NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: BUSINESS COMBINATION

On June 26, 1998, Enova Corporation (Enova), the parent company of San Diego Gas & Electric (SDG&E or the Company), and Pacific Enterprises (PE), parent company of Southern California Gas Company (SoCalGas), combined into a new company named Sempra Energy (Parent). As a result of the combination, (i) each outstanding share of common stock of Enova was converted into one share of common stock of Sempra Energy, (ii) each outstanding share of common stock of PE was converted into 1.5038 shares of common stock of Sempra Energy and (iii) the preferred stock and preference stock of the combining companies and their subsidiaries remained outstanding.

NOTE 2: SIGNIFICANT ACCOUNTING POLICIES

Principles of Consolidation

The Consolidated Financial Statements include the accounts of SDG&E and its sole subsidiary, SDG&E Funding LLC. The Company's policy is to consolidate subsidiaries that are more than 50 percent owned and controlled. All material intercompany accounts and transactions have been eliminated.

Effects of Regulation

The accounting policies of SDG&E conform with generally accepted accounting principles for regulated enterprises and reflect the policies of the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC).
SDG&E has been preparing its financial statements in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," under which a regulated utility may record a regulatory asset if it is probable that, through the ratemaking process, the utility will recover that asset from customers. Regulatory liabilities represent future reductions in rates for amounts due to customers. To the extent that portions of the utility operations were to be no longer subject to SFAS No. 71, or recovery was to be no longer probable as a result of changes in regulation or their competitive position, the related regulatory assets and liabilities would be written off. In addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," affects utility plant and regulatory assets such that a loss must be recognized whenever a regulator excludes all or part of an asset's cost from rate base. As discussed in Note 12, California enacted a law restructuring the electric-utility industry. The law adopts the December 1995 CPUC policy decision, and allows California electric utilities the opportunity to recover existing utility plant and regulatory assets over a transition period that ends in 2001. In 1997, SDG&E ceased the application of SFAS No. 71 with respect to its electric- generation business. The application of SFAS No. 121 continues to be evaluated as industry restructuring progresses. Additional information concerning regulatory assets and liabilities is described below in "Revenues and Regulatory Balancing Accounts" and in Note 12.

Revenues and Regulatory Balancing Accounts

Revenues from utility customers consist of deliveries to customers and the changes in regulatory balancing accounts.
Prior to 1998, earnings fluctuations from changes in the costs of fuel oil, purchased energy and natural gas, and consumption levels for electricity and the majority of natural gas were eliminated by balancing accounts authorized by the CPUC. This is still the case for most natural gas operations. However, as a result of California's electric-restructuring law, overcollections recorded in SDG&E's Energy Cost Adjustment Clause and Electric Revenue Adjustment Mechanism balancing accounts were transferred to the Interim Transition Cost Balancing Account, which has been applied to transition cost recovery, and fluctuations in certain costs and consumption levels can now affect earnings from electric operations. Additional information on electric-industry restructuring is included in Note 12.

Regulatory Assets

Regulatory assets include unrecovered premium on early retirement of debt, post-retirement benefit costs, deferred income taxes recoverable in rates and other regulatory-related expenditures that the Company expects to recover in future rates. See Note 12 for additional information.

Inventories

Included in inventories at December 31, 1999, are $50 million of utility materials and supplies ($48 million in 1998), and $11 million of natural gas and fuel oil ($29 million in 1998). Materials and supplies are generally valued at the lower of average cost or market; fuel oil and natural gas are valued by the last-in first-out method.

Utility Plant

This primarily represents the buildings, equipment and other facilities used by SDG&E to provide natural gas and electric utility service. The cost of utility plant includes labor, materials, contract services and related items, and an allowance for funds used during construction. The cost of retired depreciable utility plant, plus removal costs minus salvage value, is charged to accumulated depreciation. Information regarding electric- industry restructuring and its effect on utility plant is included in Note 12. Utility plant balances by major functional categories at December 31, 1999, are: electric distribution $2.5 billion, electric transmission $0.7 billion, other electric $0.4 billion and natural gas operations $0.9 billion. The corresponding amounts at December 31, 1998, were essentially the same, except that other electric decreased by $0.5 billion in 1999 in connection with electric industry restructuring, as described in Note 12. Accumulated depreciation and decommissioning of electric and natural gas utility plant in service at December 31, 1999, are $1.8 billion and $0.5 billion, respectively, and at December 31, 1998, were $2.2 billion and $0.4 billion, respectively. Depreciation expense is based on the straight-line method over the useful lives of the assets or a shorter period prescribed by the CPUC. The provisions for depreciation as a percentage of average depreciable utility plant (by major functional categories) in 1999, 1998, and 1997, respectively are: electric generation 8.70, 6.49, 5.60, electric distribution 4.69, 4.49, 4.39, electric transmission 3.50, 3.31, 3.28, other electric 8.21, 6.29, 6.02, and natural gas operations 3.83, 4.01, 4.03. The increases for electric generation reflect the accelerated recovery of generation facilities in 1999 and 1998 and the increase in depreciation rates resulting from the 1999 Cost of Service proceeding. The increase in 1999 for other electric is due to the increase in depreciation rates resulting from the 1999 Cost of Service proceeding. See Note 12 for additional discussion of generation facilities and industry restructuring.

Allowance for Funds Used During Construction (AFUDC)

The allowance represents the cost of funds used to finance the construction of utility plant and is added to the cost of utility plant. AFUDC also increases income, as an offset to interest charges shown in the Statements of Consolidated Income, although it is not a current source of cash.

Nuclear-Decommissioning Liability

Deferred credits and other liabilities at December 31, 1999, include $165 million ($146 million in 1998) of accumulated decommissioning costs associated with SDG&E's San Onofre Nuclear Generating Station (SONGS) Unit 1, which was permanently shut down in 1992. Additional information on SONGS Unit 1 decommissioning costs is included in Note 5. The corresponding liability for Units 2 and 3 is included in accumulated depreciation and amortization.

Comprehensive Income

SFAS No. 130, "Reporting Comprehensive Income." requires reporting of comprehensive income and its components (revenues, expenses, gains and losses) in any complete presentation of general-purpose financial statements. Comprehensive income describes all changes, except those resulting from investments by owners and distributions to owners, in the equity of a business enterprise from transactions and other events including, as applicable, minimum pension liability adjustments.

Use of Estimates in the Preparation of the Financial Statements

The preparation of the consolidated financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

Cash equivalents are highly liquid investments with original maturities of three months or less, or investments that are readily convertible to cash.

Basis of Presentation

Certain prior-year amounts have been reclassified to conform to the current year's presentation.

New Accounting Standard

In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 133 "Accounting for Derivative Instruments and Hedging Activities." In June 1999, the effective date of this statement was deferred for one year. As amended, SFAS 133, which is effective for the company on January 1, 2001, requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value and recognize changes in the fair value of derivatives in earnings in the period of change unless the derivative qualifies as an effective hedge that offsets certain exposures. The effect of this standard on the company's Consolidated Financial Statements has not yet been determined.

NOTE 3: SHORT-TERM BORROWINGS

At December 31, 1999, SDG&E had $205 million of bank lines available to support commercial paper and variable-rate, long-term debt. The credit agreements expire at varying dates from 2000 through 2002 and bear interest at various rates based on market rates and the Company's credit rating. SDG&E's bank lines of credit were unused at both December 31, 1999, and 1998.

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                                                 December 31,
(Dollars in millions)                         1999         1998
-------------------------------------------------------------------
First Mortgage Bonds
  7.625% June 15, 2002                      $   28       $   28
  6.800% June 1, 2015                           14           14
  5.900% June 1, 2018                           68           71
  5.900% September 1, 2018                      93           93
  6.100% September 1, 2018                      40           40
  6.400% September 1, 2018                      43           43
  6.100% September 1, 2019                      35           35
  9.625% April 15, 2020                         10           10
  Variable rates September 1, 2020              58           58
  5.850% June 1, 2021                           60           60
  8.500% April 1, 2022                          10           10
  5.420% December 1, 2027                       45           45
  6.400% December 1, 2027                       75           75
  Variable rates December 1, 2027              105          130
                                           ------------------------
                                               684          712
                                           ------------------------
Unsecured Bonds
  5.900% June 1, 2014                          130          130
  Variable % July 1, 2021                       39           39
  Variable % December 1, 2021                   60           60
  Variable % March 1, 2023                      25           25
                                           ------------------------
                                               254          254
                                           ------------------------
Rate-reduction bonds                           526          592
Capital leases                                  21           63
                                           ------------------------
    Total                                    1,485        1,621

Less:
  Current portion of long-term debt             66           72
  Unamortized debt discount less premium         1            1
                                           ------------------------
Total                                       $1,418       $1,548
-------------------------------------------------------------------

Excluding capital leases, which are described in Note 11, maturities of long-term debt, including rate-reduction bonds, are $66 million in 2000, $66 million in $2001, $94 million in 2002, $66 million in 2003, $66 million in 2004 and $1,106 million thereafter. SDG&E has CPUC authorization to issue an additional $138 million in long-term debt. Although holders of variable-rate bonds may elect to redeem them prior to scheduled maturity, for purposes of determining the maturities listed above, it is assumed the bonds will be held to maturity.

First-Mortgage Bonds

First-mortgage bonds are secured by a lien on substantially all of SDG&E's utility plant. SDG&E may issue additional first-mortgage bonds upon compliance with the provisions of their bond indentures, which permit, among other things, the issuance of an additional $712 million of first-mortgage bonds as of December 31, 1999.
In 1999, SDG&E retired $28 million of first-mortgage bonds prior to scheduled maturity.

Callable Bonds

At SDG&E's option, certain first-mortgage bonds may be called at a premium. SDG&E has $287 million of variable-rate bonds with provisions that are callable at various dates within one year. Of the Company's remaining callable bonds, $55 million are callable in the year 2000, $204 million in the year 2002 and $221 million in 2003.

Rate-Reduction Bonds

In December 1997, $658 million of rate-reduction bonds were issued on behalf of SDG&E at an average interest rate of 6.26 percent. These bonds were issued to facilitate the 10-percent rate reduction mandated by California's electric-restructuring law. See Note 12 for additional information. These bonds are being repaid over 10 years by SDG&E's residential and small commercial customers via a charge on their electricity bills. These bonds are secured by the revenue streams collected from customers and are not secured by, or payable from, utility assets.
The sizes of the rate-reduction bond issuances were set so as to make the utilities neutral as to the 10-percent rate reduction, and were based on a four-year period to recover stranded costs. Because SDG&E recovered its stranded costs in only 18 months (due to the greater-than-anticipated plant-sale proceeds), its bond proceeds were greater than needed. Accordingly, SDG&E will return to its customers over $400 million that it has collected or will collect from its customers. The timing of the return will differ from the timing of the collection, but the specific timing of the repayment and the interest rate thereon are the subject of a CPUC proceeding and are expected to be resolved in early 2000. This refund will not affect SDG&E's net income, except to the extent that the interest associated with the refund (12.63 percent if not reduced as a result of the CPUC proceeding) differs from the return earned by the Company on the funds. The bonds and their repayment schedule are not affected by this refund.

Unsecured Debt

Various long-term obligations totaling $254 million are unsecured. Unsecured bonds totaling $124 million have variable-interest-rate provisions.

Interest Rate Swaps

SDG&E periodically enters into interest-rate swap and cap agreements to moderate its exposure to interest-rate changes and to lower its overall cost of borrowings. At December 31, 1999, SDG&E had such an agreement, maturing in 2002, with underlying debt of $45 million.

-----------------------------------------------------------
(Dollars in millions)                         Southwest
Project                            SONGS      Powerlink
-----------------------------------------------------------
Percentage ownership                  20             89
Utility plant in service         $    57       $    217
Accumulated depreciation
  and amortization               $    25       $    111
Construction work in progress    $     7       $      1
-----------------------------------------------------------

The Company's share of operating expenses is included in the Statements of Consolidated Income. Each participant in the project must provide its own financing. The amounts specified above for SONGS include nuclear production, transmission and other facilities. Certain substation equipment included in these amounts is wholly owned by the Company.

SONGS Decommissioning

Objectives, work scope and procedures for the future dismantling and decontamination of the SONGS units must meet the requirements of the Nuclear Regulatory Commission, the Environmental Protection Agency, the California Public Utilities Commission and other regulatory bodies.
The Company's share of decommissioning costs for the SONGS units is estimated to be $432 million in today's dollars and is based on a cost study completed in 1998. Cost studies are performed and updated periodically by outside consultants. The recovery of decommissioning costs is allowed until the time that the costs are fully recovered.
The amount accrued each year is based on the amount allowed by regulators and is currently being collected in rates. This amount is considered sufficient to cover the Company's share of future decommissioning costs. Payments to the nuclear-decommissioning trusts are expected to continue until SONGS is decommissioned, which is not expected to occur before 2013. Unit 1, although permanently shut down in 1992, was scheduled to be decommissioned concurrently with Units 2 and 3. However, the Company and the other owner of Unit 1 received the required regulatory approvals to begin decommissioning Unit 1 in January 2000.
The amounts collected in rates are invested in externally managed trust funds. The securities held by the trust are considered available for sale and shown on the Consolidated Balance Sheets at market value. These values reflect unrealized gains of $164 million and $149 million at December 31, 1999, and 1998, respectively.
The Financial Accounting Standards Board is reviewing the accounting for liabilities related to closure and removal of long- lived assets, such as nuclear power plants, including the recognition, measurement and classification of such costs. The Board could require, among other things, that the Company's future balance sheets include a liability for the estimated decommissioning costs, and a related increase in the carrying value of the asset.
Additional information regarding SONGS is included in Notes 11 and 12.

                                     1999     1998     1997
-------------------------------------------------------------
Statutory federal income tax rate    35.0%    35.0%    35.0%
Depreciation                          5.2      1.3      6.8
State income taxes - net of
  federal income tax benefit          5.9      5.6      5.7
Tax credits                          (2.1)    (1.7)    (1.3)
Charitable contribution of plant     (7.9)      -        -
Other - net                           2.6      2.4      1.7
                                  ---------------------------
    Effective income tax rate        38.7     42.6%    47.9%
-------------------------------------------------------------

Accumulated deferred income taxes at December 31 result from the following:

-------------------------------------------------------------
(Dollars in millions)                     1999        1998
-------------------------------------------------------------
Deferred tax liabilities
  Differences in financial and
    tax bases of utility plant         $   382       $   440
  Regulatory balancing accounts            150           74
  Loss on reacquired debt                   30           34
  Other                                     70           71
                                  ---------------------------
  Total deferred tax liabilities           632          619
                                  ---------------------------
Deferred tax assets
  Investment tax credits                    61           63
  Other                                    138          122
                                  ---------------------------
  Total deferred tax assets                199          185
                                  ---------------------------
Net deferred income tax liability          433          434
-------------------------------------------------------------

The net liability is recorded on the consolidated balance sheet as follows:

-------------------------------------------------------------
 (Dollars in millions)                     1999         1998
-------------------------------------------------------------
Current liability(asset)                 $ 106        $  37
Non-current liability                      327          397
-------------------------------------------------------------
Total                                    $ 433        $ 434
-------------------------------------------------------------

The components of income tax expense are as follows:

-------------------------------------------------------------
(Dollars in millions)            1999       1998      1997
-------------------------------------------------------------
Current
  Federal                        $   90    $  150   $  164
  State                              39        41       44
                                  ---------------------------
    Total current taxes             129       191      208
                                  ---------------------------
Deferred
  Federal                            11       (30)      13
  State                             ( 9)      (16)       2
                                  ---------------------------
    Total deferred taxes              2       (46)      15
                                  ---------------------------
Deferred investment
  tax credits - net                  (5)       (3)      (4)
                                  ---------------------------
Total income tax expense         $  126    $  142   $  219
-------------------------------------------------------------

Federal and state income taxes are allocated between operating income and other income.

NOTE 7: EMPLOYEE BENEFIT PLANS

The information presented below describes the plans of the Company. In connection with the PE/Enova business combination numerous participants were transferred from the Company's plans to plans of related entities. In connection therewith, the company recorded a $9 million special termination benefit in 1998.

-------------------------------------------------------------------------------
                                                                 Other
                                   Pension Benefits      Postretirement Benefits
                                -----------------------------------------------
(Dollars in millions)                1999      1998           1999        1998
--------------------------------------------------------------------------------
Weighted-Average Assumptions
  as of December 31:
Discount rate                        7.75%     6.75%          7.75%       6.75%
Expected return on plan assets       8.00%     8.50%          4.00%       4.50%
Rate of compensation increase        5.00%     5.00%          5.00%       5.00%
Cost trend of covered
  health-care charges                   -         -           7.75%(1)    8.00%(1)

Change in Benefit Obligation:
Net benefit obligation at
  January 1                        $  494    $  605          $  48        $  43
Service cost                           11        19              1            1
Interest cost                          34        43              3            3
Plan Participants' contributions        -         -              2            -
Plan amendments                         -        (3)             -            -
Actuarial (gain) loss                   4       (17)            (4)           5
Transfer of liability (2)             (15)     (112)             -            -
Special termination benefits            -         9              -            -
Gross benefits paid                   (52)      (50)            (5)          (4)
                                  -----------------------------------------------
Net benefit obligation at
  December 31                         476       494             45           48
                                  -----------------------------------------------
Change in Plan Assets:
Fair value of plan assets
  at January 1                        587       699             17           14
Actual return on plan assets          178       103              -            1
Employer contributions                  -         1              4            6
Plan Participants' contributions       -          -              2            -
Transfer of assets (2)                  -      (166)             -            -
Gross benefits paid                   (52)      (50)            (5)          (4)
                                  -----------------------------------------------
Fair value of plan assets
  at December 31                      713       587              18           17
                                  -----------------------------------------------
Funded status at December 31          237        93             (27)         (31)
Unrecognized net actuarial
  (gain) loss                        (317)     (196)             (2)           1
Unrecognized prior service cost        20        23               -            -
                                  -----------------------------------------------
Net liability at December 31        $ (60)    $ (80)          $ (29)       $ (30)
--------------------------------------------------------------------------------
(1) Decreasing to ultimate trend of 6.50% in 2004.
(2) To reflect transfer of plan assets and liability to Sempra Energy.

The following table provides the components of net periodic benefit cost (income) for the plans:

---------------------------------------------------------------------------------
                                                                  Other
                                     Pension Benefits     Postretirement Benefits
                                  -----------------------------------------------
(Dollars in millions)               1999   1998   1997     1999     1998     1997
                                  -----------------------------------------------
Service cost                        $ 11   $ 19   $ 18     $  1     $  1     $  1
Interest cost                         34     43     40        3        3        3
Expected return on assets            (47)   (60)   (50)       -       (1)       -
Amortization of:
  Transition obligation                -      -      -        2        2        2
  Prior service cost                   3      3      3        -        -        -
  Actuarial gain                      (9)   (11)    (9)       -        -        -
Special termination benefit            -      9      -        -        -        -
Regulatory adjustment                  -      -      -        -        -       (1)
                                  -----------------------------------------------
Total net periodic benefit cost     $ (8)  $  3   $  2      $ 6      $ 5      $ 5
  (income)
---------------------------------------------------------------------------------

The following table provides the amounts recognized on the SDG&E balance sheet at December 31.

<caption
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                                                                        Other
                                        Pension Benefits      Postretirement Benefits
                                       ----------------------------------------------
(Dollars in millions)                     1999      1998         1999       1998
-------------------------------------------------------------------------------------
Prepaid benefit cost                         -         -            -          -
Accrued benefit cost                      $(57)     $(80)        $(29)      $(30)
Additional minimum liability                 -         -            -          -
Intangible asset                             -         -            -          -
Accumulated other
  comprehensive income                     ( 3)        -            -          -
-------------------------------------------------------------------------------------
Net liability                              (60)      (80)         (29)       (30)
-------------------------------------------------------------------------------------

(Dollars in millions)                      1% Increase     1% Decrease
-----------------------------------------------------------------------
Effect on total of service and interest cost
  components of net periodic postretirement
  health care benefit cost                         --             --

Effect on the health care component of the
  accumulated postretirement benefit obligation  $  2           $ (1)
------------------------------------------------------------------------

Other postretirement benefits include medical benefits for retirees and their spouses and retiree life insurance.

Savings Plans

SDG&E offers a savings plan, administered by plan trustees, to all eligible employees. Eligibility to participate in the plan begins after one month of service. Employees may contribute, subject to plan provisions, from 1 percent to 15 percent of their regular earnings. The employees' contributions, at the direction of the employees, are primarily invested in Sempra Energy stock or mutual funds. Employer contributions, after one year of service, are made in shares of Sempra Energy stock. Employer contributions are equal to 50 percent of the first 6 percent of eligible base salary contributed by employees. During 1999, SDG&E's plan contribution was age-based for represented employees. Annual expense for the savings plans was $4 million in 1999, $5 million in 1998 and $3 million in 1997.

NOTE 8: STOCK-BASED COMPENSATION

Sempra Energy has stock-based compensation plans that align employee and shareholder objectives related to Sempra Energy's long-term growth. The long-term incentive stock compensation plan provides for aggregate awards of Sempra Energy non-qualified stock options, incentive stock options, restricted stock, stock appreciation rights, performance awards, stock payments or dividend equivalents.
In 1995, Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based compensation," was issued. It encourages a fair-value-based method of accounting for stock-based compensation. As permitted by SFAS No. 123, Sempra Energy and its subsidiaries adopted the statement's disclosure-only requirements and continue to account for stock-based compensation in accordance with the provisions of accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." To the extent that subsidiary employees participate in the plans or that subsidiaries are allocated a portion of Sempra Energy's costs of the plans, the subsidiaries record an expense for the plans. SDG&E recorded expenses of $2 million in 1998 and $1 million in 1997.

NOTE 9: FINANCIAL INSTRUMENTS

Fair Value

The fair values of the Company's financial instruments are not materially different from the carrying amounts, except for long- term debt and preferred stock. The carrying amounts and fair values of long-term debt are $1,484 million and $1,465 million, respectively, at December 31, 1999, and $1,620 million and $1,679 million at December 31, 1998. Included in long-term debt are SDG&E's rate-reduction bonds. The carrying amounts and fair values of the bonds are $526 million and $511 million, respectively, at December 31, 1999, and $592 million and $607 million, respectively, at December 31, 1998. The carrying amounts and fair values of preferred stock are $104 million and $97 million, respectively, at December 31, 1999, and $104 million and $105 million, respectively, at December 31, 1998. The fair values of the first-mortgage and other bonds and preferred stock are estimated based on quoted market prices for them or for similar issues. The fair values of long-term notes payable are based on the present value of the future cash flows, discounted at rates available for similar notes with comparable maturities.

Off-Balance-Sheet Financial Instruments

The Company's policy is to use derivative financial instruments to manage its exposure to fluctuations in interest rates, foreign- currency exchange rates and energy prices. Transactions involving these financial instruments expose the Company to market and credit risks which may at times be concentrated with certain counterparties, although counterparty nonperformance is not anticipated.

Swap Agreements

The Company periodically enters into interest-rate-swap and cap agreements to moderate exposure to interest-rate changes and to lower the overall cost of borrowing. These agreements generally remain off the balance sheet as they involve the exchange of fixed- and variable-rate interest payments without the exchange of the underlying principal amounts. The related gains or losses are reflected in the consolidated income statement as part of interest expense.
At December 31, 1999, and 1998, the Company had one interest- rate-swap agreement: a floating-to-fixed-rate swap associated with $45 million of variable-rate bonds maturing in 2002. SDG&E expects to hold this financial instrument to its maturity. This swap agreement has effectively fixed the interest rate on the underlying variable-rate debt at 5.4 percent. SDG&E would be exposed to interest-rate fluctuations on the underlying debt should the counterparty to the agreement not perform. Such nonperformance is not anticipated. This agreement, if terminated, would result in an obligation of $1.3 million at December 31, 1999, and $3 million at December 31, 1998. Additional information on this topic is included in Note 4.

Energy Derivatives

The Company uses energy derivatives for price-risk management purposes within certain limitations imposed by Company policies and regulatory requirements. Energy derivatives are used to mitigate risk and better manage costs. These instruments include forward contracts, swaps, options and other contracts which have maturities ranging from 30 days to 12 months.
For the years ended December 31, 1999, 1998, and 1997, gains and losses from these activities are not material to SDG&E's financial statements.

--------------------------------------------------------------
                                             December 31,
(Dollars in millions)                      1999        1998
--------------------------------------------------------------
COMMON EQUITY
Common stock, without par value,
  authorized 255,000,000 shares          $  857      $  857
Retained earnings                           460         267
Accumulated other comprehensive income       (3)         --
                                        ----------------------
    Total common equity                  $1,314      $1,124
--------------------------------------------------------------

All shares of SDG&E common stock are owned by Enova Corporation.

---------------------------------------------------------------
                                          Call     December 31,
(Dollars in millions except call price)   Price    1999   1998
---------------------------------------------------------------
PREFERRED STOCK
Not subject to mandatory redemption
   $20 par value, authorized
     1,375,000 shares:
      5% Series, 375,000
        shares outstanding               $ 24.00   $ 8    $ 8
      4.50% Series, 300,000
        shares outstanding               $ 21.20     6      6
      4.40% Series, 325,000
        shares outstanding               $ 21.00     7      7
      4.60% Series, 373,770
        shares outstanding               $ 20.25     7      7
  Without par value:
      $1.70 Series, 1,400,000
        shares outstanding               $ 25.85    35     35
      $1.82 Series, 640,000
        shares outstanding               $ 26.00    16     16
                                                 --------------
    Total not subject to
      mandatory redemption                         $79    $79
 ---------------------------------------------------------------

---------------------------------------------------------------
                                          Call     December 31,
(Dollars in millions except call price)   Price    1999   1998
---------------------------------------------------------------
PREFERRED STOCK
Subject to mandatory redemption
  Without par value
      $1.7625 Series, 1,000,000
        shares outstanding               $ 25.00   $25    $25
---------------------------------------------------------------

All series of SDG&E's preferred stock have cumulative preferences as to dividends. The $20 par value preferred stock has two votes per share on matters being voted upon by shareholders of SDG&E and a liquidation value at par, whereas the no par value preferred stock is nonvoting and has a liquidation value of $25 per share. SDG&E is authorized to issue 10,000,000 shares of no par value stock (both subject to and not subject to mandatory redemption). All series are currently callable except for the $1.70 and $1.7625 series (callable in 2003). The $1.7625 series has a sinking fund requirement to redeem 50,000 shares per year from 2003 to 2007; the remaining 750,000 shares must be redeemed in 2008.

NOTE 11: CONTINGENCIES AND COMMITMENTS

Natural Gas Contracts
The company buys natural gas under several short-term and long-term contracts. Short-term purchases are primarily from various Southwest U.S. suppliers and are based on monthly spot-market prices. SDG&E natural gas purchases are primarily from various U.S. Southwest gas supplies and are based on monthly spot-market prices. SDG&E has long-term capacity contracts with interstate pipelines which expire on various dates between 2007 and 2023. These agreements provide for payments of an annual reservation charge. SDG&E recovers such fixed charges in rates.
SDG&E had been involved in negotiations and litigation with four Canadian suppliers concerning contract terms and prices related to long-term natural gas supply contracts. In 1999, SDG&E settled with the last of the four suppliers, terminating the contract. SDG&E continues to purchase natural gas from one of the suppliers under terms of the settlement agreement. SDG&E purchases natural gas on a spot basis to fill any additional long-term pipeline capacity. SDG&E intends to continue using the long-term pipeline capacity in other ways as well, including the transport of replacement natural gas and the release of a portion of this capacity to third parties. All of SDG&E's gas is delivered through SoCalGas pipelines under a short-term transportation agreement. In addition, SoCalGas provides SDG&E six billion cubic feet of natural gas storage capacity under an agreement expiring March 2001 At December 31, 1999, the future minimum payments under natural gas contracts were:

-----------------------------------------------------------------
                               Storage and
(Dollars in millions)       Transportation          Natural Gas
-----------------------------------------------------------------
2000                              $  14                   23
2001                                 11                   23
2002                                  9                   24
2003                                 11                   14
2004                                 14                    -
Thereafter                          196                    -
                               ----------------------------------
Total minimum payments            $ 255                   84
-----------------------------------------------------------------

Total payments under the contracts were $220 million in 1999, $324 million in 1998 and $335 million in 1997.

Purchased-Power Contracts

SDG&E buys electric power under several long-term contracts. The contracts expire on various dates between 2000 and 2025. Under California's electric-industry restructuring law, which is described in Note 12, the above market cost of these contracts is recovered from virtually all of SDG&E's customers. In general, the market value of these contracts is recovered by bidding them into the California Power Exchange (PX) and receiving revenue from the PX for bids accepted.

At December 31, 1999, the estimated future minimum payments under the long-term contracts were:

-----------------------------------------------------------------
2000                                                    $  198
2001                                                       180
2002                                                       133
2003                                                       133
2004                                                       127
Thereafter                                               2,046
                                                       ----------
Total minimum payments                                  $2,817
-----------------------------------------------------------------

The payments represent capacity charges and minimum energy purchases. SDG&E is required to pay additional amounts for actual purchases of energy that exceed the minimum energy commitments. Total payments, under the contracts were $251 million in 1999, $293 million in 1998 and $421 million in 1997.

Leases

SDG&E has capital and operating leases on real and personal property expiring at various dates from 2000 to 2037. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 2 percent to 7 percent. The rentals payable under these leases are determined on both fixed and percentage bases, and most leases contain options to extend, which are exercisable by the Company. The Company also has nuclear fuel and real property that are financed by long-term capital leases. Property, plant and equipment included $46 million at December 31, 1999, and $177 million at December 31, 1998 related to these leases. The associated accumulated amortization is $24 million and $114 million, respectively.

The minimum rental commitments payable in future years under all noncancellable leases are:

-----------------------------------------------------------------
                                     Operating     Capitalized
(Dollars in millions)                   Leases          Leases
-----------------------------------------------------------------
2000                                    $ 13             $23
2001                                      12               -
2002                                      11               -
2003                                       8               -
2004                                       7               -
Thereafter                                26               -
                                   ------------------------------
Total future rental commitment          $ 77              23
Imputed interest (5% to 6%)                               (2)
                                                      -----------
Net commitment                                           $21
-----------------------------------------------------------------

Rent expense totaled $39 million in 1999, $50 million in 1998 and $43 million in 1997.

Other Commitments and Contingencies

At December 31, 1999, commitments for capital expenditures were approximately $10 million.

Environmental Issues

The Company believes that its operations are subject to federal, state and local environmental laws and regulations governing hazardous wastes, air and water quality, land use, solid waste disposal and the protection of wildlife. SDG&E incurs significant costs to operate its facilities in compliance with these laws and regulations and these costs generally have been recovered in customer rates.
In 1994, the CPUC approved the Hazardous Waste Collaborative Memorandum account allowing utilities to recover their hazardous waste costs, including those related to Superfund sites or similar sites requiring cleanup. Recovery of 90 percent of cleanup costs and related third-party litigation costs and 70 percent of the related insurance-litigation expenses is permitted. In addition, the Company has the opportunity to retain a percentage of any insurance recoveries to offset the 10 percent of costs not recovered in rates. Environmental liabilities that may arise are recorded when remedial efforts are probable and the costs can be estimated.
SDG&E's capital expenditures to comply with environmental laws and regulations were $160,000 in 1999, $1 million in 1998 and $4 million in 1997, and are not expected to be significant over the next five years due to the sale of the Company's fossil fuel power plants. SDG&E has been associated with various sites which may require remediation under federal, state or local environmental laws. SDG&E is unable to fully determine the extent of its responsibility for remediation of these sites until assessments are completed. Furthermore, the number of others that also may be responsible, and their ability to share in the cost of the cleanup, is not known.
As discussed in Note 12, restructuring of the California electric-utility industry has changed the way utility rates are set and costs are recovered. In 1998, the CPUC modified the Hazardous Waste Collaborative mechanism by providing that electric generation-related cleanup costs be eligible for transition-cost recovery. The effect of this decision is that SDG&E's costs of compliance with environmental regulations may not be fully recoverable.

Nuclear Insurance

SDG&E and the co-owners of SONGS have purchased primary insurance of $200 million, the maximum amount available, for public-liability claims. An additional $9.5 billion of coverage is provided by secondary financial protection required by the Nuclear Regulatory Commission and provides for loss sharing among utilities owning nuclear reactors if a costly accident occurs. SDG&E could be assessed retrospective premium adjustments of up to $36 million in the event of a nuclear incident involving any of the licensed, commercial reactors in the United States, if the amount of the loss exceeds $200 million. In the event the public-liability limit stated above is insufficient, the Price-Anderson Act pro-vides for Congress to enact further revenue-raising measures to pay claims, which could include an additional assessment on all licensed reactor operators. Insurance coverage is provided for up to $2.8 billion of property damage and decontamination liability. Coverage is also provided for the cost of replacement power, which includes indemnity payments for up to three years, after a waiting period of 12 weeks. Coverage is provided primarily through mutual insurance companies owned by utilities with nuclear facilities. If losses at any of the nuclear facilities covered by the risk-sharing arrangements were to exceed the accumulated funds available from these insurance programs, SDG&E could be assessed retrospective premium adjustments of up to $5 million.

Department of Energy Decommissioning

The Energy Policy Act of 1992 established a fund for the decontamination and decommissioning of the Department of Energy nuclear-fuel-enrichment facilities. Utilities which have used DOE enrichment services are being assessed a total of $2.3 billion, subject to adjustment for inflation, over a 15-year period ending in 2006. Each utility's share is based on its share of enrichment services purchased from the DOE through 1992. SDG&E's annual assessment is approximately $1 million. This assessment is recovered through SONGS revenue.
The Nuclear Waste Policy Act of 1982 made the DOE responsible for the disposal of nuclear fuel and other radioactive waste. However, it is uncertain when the DOE will begin accepting nuclear fuel from SONGS. Continued delays by the DOE can lead to increased cost of disposal, which could be significant. If this occurs and the Company is unable to recover the increased costs from the federal government or from its customers, the Company's profitability from SONGS would be adversely affected.

Litigation

The Company is involved in various legal matters, including those arising out of the ordinary course of business. Management believes that these matters will not have a material adverse effect on the Company's results of operations, financial condition or liquidity.

Electric Distribution System Conversion

Under a CPUC-mandated program and through franchise agreements with various cities, SDG&E is committed, in varying amounts, to converting overhead distribution facilities to underground. As of December 31, 1999, the aggregate unexpended amount of this commitment was approximately $105 million. Capital expenditures for underground conversions were $20 million in 1999, and $17 million in 1998 and 1997.

Concentration of Credit Risk

SDG&E maintains credit policies and systems to minimize overall credit risk. These policies include, when applicable, the use of an evaluation of potential counterparties' financial condition and an assignment of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. SDG&E grants credit to its utility customers, substantially all of whom are located in SDG&E's service territory, which covers all of San Diego County and an adjacent portion of Orange County.

NOTE 12: REGULATORY MATTERS

Electric-Industry Restructuring

In September 1996, California enacted a law restructuring its electric-utility industry (AB 1890). The legislation adopts the December 1995 CPUC policy decision restructuring the industry to stimulate competition and reduce rates.
Beginning on March 31, 1998, customers were given the opportunity to choose to continue to purchase their electricity from the local utility under regulated tariffs, to enter into contracts with other energy-service providers (direct access) or to buy their power from the PX that serves as an independent wholesale power pool allowing all energy producers to participate competitively. The PX obtains its power from qualifying facilities, from nuclear units and, lastly, from the lowest-bidding suppliers. California's investor-owned utilities (IOUs) are obligated to sell their power supply, including owned generation and purchased-power contracts, to the PX. The IOUs are also obligated to purchase from the PX the power that they distribute. An Independent System Operator (ISO) schedules power transactions and access to the transmission system. The local utility continues to provide distribution service regardless of which source the consumer chooses. Purchases from the PX/ISO are included in purchased-power expenses and PX/ISO power revenues have been netted therein on the Statements of Consolidated Income. Revenues from the PX/ISO reflect sales to the PX/ISO commencing April 1, 1998, at market prices of energy from SDG&E's power plants and from long-term purchased-power contracts.
Utilities were allowed a reasonable opportunity to recover their stranded costs via a competition transition charge (CTC) to customers through December 31, 2001. Stranded costs include sunk costs, as well as ongoing costs the CPUC finds reasonable and necessary to maintain generation facilities through December 31, 2001. These costs also include other items the utilities had recorded under traditional cost-of-service regulation. Certain stranded costs, such as those related to reasonable employee- related costs directly caused by restructuring, and purchased-power contracts (including those with qualifying facilities) may be recovered beyond December 31, 2001. Outside of those exceptions, any stranded costs not recovered through 2001 would not be collected from customers. Such costs, if any, would be written off as a charge against earnings. Nuclear decommissioning costs are nonbypassable until fully recovered, but are not included as part of transition costs. Additional information is provided in Note 5.
In June 1999, SDG&E completed the recovery of its stranded costs, other than the future above-market portion of qualifying facilities and other purchased-power contracts that were in effect at December 31, 1995, and SONGS costs as described below. These costs will continue to be collected in rates. Recovery of the other stranded costs was effected by, among other things, the sale of SDG&E's fossil power plants and combustion turbines during the quarter ended June 30, 1999. The South Bay Power Plant sale to the San Diego Unified Port District for $110 million was completed on April 23, 1999. Duke South Bay, a subsidiary of Duke Energy Power Services, will manage the plant for the Port District. The sale of the Encina Power Plant and 17 combustion-turbine generators to Dynegy Inc. and NRG Energy Inc. for $356 million was completed on May 21, 1999. SDG&E will operate and maintain both the South Bay and Encina facilities for the new owners until April 2001 and May 2001, respectively.
Stranded costs included the cost of SONGS as of December 31, 1995. SDG&E retains ownership of its 20 percent interest in SONGS. Subsequent SONGS costs are recoverable only from the sales of power from SONGS, at rates previously fixed by the CPUC through December 31, 2003 and as determined by the market thereafter. If approved by the CPUC, SDG&E is planning to auction its interest in SONGS. A major issue being addressed is how to handle the decommissioning trust to ensure that adequate funding is available at the time the plant is decommissioned.
AB 1890 required a 10 percent reduction of residential and small commercial customers' rates, beginning in January 1998, and provided for the issuance of rate-reduction bonds by an agency of the state of California to enable the IOUs to achieve this rate reduction. In December 1997, $658 million of rate-reduction bonds were issued on behalf of SDG&E at an average interest rate of 6.26 percent. These bonds are being repaid over 10 years by SDG&E's residential and small commercial customers via a nonbypassable charge on their electric bills. In 1997, SDG&E formed a subsidiary, SDG&E Funding LLC, to facilitate the issuance of the bonds. In exchange for the bond proceeds, SDG&E sold to SDG&E Funding LLC all of its rights to certain revenue streams collected from such customers. Consequently, the transaction is structured to cause such revenue streams not to be the property of SDG&E nor to be available to satisfy any claims of SDG&E's creditors.
The sizes of the rate-reduction bond issuances were set so as to make the IOUs neutral as to the 10-percent rate reduction, and were based on a four-year period to recover stranded costs. Because SDG&E recovered its stranded costs in only 18 months (due to the greater-than-anticipated plant-sale proceeds), the bond proceeds were greater than needed. Accordingly, SDG&E will return to its customers over $400 million that it has collected or will collect from its customers. The timing of the return will differ from the timing of the collection, but the specific timing of the repayment and the interest rate thereon are the subject of a CPUC proceeding and are expected to be resolved in early 2000. This refund will not affect SDG&E's net income, except to the extent that the interest associated with the refund (12.63 percent if not reduced as a result of the CPUC proceeding) differs from the return earned by the Company on the funds to be refunded. The bonds and their repayment schedule are unaffected by this refund.
AB 1890 also includes a rate freeze for all IOU customers. Beginning in 1998, SDG&E's system-average rates were fixed at 9.43 cents per kwh. The rate freeze would have stayed in place until January 1, 2002. However, in connection with completion of its stranded cost recovery (described above), SDG&E filed with the CPUC for a mechanism to structure electric rates after the end of the rate freeze. SDG&E received approval to reduce base rates (the non- commodity portion of rates) to all electric customers effective July 1, 1999. As a result base electric rates will decrease beyond the original 10 percent rate reduction described above. The portion of the electric rate representing the commodity cost is simply passed through to customers and will fluctuate with the price of electricity from the PX. Except for the interim protection mechanism described below, customers will no longer be insulated from commodity price fluctuations.
In April 1999, SDG&E filed an all-party settlement (including energy service providers, the CPUC's Office of Ratepayer Advocates (ORA), and the Utility Consumers Action Network (UCAN)) detailing proposed implementation plans for lifting the rate freeze. Included in the settlement is an interim customer-protection mechanism for residential and small commercial customers that capped rates between July 1999 and September 1999, regardless of how high the PX price had moved during that period. The resulting undercollection (which amounted to less than $1 million) is being recovered through a balancing account mechanism. A CPUC decision adopting the all- party settlement was issued in May 1999 and became effective July 1, 1999. The interim post rate-freeze period runs until the CPUC issues its decision on the pending legal and policy issues of ending the rate freeze. This decision is expected during the second quarter of 2000. The decision will address, among other things, a proposal by SDG&E that would limit SDG&E's obligation to purchase from the PX to 80 percent of the electricity required by its utility default customers, and to establish an Electric Commodity Performance-Based Regulation mechanism, which would measure the Company's effectiveness in procuring electricity on behalf of its utility default commodity customers and the administration of its above market purchased power contracts.
In October 1997, the FERC approved key elements of the California IOU's restructuring proposal. This included the transfer by the IOUs of the operational control of their transmission facilities to the ISO, which is under FERC jurisdiction. The FERC also approved the establishment of the California PX to operate as an independent wholesale power pool. The IOUs pay to the PX an upfront restructuring charge (in four annual installments) and an administrative usage charge for each megawatt hour of volume transacted. SDG&E's share of the restructuring charge is approximately $10 million, which is being recovered in rates. The IOUs have guaranteed $300 million of commercial loans to the ISO and PX for their development and initial start-up. SDG&E's share of the guarantee is $30 million.
Thus far, electric-industry restructuring has been confined to generation. Transmission and distribution have remained subject to traditional cost-of-service regulation and performance-based regulation. However, the CPUC is exploring the possibility of opening up electric distribution to competition. During 2000, the CPUC will consider whether any changes should be made in electric distribution regulation. A CPUC staff report will be submitted on this issue to the CPUC in the second quarter of 2000. SDG&E and SoCalGas will actively participate in this effort.
On December 20, 1999 the FERC issued "Order 2000" concerning the formation of Regional Transmission Organizations (RTOs). The rule generally requires all public utilities that own, operate or control interstate transmission to file by October 15, 2000, a proposal for an RTO. Public utilities that are members of an existing, FERC-approved regional entity, which includes SDG&E, must file by January 15, 2001. The rule states that RTOs will be operational by December 15, 2001. The FERC order permits a number of different types of RTOs, including non-profit independent system operators, for-profit transmission companies, or other approaches. The FERC also allows flexibility so that an RTO can improve its structure, geographic scope, market support and operations to meet market needs. It notes that the FERC intends for RTOs: to alleviate stress on the bulk power system caused by changes in the structure of the industry; improve efficiencies in transmission grid management through better pricing and congestion management; improve grid reliability; remove remaining opportunities for discriminatory transmission practices; improve market performance; increase coordination among state regulatory agencies; cut transaction costs; facilitate the success of state retail access programs; and facilitate reduced regulation. The order also specifies the required characteristics for each RTO, including independence from market participants, and the functional responsibilities required of each RTO. The order also provides guidance on transmission pricing reforms. The identification of RTO regions and formation of the RTO's will be subject to a collaborative process. The impact of Order 2000 on SDG&E depends on the results of this process and other implementation issues.

Gas Industry Restructuring

The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating gas sales to noncore customers. On January 21, 1998, the CPUC released a staff report initiating a proceeding to assess the current market and regulatory framework for California's natural gas industry. The general goals of the plan are to consider reforms to the current regulatory framework emphasizing market-oriented policies benefiting California's natural gas consumers.
In August 1998, California enacted a law prohibiting the CPUC from enacting any natural gas industry restructuring decision for core (residential and small commercial) customers prior to January 1, 2000. During the implementation moratorium, the CPUC held hearings throughout the state and intends to give the legislature a draft ruling before adopting a final market-structure policy. SDG&E has been actively participating in this effort and has argued in support of competition intended to maximize benefits to customers rather than to protect competitors.
In October 1999, the State of California enacted a law (AB 1421) which requires that gas utilities provide "bundled basic gas service" (including transmission, storage, distribution, purchasing, revenue-cycle services and after-meter services) to all core customers, unless the customer chooses to purchase gas from a non-utility provider. The law prohibits the CPUC from further unbundling of distribution-related gas services (including meter reading and billing) and after-meter services (including leak investigation, inspecting customer piping and appliances, pilot relighting and carbon monoxide investigation) for most customers. The objective is to preserve both customer safety and customer choice.

Performance-Based Regulation (PBR)

To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, the CPUC has been directing utilities to use PBR. PBR has replaced the general rate case and certain other regulatory proceedings for SDG&E. Under PBR, regulators require future income potential to be tied to achieving or exceeding specific performance and productivity measures, as well as cost reductions, rather than relying solely on expanding utility plant in a market where a utility already has a highly developed infrastructure.
SDG&E's PBR mechanism is in effect through December 31, 2002 and scheduled to be updated at December 31, 2002, at which time it will be updated for, among other things, changes in costs and volumes. Key elements of the mechanism include an initial reduction in base rates, an indexing mechanism that limits future rate increases to the inflation rate less a productivity factor, a sharing mechanism with customers if earnings exceed the authorized rate of return on rate base, and rate refunds to customers if service quality deteriorates or awards if service quality exceeds set standards. Specifically, the key elements of the mechanism include the following:

-- Earnings up to 25 basis points in excess of the authorized rate of return on rate base are retained 100 percent by shareholders. Earnings that exceed the authorized rate of return on rate base by greater than 25 basis points are shared between customers and shareholders on a sliding scale that begins with 75 percent of the additional earnings being given back to customers and declining to 0 percent as earned returns approach 300 basis points above authorized amounts. There is no sharing if actual earnings fall below the authorized rate of return. In 1999, SDG&E was authorized to earn 9.05 percent on its rate base. For 2000, the authorized return is 8.75 percent.

-- Base rates are indexed based on inflation less an estimated productivity factor.

-- Performance indicators, including employee safety, electric reliability, customer satisfaction, and call-center responsiveness, affect the Company's future income potential. SDG&E is authorized to earn or be penalized up to a maximum of $14.5 million annually as a result of its performance in those areas.

-- Annual cost of capital proceedings are replaced by an automatic adjustment mechanism if changes in certain indices exceed established tolerances. SDG&E's mechanism is triggered by a six- month trailing average and a 100 basis point change in interest rates. If this occurs, there would be an automatic adjustment of rates for the change in the cost of capital according to a formula which applies a percentage of the change to various capital components.

Biennial Cost Allocation Proceeding (BCAP)

In October 1998, SDG&E filed its 1999 BCAP application requesting that new rates become effective August 1, 1999 and remain in effect through December 31, 2002. On January 11, 2000, the CPUC issued a proposed decision adopting an overall decrease in natural gas revenues of $38 million for SDG&E. A final CPUC decision is expected in the second quarter of 2000.

Cost Of Capital

For 2000, electric-industry restructuring has changed the method of calculating the utility's annual cost of capital. In May 1998, SDG&E filed with the CPUC its unbundled Cost of Capital application to establish rates of return for SDG&E's electric-distribution and natural gas businesses. In June 1999, the CPUC adopted a 10.6 percent return on common equity and 8.75 percent return on rate base for SDG&E, compared to 9.35 percent and 11.6 percent prior to July 1, 1999, respectively. The electric transmission cost of capital is determined under a separate FERC proceeding.

Transactions Between Utilities and Affiliated Companies

On December 16, 1997, the CPUC adopted rules, effective January 1, 1998, establishing uniform standards of conduct governing the manner in which IOUs conduct business with their energy-related affiliates. The objective of the affiliate-transaction rules is to ensure that these affiliates do not gain an unfair advantage over other competitors in the marketplace and that utility customers do not subsidize affiliate activities. The rules establish standards relating to non-discrimination, disclosure and information exchange, and separation of activities. The CPUC excluded utility- to-utility transactions between SDG&E and SoCalGas from the affiliate-transaction rules in its March 1998 decision approving the business combination of Enova and PE, which is described in Note 1.
During 1999, 1998 and 1997, the Company purchased natural gas transportation and storage services from SoCalGas in the amount of $50 million to $60 million per year.These sales were at rates established by the CPUC.

NOTE 13: SEGMENT INFORMATION

The Company has three separately managed reportable segments:
electric transmission and distribution, electric generation, and natural gas service. The accounting policies of the segments are the same as those described in Note 2 and segment performance is evaluated by management based on reported operating income. Intersegment transactions generally are recorded the same as sales or transactions with third parties. Interest expense and income tax expense are not allocated to the reportable segments.

-----------------------------------------------------------------------
                                       For the year ended December 31,
(Dollars in millions)                  1999          1998         1997
-----------------------------------------------------------------------
Revenues:
  Transmission & distribution      $   1,396     $   1,430    $   1,202
  Electric Generation                    422           435          567
  Natural Gas                            389           384          398
                                  -------------------------------------
    Total                          $   2,207     $   2,249    $   2,167
                                  -------------------------------------
Depreciation and amortization:
  Transmission & distribution      $     148     $     134    $     128
  Electric Generation                    374           430          159
  Natural Gas                             39            39           37
                                  -------------------------------------
    Total                          $     561     $     603    $     324
                                  -------------------------------------
Segment Income:
  Transmission & distribution      $     318     $     302    $     349
  Electric Generation                     (5)           54          106
  Natural Gas                             70            63           79
                                  -------------------------------------
    Total segment income                 383           419          534
                                  -------------------------------------
  Interest expense                      (120)         (106)         (74)
  Income tax expense                    (126)         (142)        (219)
  Nonoperating income                     62            20           (3)
                                  -------------------------------------
    Net income                     $     199     $     191    $     238
                                  -------------------------------------
Capital Expenditures:
  Transmission & distribution      $     201     $     173    $     147
  Electric Generation                      9            18           14
  Natural Gas                             35            36           36
                                  -------------------------------------
    Total                          $     245     $     227    $     197
                                  -------------------------------------

-----------------------------------------------------------------------
                                         At December 31, or for
                                          the year then ended
(Dollars in millions)                 1999           1998         1997
-----------------------------------------------------------------------
Assets:
  Transmission & distribution      $   2,563     $   2,518    $   2,257
  Electric Generation                    146           685        1,051
  Natural Gas                            539           553          592
  All other                            1,118           501          754
                                  -------------------------------------
    Total                          $   4,366     $   4,257    $   4,654
                                  -------------------------------------
Geographic Information:
  Long-lived assets
    United States                  $   2,157      $  2,300    $   2,359
                                  -------------------------------------
  Operating Revenues:
    United States                  $   2,207      $  2,249    $   2,159
    Mexico                                --            --            8
                                  -------------------------------------
      Total                        $   2,207      $  2,249    $   2,167
-----------------------------------------------------------------------

                                                 Quarter ended
                             -----------------------------------------------------
Dollars in millions           March 31     June 30     September 30  December 31
----------------------------------------------------------------------------------
1999
Operating revenues            $    461    $    740       $    520      $    486
Operating expenses                 390         673            438           425
                               ---------------------------------------------------
Operating income              $     71    $     67       $     82      $     61
                               ---------------------------------------------------
Net income                    $     55    $     47       $     61      $     36
Dividends on preferred stock         2           1              2             1
                               ---------------------------------------------------
Net income applicable
  to common shares            $     53    $     46       $     59      $     35
                               ===================================================
1998
Operating revenues            $    606    $     569      $    563      $    511
Operating expenses                 529          524           475           435
                               ---------------------------------------------------
Operating income              $     77    $      45      $     88      $     76
                               ---------------------------------------------------
Net income                    $     50    $      27      $     64      $     50
Dividends on preferred stock         2            1             2             1
                               ---------------------------------------------------
Net income applicable
  to common shares            $     48    $      26      $     62      $     49
                               ===================================================