

(b)

Deferral Elections.  As provided in Sections 5(f), 6(h) and 14(d), the  Executive may elect to defer the Pre-Change in Control Severance Payment, the Post-Change in Control Severance Payment and the Consulting Payment as follows.    The  Executive’s deferral election shall satisfy the requirements of Treasury Regulation Section 1.409A-2(b) and the terms and conditions of the Deferred Compensation Plan.  Such deferral election shall designate the whole percentage (up to a maximum of 100%) of the Pre-Change in Control Severance Payment, the Post-Change in Control Severance Payment and the Consulting Payment to be deferred, shall be irrevocable when made, and shall not take effect until at least twelve (12) months after the date on which the election is made.  Such deferral election shall provide that the amount deferred shall be deferred for a period of not less than five (5) years from the date the payment of the amount deferred would otherwise have been made, in accordance with Treasury Regulation Section 1.409A-2(b)(1)(ii).

Section 19.

Miscellaneous.

(a)

Governing Law.  This Agreement shall be governed by and construed in accordance with the laws of the State of California, without reference to its principles of conflict of laws.  The captions of this Agreement are not part of the provisions hereof and shall have no force or effect.  This Agreement may not be amended, modified, repealed, waived, extended or discharged except by an agreement in writing signed by the party against whom enforcement of such amendment, modification, repeal, waiver, extension or discharge is sought.  No person, other than pursuant to a resolution of the Board or a committee thereof, shall have authority on behalf of the Company to agree to amend, modify, repeal, waive, extend or discharge any provision of this Agreement or anything in reference thereto.

(b)

Notices.  All notices and other communications hereunder shall be in writing and shall be given by hand delivery to the other party or by registered or certified mail, return receipt requested, postage prepaid, addressed, in either case, to the Company’s headquarters or to such other address as either party shall have furnished to the other in writing in accordance herewith.  Notices and communications shall be effective when actually received by the addressee.

(c)

Severability.  The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement.

(d)

Taxes.  The Company may withhold from any amounts payable under this Agreement such federal, state or local taxes as shall be required to be withheld pursuant to any applicable law or regulation.

(e)

No Waiver.  The  Executive’s or the Company’s failure to insist upon strict compliance with any provision hereof or any other provision of this Agreement or the failure to assert any right the  Executive or the Company may have hereunder, including, without limitation, the right of the  Executive to terminate employment for Good Reason pursuant to Section 1 hereof, or the right of the Company to terminate the  Executive’s employment for Cause pursuant to Section 1 hereof shall not be deemed to be a waiver of such provision or right or any other provision or right of this Agreement.

(f)

Entire Agreement; Exclusive Benefit; Supersession of Prior Agreement.  This instrument contains the entire agreement of the  Executive, the Company or any predecessor or subsidiary thereof with respect to any severance or termination pay.  The Pre-Change in Control Severance Payment, the Post-Change in Control Severance Payment and all other benefits provided hereunder shall be in lieu of any other severance payments to which the  Executive is entitled under any other severance plan or program or arrangement sponsored by the Company, as well as pursuant to any individual employment or severance agreement that was entered into by the  Executive and the Company, and, upon the Effective Date of this Agreement, all such plans, programs, arrangements and agreements are hereby automatically superseded and terminated.  

(g)

No Right of Employment.  Nothing in this Agreement shall be construed as giving the  Executive any right to be retained in the employ of the Company or shall interfere in any way with the right of the Company to terminate the  Executive’s employment at any time, with or without Cause.

(h)

Unfunded Obligation.  The obligations under this Agreement shall be unfunded.  Benefits payable under this Agreement shall be paid from the general assets of the Company.  The Company shall have no obligation to establish any fund or to set aside any assets to provide benefits under this Agreement.

(i)

Termination upon Sale of Assets of Subsidiary.  Notwithstanding anything contained herein, this Agreement shall automatically terminate and be of no further force and effect and no benefits shall be payable hereunder in the event that (i) the Executive is employed by a direct or indirect subsidiary of Sempra Energy, and (ii) an Asset Sale (as defined in Section 16(e)) occurs (other than such a sale or disposition which is part of a transaction or series of transactions which would result in a Change in Control), and (iii) as a result of such Asset Sale, the  Executive is offered employment by the Asset Purchaser in an executive position with reasonably comparable status, compensation, benefits and severance agreement (including the assumption of this Agreement in accordance with Section 16(e)) and which is consistent with the  Executive’s experience and education, but the  Executive declines to accept such offer and the Executive fails to become employed by the Asset Purchaser on the date of the Asset Sale.  

(j)

Term.  The term of this Agreement shall commence on the Effective Date and shall continue until the third (3rd) anniversary of the Effective Date; provided, however, that commencing on the second (2nd) anniversary of the Effective Date (and each anniversary of the Effective Date thereafter), the term of this Agreement shall automatically be extended for one (1) additional year, unless at least ninety (90) days prior to such date, the Company or the  Executive shall give written notice to the other party that it or he, as the case may be, does not wish to so extend this Agreement.  Notwithstanding the foregoing, if the Company gives such written notice to the  Executive less than two (2) years after a Change in Control, the term of this Agreement shall be automatically extended until the later of (A) the date that is one (1) year after the anniversary of the Effective Date that follows such written notice or (B) the second (2nd) anniversary of the Change in Control Date.

(k)

Counterparts.  This Agreement may be executed in several counterparts, each of which shall be deemed to be an original but all of which together shall constitute one and the same instrument.


[remainder of page intentionally left blank]



 


IN WITNESS WHEREOF, the  Executive and, pursuant to due authorization from its Board of Directors, the Company have caused this Agreement to be executed as of the day and year first above written.

SEMPRA ENERGY


G. Joyce Rowland

Senior Vice President – Human Resources, Diversity & Inclusion  


_____________________________________

Date


EXECUTIVE




Dennis Arriola

President & COO – Southern California Gas Company


_____________________________________

Date




 




EXHIBIT A


GENERAL RELEASE

This GENERAL RELEASE (the “Agreement”), dated ___________, is made by and between ______________________________, a California corporation (the “Company”) and  ___________________________ (“you” or “your”).

WHEREAS, you and the Company have previously entered into that certain Severance Pay Agreement dated ____________, 20___ (the “Severance Pay Agreement”); and

WHEREAS, Section 14(d) of the Severance Pay Agreement provides for the payment of a benefit to you by the Company in consideration for certain covenants, including your execution and non-revocation of a general release of claims by you against the Company and its subsidiaries and affiliates.

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, you and the Company hereby agree as follows:

ONE:  Your signing of this Agreement confirms that your employment with the Company shall terminate at the close of business on ____________, or earlier upon our mutual agreement.

TWO:  As a material inducement for the payment of the benefit under Section 14(d) of the Severance Pay Agreement, and except as otherwise provided in this Agreement, you and the Company hereby irrevocably and unconditionally release, acquit and forever discharge the other from any and all Claims either may have against the other.  For purposes of this Agreement and the preceding sentence, the words “Releasee” or “Releasees” and “Claim” or “Claims” shall have the meanings set forth below:

(a)

The words “Releasee” or “Releasees” shall refer to you and to the Company and each of the Company’s owners, stockholders, predecessors, successors, assigns, agents, directors, officers, employees, representatives, attorneys, advisors, parent companies, divisions, subsidiaries, affiliates (and agents, directors, officers, employees, representatives, attorneys and advisors of such parent companies, divisions, subsidiaries and affiliates) and all persons acting by, through, under or in concert with any of them.

(b)

The words “Claim” or “Claims” shall refer to any charges, complaints, claims, liabilities, obligations, promises, agreements, controversies, damages, actions, causes of action, suits, rights, demands, costs, losses, debts and expenses (including attorneys’ fees and costs actually incurred) of any nature whatsoever, known or unknown, suspected or unsuspected, which you or the Company now, in the past or, except as limited by law or regulation such as the Age Discrimination in Employment Act (ADEA), in the future may have, own or hold against any of the Releasees; provided, however, that the word “Claim” or “Claims” shall not refer to any charges, complaints, claims, liabilities, obligations, promises, agreements, controversies, damages, actions, causes of action, suits, rights, demands, costs, losses, debts and expenses (including attorneys’ fees and costs actually incurred) arising under [identify severance, employee benefits, stock option, indemnification and D&O  and other agreements containing duties, rights obligations etc. of either party that are to remain operative].  Claims released pursuant to this Agreement by you and the Company include, but are not limited to, rights arising out of alleged violations of any contracts, express or implied, any tort, any claim that you failed to perform or negligently performed or breached your duties during employment at the Company, any legal restrictions on the Company’s right to terminate employees or any federal, state or other governmental statute, regulation, or ordinance, including, without limitation:  (1) Title VII of the Civil Rights Act of 1964 (race, color, religion, sex and national origin discrimination); (2) 42 U.S.C. § 1981 (discrimination); (3) 29 U.S.C. §§ 621–634 (age discrimination); (4) 29 U.S.C. § 206(d)(l) (equal pay); (5) 42 U.S.C. §§ 12101, et seq. (disability); (6) the California Constitution, Article I, Section 8 (discrimination); (7) the California Fair Employment and Housing Act (discrimination, including race, color, national origin, ancestry, physical handicap, medical condition, marital status, religion, sex or age); (8) California Labor Code Section 1102.1 (sexual orientation discrimination); (9) the Executive Order 11246 (race, color, religion, sex and national origin discrimination); (10) the Executive Order 11141 (age discrimination); (11) §§ 503 and 504 of the Rehabilitation Act of 1973 (handicap discrimination); (12) The Worker Adjustment and Retraining Act (WARN Act); (13) the California Labor Code (wages, hours, working conditions, benefits and other matters); (14) the Fair Labor Standards Act (wages, hours, working conditions and other matters); the Federal Employee Polygraph Protection Act (prohibits employer from requiring employee to take polygraph test as condition of employment); and (15) any federal, state or other governmental statute, regulation or ordinance which is similar to any of the statutes described in clauses (1) through (14).

THREE:  You and the Company expressly waive and relinquish all rights and benefits afforded by any statute (including but not limited to Section 1542 of the Civil Code of the State of California) which limits the effect of a release with respect to unknown claims.  You and the Company do so understanding and acknowledging the significance of the release of unknown claims and the waiver of statutory protection against a release of unknown claims (including but not limited to Section 1542).  Section 1542 of the Civil Code of the State of California states as follows:

“A GENERAL RELEASE DOES NOT EXTEND TO CLAIMS WHICH THE CREDITOR DOES NOT KNOW OR SUSPECT TO EXIST IN HIS FAVOR AT THE TIME OF EXECUTING THE RELEASE, WHICH IF KNOWN BY HIM MUST HAVE MATERIALLY AFFECTED HIS SETTLEMENT WITH THE DEBTOR.”

Thus, notwithstanding the provisions of Section 1542 or of any similar statute, and for the purpose of implementing a full and complete release and discharge of the Releasees, you and the Company expressly acknowledge that this Agreement is intended to include in its effect, without limitation, all Claims which are known and all Claims which you or the Company do not know or suspect to exist in your or the Company’s favor at the time of execution of this Agreement and that this Agreement contemplates the extinguishment of all such Claims.

FOUR:  The parties acknowledge that they might hereafter discover facts different from, or in addition to, those they now know or believe to be true with respect to a Claim or Claims released herein, and they expressly agree to assume the risk of possible discovery of additional or different facts, and agree that this Agreement shall be and remain effective, in all respects, regardless of such additional or different discovered facts.

FIVE:  You hereby represent and acknowledge that you have not filed any Claim of any kind against the Company or others released in this Agreement.  You further hereby expressly agree never to initiate against the Company or others released in this Agreement any administrative proceeding, lawsuit or any other legal or equitable proceeding of any kind asserting any Claims that are released in this Agreement.

The Company hereby represents and acknowledges that it has not filed any Claim of any kind against you or others released in this Agreement.  The Company further hereby expressly agrees never to initiate against you or others released in this Agreement any administrative proceeding, lawsuit or any other legal or equitable proceeding of any kind asserting any Claims that are released in this Agreement.

SIX:  You hereby represent and agree that you have not assigned or transferred, or attempted to have assigned or transfer, to any person or entity, any of the Claims that you are releasing in this Agreement.

The Company hereby represents and agrees that it has not assigned or transferred, or attempted to have assigned or transfer, to any person or entity, any of the Claims that it is releasing in this Agreement.

SEVEN:  As a further material inducement to the Company to enter into this Agreement, you hereby agree to indemnify and hold each of the Releasees harmless from all loss, costs, damages, or expenses, including without limitation, attorneys’ fees incurred by the Releasees, arising out of any breach of this Agreement by you or the fact that any representation made in this Agreement by you was false when made.

As a further material inducement to you to enter into this Agreement, the Company hereby agrees to indemnify and hold each of the Releasees harmless from all loss, costs, damages, or expenses, including without limitation, attorneys’ fees incurred by the Releasees, arising out of any breach of this Agreement by it or the fact that any representation made in this Agreement by it was knowingly false when made.

EIGHT:  You and the Company represent and acknowledge that in executing this Agreement, neither is relying upon any representation or statement not set forth in this Agreement or the Severance Agreement.

NINE:

(a)

This Agreement shall not in any way be construed as an admission by the Company that it has acted wrongfully with respect to you or any other person, or that you have any rights whatsoever against the Company, and the Company specifically disclaims any liability to or wrongful acts against you or any other person, on the part of itself, its employees or its agents.  This Agreement shall not in any way be construed as an admission by you that you have acted wrongfully with respect to the Company, or that you failed to perform your duties or negligently performed or breached your duties, or that the Company had good cause to terminate your employment.

(b)

If you are a party or are threatened to be made a party to any proceeding by reason of the fact that you were an officer or director of the Company, the Company shall indemnify you against any expenses (including reasonable attorneys’ fees; provided, that counsel has been approved by the Company prior to retention, which approval shall not be unreasonably withheld), judgments, fines, settlements and other amounts actually or reasonably incurred by you in connection with that proceeding; provided, that you acted in good faith and in a manner you reasonably believed to be in the best interest of the Company.  The limitations of California Corporations Code Section 317 shall apply to this assurance of indemnification.

(c)

You agree to cooperate with the Company and its designated attorneys, representatives and agents in connection with any actual or threatened judicial, administrative or other legal or equitable proceeding in which the Company is or may become involved.  Upon reasonable notice, you agree to meet with and provide to the Company or its designated attorneys, representatives or agents all information and knowledge you have relating to the subject matter of any such proceeding.  The Company agrees to reimburse you for any reasonable costs you incur in providing such cooperation.

TEN:  This Agreement is made and entered into in California.  This Agreement shall in all respects be interpreted, enforced and governed by and under the laws of the State of California and applicable Federal law.  Any dispute about the validity, interpretation, effect or alleged violation of this Agreement (an “arbitrable dispute”) must be submitted to arbitration in San Diego, California.  Arbitration shall take place before an experienced employment arbitrator licensed to practice law in such state and selected in accordance with the then existing JAMS arbitration rules applicable to employment disputes; provided, however, that in any event, the arbitrator shall allow reasonable discovery.  Arbitration shall be the exclusive remedy for any arbitrable dispute.  The arbitrator in any arbitrable dispute shall not have authority to modify or change the Agreement in any respect.  You and the Company shall each be responsible for payment of one-half (1/2) the amount of the arbitrator’s fee(s); provided, however, that in no event shall you be required to pay any fee or cost of arbitration that is unique to arbitration or exceeds the costs you would have incurred had any arbitrable dispute been pursued in a court of competent jurisdiction.  The Company shall make up any shortfall.  Should any party to this Agreement institute any legal action or administrative proceeding against the other with respect to any Claim waived by this Agreement or pursue any arbitrable dispute by any method other than arbitration, the prevailing party shall be entitled to recover from the non-prevailing party all damages, costs, expenses and attorneys’ fees incurred as a result of that action.  The arbitrator’s decision and/or award shall be rendered in writing and will be fully enforceable and subject to an entry of judgment by the Superior Court of the State of California for the County of San Diego, or any other court of competent jurisdiction.

ELEVEN:  Both you and the Company understand that this Agreement is final and binding eight (8) days after its execution and return.  Should you nevertheless attempt to challenge the enforceability of this Agreement as provided in Paragraph TEN or, in violation of that Paragraph, through litigation, as a further limitation on any right to make such a challenge, you shall initially tender to the Company, by certified check delivered to the Company, all monies received pursuant to Section 14(d) of the Severance Pay Agreement, plus interest, and invite the Company to retain such monies and agree with you to cancel this Agreement and void the Company’s obligations under Section 14(d) of the Severance Pay Agreement.  In the event the Company accepts this offer, the Company shall retain such monies and this Agreement shall be canceled and the Company shall have no obligation under Section 14(d) of the Severance Pay Agreement.  In the event the Company does not accept such offer, the Company shall so notify you and shall place such monies in an interest-bearing escrow account pending resolution of the dispute between you and the Company as to whether or not this Agreement and the Company’s obligations under Section 14(d) of the Severance Pay Agreement shall be set aside and/or otherwise rendered voidable or unenforceable.  Additionally, any consulting agreement then in effect between you and the Company shall be immediately rescinded with no requirement of notice.

TWELVE:  Any notices required to be given under this Agreement shall be delivered either personally or by first class United States mail, postage prepaid, addressed to the respective parties as follows:

To Company:

[TO COME]

Attn:  [TO COME]

To You:

______________________


______________________


______________________

THIRTEEN:  You understand and acknowledge that you have been given a period of forty-five (45) days to review and consider this Agreement (as well as statistical data on the persons eligible for similar benefits) before signing it and may use as much of this forty-five (45) day period as you wish prior to signing.  You are encouraged, at your personal expense, to consult with an attorney before signing this Agreement.  You understand and acknowledge that whether or not you do so is your decision.  You may revoke this Agreement within seven (7) days of signing it.  If you wish to revoke, the Company’s Vice President, Human Resources must receive written notice from you no later than the close of business on the seventh (7th) day after you have signed the Agreement.  If revoked, this Agreement shall not be effective and enforceable, and you will not receive payments or benefits under Section 14(d) of the Severance Pay Agreement.

FOURTEEN:  This Agreement constitutes the entire agreement of the parties hereto and supersedes any and all other agreements (except the Severance Pay Agreement) with respect to the subject matter of this Agreement, whether written or oral, between you and the Company.  All modifications and amendments to this Agreement must be in writing and signed by the parties.

FIFTEEN:  Each party agrees, without further consideration, to sign or cause to be signed, and to deliver to the other party, any other documents and to take any other action as may be necessary to fulfill the obligations under this Agreement.

SIXTEEN:  If any provision of this Agreement or the application thereof is held invalid, the invalidity shall not affect other provisions or applications of the Agreement which can be given effect without the invalid provisions or application; and to this end the provisions of this Agreement are declared to be severable.

SEVENTEEN:  This Agreement may be executed in counterparts.

I have read the foregoing General Release, and I accept and agree to the provisions it contains and hereby execute it voluntarily and with full understanding of its consequences.  I am aware it includes a release of all known or unknown claims.

DATED:  __________

__________________________________________

DATED:  __________

__________________________________________

You acknowledge that you first received this Agreement on [date].

_________________________







 


SE exhibit 12.1




 

EXHIBIT 12.1

SEMPRA ENERGY

COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES

AND PREFERRED STOCK DIVIDENDS

(Dollars in millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

 

2007

 

2008(1)

 

2009(1)

 

2010(1)

 

2011(1)

 

2012

Fixed charges and preferred stock dividends:

 

 

 

 

 

 

 

 

 

 

 

 

Interest

 

$           379

 

$           353

 

$           455

 

$           492

 

$           549

 

$             438

Interest portion of annual rentals

 

6

 

3

 

2

 

3

 

2

 

2

Preferred dividends of subsidiaries (2)

 

14

 

13

 

13

 

11

 

10

 

5

     Total fixed charges

 

399

 

369

 

470

 

506

 

561

 

445

Preferred dividends for purpose of ratio

 

-

 

-

 

-

 

-

 

-

 

-

Total fixed charges and preferred dividends for purpose of ratio                        

 

$           399

 

$           369

 

$           470

 

$           506

 

$           561

 

$             445

Earnings:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Pretax income from continuing operations before adjustment for income or loss from equity investees

 

$         1,538

 

$         1,009

 

$           977

 

$         1,079

 

$         1,747

 

$          1,009

Add:

 

 

 

 

 

 

 

 

 

 

 

 

  Total fixed charges (from above)

 

399

 

369

 

470

 

506

 

561

 

445

  Distributed income of equity investees

 

19

 

133

 

493

 

260

 

96

 

37

Less:

 

 

 

 

 

 

 

 

 

 

 

 

  Interest capitalized

 

100

 

100

 

73

 

74

 

27

 

41

  Preferred dividends of subsidiaries (2)

 

10

 

10

 

13

 

11

 

10

 

5

Total earnings for purpose of ratio

 

$         1,846

 

$         1,401

 

$         1,854

 

$         1,760

 

$         2,367

 

$          1,445

 

 

 

 

 

 

 

 

 

 

 

 

 

Ratio of earnings to combined fixed charges and preferred stock dividends

 

4.63

 

3.80

 

3.94

 

3.48

 

4.22

 

3.25

 

 

 

 

 

 

 

 

 

 

 

 

 

Ratio of earnings to fixed charges

 

4.63

 

3.80

 

3.94

 

3.48

 

4.22

 

3.25

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)

As adjusted for the retrospective effect of a change in accounting principle. This change had no impact at December 31, 2007 or for the year then ended.

(2)

In computing this ratio, “Preferred dividends of subsidiaries” represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.




SDGE exhibit 12.2




 

 

 

 

 

 

 

 

 

 

 

 

 

 

EXHIBIT 12.2

SAN DIEGO GAS & ELECTRIC COMPANY

COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES

AND PREFERRED STOCK DIVIDENDS

(Dollars in millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 September 30,

 

 

2007

 

2008

 

2009

 

2010

 

2011

 

2012

Fixed Charges and Preferred Stock Dividends:

 

 

 

 

 

 

 

 

 

 

 

 

Interest

 

$            105

 

$            107

 

$            118

 

$            153

 

$            193

 

$               163

Interest portion of annual rentals

 

3

 

1

 

1

 

1

 

1

 

1

Total fixed charges

 

108

 

108

 

119

 

154

 

194

 

164

Preferred stock dividends (1)

 

7

 

7

 

7

 

7

 

7

 

6

Combined fixed charges and preferred stock dividends for purpose of ratio

 

$            115

 

$            115

 

$            126

 

$            161

 

$            201

 

$               170

Earnings:

 

 

 

 

 

 

 

 

 

 

 

 

Pretax income from continuing operations

 

$            406

 

$            451

 

$            550

 

$            531

 

$            692

 

$               552

Total fixed charges (from above)

 

108

 

108

 

119

 

154

 

194

 

164

Less: Interest capitalized

 

3

 

13

 

4

 

1

 

1

 

-

Total earnings for purpose of ratio

 

$            511

 

$            546

 

$            665

 

$            684

 

$            885

 

$               716

 

 

 

 

 

 

 

 

 

 

 

 

 

Ratio of earnings to combined fixed charges and preferred stock dividends

 

4.44

 

4.75

 

5.28

 

4.25

 

4.40

 

4.21

 

 

 

 

 

 

 

 

 

 

 

 

 

Ratio of earnings to fixed charges

 

4.73

 

5.06

 

5.59

 

4.44

 

4.56

 

4.37

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)

In computing this ratio, “Preferred stock dividends” represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.




SCG exhibit 12.3




 

 

 

 

 

 

 

 

 

 

 

 

 

EXHIBIT 12.3

SOUTHERN CALIFORNIA GAS COMPANY

COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES

AND PREFERRED STOCK DIVIDENDS

(Dollars in millions)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

September 30,

 

2007

 

2008

 

2009

 

2010

 

2011

 

2012

Fixed Charges:

 

 

 

 

 

 

 

 

 

 

 

Interest

$             72

 

$             65

 

$             74

 

$             72

 

$             77

 

$                57

Interest portion of annual rentals

3

 

2

 

1

 

2

 

1

 

1

Total fixed charges

75

 

67

 

75

 

74

 

78

 

58

Preferred stock dividends (1)

2

 

2

 

2

 

2

 

2

 

2

Combined fixed charges and preferred stock dividends for purpose of ratio

$             77

 

$             69

 

$             77

 

$             76

 

$             80

 

$                60

Earnings:

 

 

 

 

 

 

 

 

 

 

 

Pretax income from continuing operations

$            391

 

$            385

 

$            418

 

$            463

 

$            431

 

$              296

Add: Total fixed charges (from above)

75

 

67

 

75

 

74

 

78

 

58

Less: Interest capitalized

1

 

-

 

1

 

1

 

1

 

-

Total earnings for purpose of ratio

$            465

 

$            452

 

$            492

 

$            536

 

$            508

 

$              354

 

 

 

 

 

 

 

 

 

 

 

 

Ratio of earnings to combined fixed charges and preferred stock dividends

6.04

 

6.55

 

6.39

 

7.05

 

6.35

 

5.90

 

 

 

 

 

 

 

 

 

 

 

 

Ratio of earnings to fixed charges

6.20

 

6.75

 

6.56

 

7.24

 

6.51

 

6.10

 

 

 

 

 

 

 

 

 

 

 

 

 

(1)

In computing this ratio, “Preferred stock dividends” represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.




Sempra Energy Ex 31.1

EXHIBIT 31.1

CERTIFICATION


I, Debra L. Reed, certify that:


1.

I have reviewed this report on Form 10-Q of Sempra Energy;


2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:


a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and


d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):


a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



November 6, 2012


/S/  Debra L. Reed

Debra L. Reed

Chief Executive Officer




Sempra Energy Ex 31.2

EXHIBIT 31.2

CERTIFICATION


I, Joseph A. Householder, certify that:


1.

I have reviewed this report on Form 10-Q of Sempra Energy;


2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:


a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and


d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):


a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.



November 6, 2012


/S/  Joseph A. Householder

Joseph A. Householder

Chief Financial Officer




SDG&E Ex 31.3

EXHIBIT 31.3

CERTIFICATION


I, Jessie J. Knight, Jr., certify that:


1.

I have reviewed this report on Form 10-Q of San Diego Gas & Electric Company;


2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:


a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and


d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):


a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.


November 6, 2012


/S/  Jessie J. Knight, Jr.

Jessie J. Knight, Jr.

Chief Executive Officer




SDG&E Ex 31.4

EXHIBIT 31.4

CERTIFICATION


I, Robert M. Schlax, certify that:


1.

I have reviewed this report on Form 10-Q of San Diego Gas & Electric Company;


2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:


a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and


d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):


a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.


November 6, 2012


/S/  Robert M. Schlax

Robert M. Schlax

Chief Financial Officer




PE/SCG Ex 31.7

EXHIBIT 31.5

CERTIFICATION


I, Anne S. Smith, certify that:


1.

I have reviewed this report on Form 10-Q of Southern California Gas Company;


2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:


a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and


d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):


a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.


November 6, 2012


/S/  Anne S. Smith

Anne S. Smith

Chief Executive Officer




PE/SCG Ex 31.8

EXHIBIT 31.6

CERTIFICATION


I, Robert M. Schlax, certify that:


1.

I have reviewed this report on Form 10-Q of Southern California Gas Company;


2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) for the registrant and have:


a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report, based on such evaluation; and


d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and


5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):


a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and


b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.


November 6, 2012


/S/  Robert M. Schlax

Robert M. Schlax

Chief Financial Officer




Sempra Energy Ex 32.1

Exhibit 32.1



Statement of Chief Executive Officer


Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of Sempra Energy (the "Company") certifies that:


(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2012 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and


(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.




November 6, 2012

                                            

/S/  Debra L. Reed

Debra L. Reed

Chief Executive Officer





Sempra Energy Ex 32.2

Exhibit 32.2


Statement of Chief Financial Officer


Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of Sempra Energy (the "Company") certifies that:


(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2012 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and


(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.




November 6, 2012

                                          

/S/  Joseph A. Householder

Joseph A. Householder

Chief Financial Officer




SDG&E Ex 32.3

Exhibit 32.3


Statement of Chief Executive Officer


Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of San Diego Gas & Electric Company (the "Company") certifies that:


(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2012 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and


(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.




November 6, 2012

                                             

/S/  Jessie J. Knight, Jr.

Jessie J. Knight, Jr.

Chief Executive Officer






SDG&E Ex 32.4

Exhibit 32.4


Statement of Chief Financial Officer


Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of San Diego Gas & Electric Company (the "Company") certifies that:


(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2012 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and


(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.




November 6, 2012

                                                

/S/  Robert M. Schlax

Robert M. Schlax

Chief Financial Officer




PE/SCG Ex 32.7

Exhibit 32.5


Statement of Chief Executive Officer


Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Executive Officer of Southern California Gas Company (the "Company") certifies that:


(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2012 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and


(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.




November 6, 2012

                                                

/S/  Anne S. Smith

Anne S. Smith

Chief Executive Officer





PE/SCG Ex 32.8

Exhibit 32.6


Statement of Chief Financial Officer


Pursuant to 18 U.S.C. Sec 1350, as created by Section 906 of the Sarbanes-Oxley Act of 2002, the undersigned Chief Financial Officer of Southern California Gas Company (the "Company") certifies that:


(i)

the Quarterly Report on Form 10-Q of the Company filed with the Securities and Exchange Commission for the quarter ended September 30, 2012 (the "Quarterly Report") fully complies with the requirements of Section 13(a) or Section 15(d), as applicable, of the Securities Exchange Act of 1934, as amended; and


(ii)

the information contained in the Quarterly Report fairly presents, in all material respects, the financial condition and results of operations of the Company.




November 6, 2012


                                               

/S/  Robert M. Schlax

Robert M. Schlax

Chief Financial Officer