SEMPRA ENERGY - 10-Q Quarterly Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2004
-------------------------------------

Commission file number 1-14201
---------------------------------------------

Sempra Energy
----------------------------------------------------------
(Exact name of registrant as specified in its charter)

California 33-0732627
- ------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

101 Ash Street, San Diego, California 92101
- -------------------------------------------------------------------
(Address of principal executive offices)
(Zip Code)

(619) 696-2034
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(Registrant's telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days.
Yes X No
----- -----

Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act).
Yes X No
----- -----

Indicate the number of shares outstanding of each of the issuer's
classes of common stock, as of the latest practicable date.

Common stock outstanding on July 31, 2004: 231,795,224
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2

INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report contains statements that are not historical fact
and constitute forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995. The words
"estimates," "believes," "expects," "anticipates," "plans," "intends,"
"may," "could," "would" and "should" or similar expressions, or
discussions of strategy or of plans are intended to identify forward-
looking statements. Forward-looking statements are not guarantees of
performance. They involve risks, uncertainties and assumptions. Future
results may differ materially from those expressed in these forward-
looking statements.

Forward-looking statements are necessarily based upon various
assumptions involving judgments with respect to the future and other
risks, including, among others, local, regional, national and
international economic, competitive, political, legislative and
regulatory conditions and developments; actions by the California
Public Utilities Commission, the California Legislature, the California
Department of Water Resources, environmental and other regulatory
bodies in countries other than the United States, and the Federal
Energy Regulatory Commission; capital market conditions, inflation
rates, interest rates and exchange rates; energy and trading markets,
including the timing and extent of changes in commodity prices; weather
conditions and conservation efforts; war and terrorist attacks;
business, regulatory and legal decisions; the status of deregulation of
retail natural gas and electricity delivery; the timing and success of
business development efforts; and other uncertainties, all of which are
difficult to predict and many of which are beyond the control of the
company. Readers are cautioned not to rely unduly on any forward-
looking statements and are urged to review and consider carefully the
risks, uncertainties and other factors which affect the company's
business described in this report and other reports filed by the
company from time to time with the Securities and Exchange Commission.

3

PART I. FINANCIAL INFORMATION
ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions, except per share amounts)

4

SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions, except per share amounts)

5

SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

6

SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

7

SEMPRA ENERGY
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)

8

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. GENERAL

This Quarterly Report on Form 10-Q is that of Sempra Energy (the
company), a California-based Fortune 500 holding company. Sempra
Energy's subsidiaries include San Diego Gas & Electric Company (SDG&E),
Southern California Gas Company (SoCalGas) (collectively referred to
herein as the California Utilities); Sempra Energy Global Enterprises
(Global), which is the holding company for Sempra Energy Trading (SET),
Sempra Energy Resources (SER), Sempra Energy International (SEI),
Sempra Energy Solutions (SES) and other, smaller businesses; Sempra
Energy Financial (SEF); and additional smaller businesses. The
financial statements herein are the Consolidated Financial Statements
of Sempra Energy and its consolidated subsidiaries.

The accompanying Consolidated Financial Statements have been prepared
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. 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. Certain changes in classification have been
made to prior presentations to conform to the current financial
statement presentation. Specifically, certain December 31, 2003 income
tax liabilities have been reclassified from Deferred Income Taxes to
current Income Taxes Payable and to Deferred Credits and Other
Liabilities to conform to the current presentation of these items.

Information in this Quarterly Report is unaudited and should be read in
conjunction with the Annual Report on Form 10-K for the year ended
December 31, 2003 (Annual Report) and the Quarterly Report on Form 10-Q
for the first quarter of 2004.

The company's significant accounting policies are described in Note 1
of the notes to Consolidated Financial Statements in the Annual Report.
The same accounting policies are followed for interim reporting
purposes.

The company follows the guidance of Statement of Financial Accounting
Standards (SFAS) 142, "Goodwill and Other Intangible Assets." The
carrying amount of goodwill (included in Noncurrent Sundry Assets on
the Consolidated Balance Sheets) was $188 million as of December 31,
2003 and June 30, 2004.

The California Utilities account for the economic effects of regulation
on utility operations in accordance with SFAS No. 71, "Accounting for
the Effects of Certain Types of Regulation."

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NOTE 2. NEW ACCOUNTING STANDARDS

SFAS 132 (revised 2003), "Employers' Disclosures about Pensions and
Other Postretirement Benefits": This statement revises employers'
disclosures about pension plans and other postretirement benefit plans,
effective in 2004. It requires disclosures beyond those in the original
SFAS 132 related to the assets, obligations, cash flows and net
periodic benefit cost of defined benefit pension plans and other
defined postretirement plans. In addition, it requires interim-period
disclosures regarding the amount of net periodic benefit cost
recognized and the total amount of the employers' contributions paid
and expected to be paid during the current fiscal year. It does not
change the measurement or recognition of those plans.

The following table provides the components of benefit costs for the
three months and six months ended June 30:

10

Note 8 of the notes to Consolidated Financial Statements in the Annual
Report discusses the company's expected contribution to its pension
plans and other postretirement benefit plans in 2004. For the six
months ended June 30, 2004, $9 million and $30 million of contributions
have been made to its pension plans and other postretirement benefit
plans, respectively, including $8 million and $16 million,
respectively, for the three months ended June 30, 2004.

SFAS 143, "Accounting for Asset Retirement Obligations": Beginning in
2003, SFAS 143 requires entities to record liabilities for future costs
expected to be incurred when assets are retired from service, if the
retirement process is legally required. It also requires the
reclassification of utilities' estimated removal costs, which have
historically been recorded in accumulated depreciation, to a regulatory
liability. At June 30, 2004 and December 31, 2003, the estimated
removal costs recorded as a regulatory liability were $1.4 billion at
both dates for SoCalGas, and $868 million and $846 million,
respectively, for SDG&E.

The change in the asset retirement obligations for the six months ended
June 30, 2004 is as follows (dollars in millions):

Balance as of January 1, 2004 $ 337
Accretion expense (interest) 11
Payments (6)
------
Balance as of June 30, 2004 $ 342*
======

* The current portion of the obligation is included in Other Current
Liabilities on the Consolidated Balance Sheets.

SFAS 148, "Accounting for Stock-Based Compensation -- Transition and
Disclosure": SFAS 148 requires quarterly disclosure of the effects that
would have been recorded if the financial statements applied the fair
value recognition principle of SFAS 123, "Accounting for Stock-Based
Compensation." The company accounts for stock-based employee
compensation plans under the recognition and measurement principles of
Accounting Principles Board (APB) Opinion No. 25, "Accounting for Stock
Issued to Employees," and related interpretations. For certain grants,
no stock-based employee compensation cost is reflected in net income,
since each option granted under those plans had an exercise price equal
to the market value of the underlying common stock on the date of
grant. The following table provides the pro forma effects of
recognizing compensation expense in accordance with SFAS 148 had the
company adopted the modified prospective method in January 2003:

11

On March 31, 2004, the Financial Accounting Standards Board (FASB)
issued a proposed Exposure Draft (ED) to amend SFAS 123. The proposed
statement would eliminate the choice of accounting for share-based
compensation transactions using APB Opinion No. 25, whereby no expense
is recorded for most stock options and instead generally require that
such transactions be accounted for using a fair-value-based method,
whereby expense is recorded for stock options. It would also prohibit
application by restating prior periods and would require that expense
be recognized only for those options that actually vest. If passed,
the proposed ED would be effective for the company in 2005.

SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": Effective July 1, 2003, SFAS 149 amended and
clarified accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging
activities under SFAS 133. Under SFAS 149 natural gas forward contracts
that are subject to unplanned netting generally do not qualify for the
normal purchases and normal sales exception, whereby derivatives are
not required to be marked to market when the contract is usually
settled by the physical delivery of natural gas. ("Netting" refers to
contract settlement by paying or receiving the monetary difference
between the contract price and the market price at the date on which
physical delivery would have occurred.) In addition, effective January
1, 2004, power contracts that are subject to unplanned netting and that
do not meet the normal purchases and normal sales exception under SFAS
149 will continue to be marked to market. Implementation of SFAS 149
did not have a material impact on reported net income. Additional
information on derivative instruments is provided in Note 5.

12

SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of Liabilities and Equity": The company adopted SFAS
150 beginning July 1, 2003 by reclassifying $200 million of mandatorily
redeemable trust preferred securities to Deferred Credits and Other
Liabilities and $24 million of mandatorily redeemable preferred stock
of subsidiaries to Deferred Credits and Other Liabilities and to Other
Current Liabilities on the Consolidated Balance Sheets. On December 31,
2003, the $200 million of mandatorily redeemable trust preferred
securities were reclassified to Due to Affiliates due to the adoption
of FASB Interpretation No. (FIN) 46 as discussed below.

Emerging Issues Task Force (EITF) 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities": In
accordance with the EITF's rescission of Issue 98-10 by the release of
Issue 02-3, the company no longer marks to market energy-related
contracts unless the contracts meet the requirements stated under SFAS
133 and SFAS 149. A substantial majority of the company's contracts do
meet these requirements. On January 1, 2003, the company recorded the
initial effect of Issue 98-10's rescission as a cumulative effect of a
change in accounting principle, which reduced after-tax earnings by $29
million. Neither the cumulative nor the ongoing effect impacts the
company's cash flow or liquidity. Additional information on derivative
instruments is provided in Note 5.

FIN 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees": As of June 30, 2004, substantially all of the company's
guarantees were intercompany, whereby the parent issues the guarantees
on behalf of its consolidated subsidiaries. The only significant
guarantees for which disclosure is required are the mandatorily
redeemable trust preferred securities and $25 million related to debt
issued by Chilquinta Energia Finance, LLC, an unconsolidated affiliate.
The mandatorily redeemable trust preferred securities were also
affected by FIN 46, as described below.

FIN 46, "Consolidation of Variable Interest Entities an interpretation
of Accounting Research Bulletin (ARB) No. 51": FIN 46 requires the
primary beneficiary of a variable interest entity's activities to
consolidate the entity. Variable interest entities (VIEs) are
enterprises that have certain characteristics defined in FIN 46.

Sempra Energy adopted FIN 46 on December 31, 2003, resulting in the
consolidation of two VIEs for which it is the primary beneficiary. One
of the VIEs (Mesquite Trust) was the owner of the Mesquite Power plant
for which the company had a synthetic lease agreement, as described in
Note 2 in the Annual Report. The Mesquite Power plant is a 1,250-
megawatt (MW) plant that provides electricity to wholesale energy
markets in the Southwest and that became fully operational in December
2003. The company recorded an after-tax credit of $9 million in 2003
for the cumulative effect of the change in accounting principle. The
company bought out the lease in January 2004.

The other VIE is Atlantic Electric & Gas (AEG), which marketed power
and natural gas commodities to commercial and residential customers in
the United Kingdom. Consolidation of AEG resulted in Sempra Energy's
recording of 100 percent of AEG's balance sheet and results of
operations, whereas it previously recorded only its share of AEG's net
operating results. Due to AEG's consolidation, the company recorded an

13

after-tax charge of $26 million in 2003 for the cumulative effect of
the change in accounting principle. During the first quarter of 2004,
Sempra Energy's Board of Directors approved management's plan to
dispose of AEG. Note 4 provides further discussion concerning this
matter and the disposal of AEG's discontinued operations, which
occurred in April 2004.

In accordance with this interpretation, the company deconsolidated a
wholly owned subsidiary trust from its financial statements at December
31, 2003. The trust has no assets except for its receivable from the
company. Due to the deconsolidation of this entity, Sempra Energy
reclassified $200 million of mandatorily redeemable trust preferred
securities to Due to Affiliates on its Consolidated Balance Sheets.

In addition, contracts under which SDG&E acquires power from generation
facilities otherwise unrelated to SDG&E could result in a requirement
for SDG&E to consolidate the entity that owns the facility. As
permitted by the interpretation, SDG&E is continuing the process of
determining whether it has any such situations and, if so, gathering
the information that would be needed to perform the consolidation. The
effects of this, if any, are not expected to significantly affect the
financial position of SDG&E and there would be no effect on results of
operations or liquidity.

FASB Staff Position (FSP) 106-1 and 106-2, "Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003": Issued January 12, 2004, FSP 106-1 allowed
the company to make a one-time election during the first quarter of
2004 to defer accounting for the effects of the Medicare Prescription
Drug, Improvement and Modernization Act of 2003 (the Act) until
authoritative guidance on the accounting for federal subsidies was
issued.

In May 2004, FSP 106-1 was superseded by FSP 106-2, which provides
guidance on the accounting for the effects of the Act by employers
whose prescription drug benefits are actuarially equivalent to the drug
benefit under Medicare Part D. In such a case, the employer includes
the federal subsidy in measuring the accumulated postretirement benefit
obligation (APBO). The resulting reduction in the APBO is recognized as
an actuarial gain and the employer's share of future costs under the
plan is reflected in current period service cost. FSP 106-2 also
provides disclosure guidance about the effects of the subsidy for an
employer who offers postretirement prescription drug coverage, but is
unable to determine whether the plan's provisions are actuarially
equivalent to the Medicare Part D benefit. For the company, FSP 106-2
is effective for the quarter ending September 30, 2004. The company has
not yet determined whether the benefits provided by the plans are
actuarially equivalent, and, at June 30, 2004, the APBO and net
periodic postretirement benefit costs do not reflect any amount
associated with the subsidy.

14

NOTE 3. COMPREHENSIVE INCOME

The following is a reconciliation of net income to comprehensive
income.

Three months Six months
ended ended
June 30, June 30,
---------------------------------
(Dollars in millions) 2004 2003 2004 2003
- -----------------------------------------------------------------

Net income $ 121 $ 116 $ 318 $ 204

Minimum pension liability
adjustments -- -- -- (6)

Foreign currency adjustments (14) 30 (10) 44

Financial instruments (8) -- (13) --

---------------------------------
Comprehensive income $ 99 $ 146 $ 295 $ 242
- -----------------------------------------------------------------

NOTE 4. DISCONTINUED OPERATIONS

During the first quarter of 2004, Sempra Energy's Board of Directors
approved management's plan to dispose of its interest in AEG, which
markets power and natural gas commodities to commercial and residential
customers in the United Kingdom. This disposal met the criteria
established for recognition as discontinued operations under SFAS 144,
"Accounting for the Impairment or Disposal of Long-Lived Assets." On
April 27, 2004, AEG went into administrative receivership and
substantially all of the assets were sold. This transaction resulted in
a loss of $2 million after taxes, which has been reported separately on
the Statements of Consolidated Income.

The net losses from discontinued operations were $32 million ($0.14 per
basic and diluted share) for the six months ended June 30, 2004 and $8
million ($0.04 per basic and diluted share) for the quarter ended June
30, 2004 (including the $2 million loss on disposal). During 2003, the
company accounted for its investment in AEG under the equity method of
accounting. As such, for the six-month and three-month periods ended
June 30, 2003, the company recorded its share of AEG's net losses ($6
million and $3 million, respectively) in Other Income - Net on the
Statements of Consolidated Income. Additionally, the company recorded
offsetting interest income of $1 million for both periods. Effective
December 31, 2003, AEG was consolidated as a result of the adoption of
FIN 46. This is discussed further in the Annual Report.

15

Included within the net loss from discontinued operations are AEG's
operating results, summarized below:

AEG's balance sheet data, excluding intercompany balances (which are
significant) eliminated in consolidation, are summarized below:

NOTE 5. FINANCIAL INSTRUMENTS

As described in Note 10 of the notes to Consolidated Financial
Statements in the Annual Report, the company follows the guidance of
SFAS 133 as amended by SFAS 138 and 149 (collectively SFAS 133) to
account for its derivative instruments and hedging activities.
Derivative instruments and related hedged items are recognized as
either assets or liabilities on the balance sheet, measured at fair
value. Changes in the fair value of derivatives are recognized in
earnings in the period of change unless the derivative qualifies as an
effective hedge that offsets certain exposure, except at the California
Utilities, where such changes are balanced in the ratemaking process.

SFAS 133 provides for hedge accounting treatment when certain criteria
are met. For derivative instruments designated as fair value hedges,
the gain or loss is recognized in earnings in the period of change
together with the offsetting gain or loss on the hedged item
attributable to the risk being hedged. For derivative instruments
designated as cash flow hedges, the effective portion of the derivative
gain or loss is included in Other Comprehensive Income, but not
reflected in the Statements of Consolidated Income until the

16

corresponding hedged transaction is settled. The ineffective portion is
reported in earnings immediately.

The company utilizes derivative instruments to reduce its exposure to
unfavorable changes in energy and other commodity prices, which are
subject to significant and often volatile fluctuation. The company also
uses derivative physical and financial instruments to reduce its
exposure to fluctuations in interest rates and foreign currency
exchange rates. Derivative instruments include futures, forwards,
swaps, options and long-term delivery contracts. These contracts allow
the company to predict with greater certainty the effective prices to
be received by the company and, in the case of the California
Utilities, their customers. The company also periodically enters into
interest-rate swap agreements to moderate exposure to interest-rate
changes and to lower the overall cost of borrowing.

Contracts that meet the definition of normal purchase and sales
generally are long-term contracts that are settled by physical delivery
and, therefore, are eligible for the normal purchases and sales
exception of SFAS 133. The contracts are accounted for under accrual
accounting and recorded in Revenues or Cost of Sales on the Statements
of Consolidated Income when physical delivery occurs. Due to the
adoption of SFAS 149, the company has determined that its natural gas
contracts entered into after June 30, 2003 generally do not qualify for
the normal purchases and sales exception.

Fixed-priced Contracts and Other Derivatives

Fixed-priced Contracts and Other Derivatives on the Consolidated
Balance Sheets primarily reflect the California Utilities' unrealized
gains and losses related to long-term delivery contracts for purchased
power and natural gas transportation. The California Utilities have
established offsetting regulatory assets and liabilities to the extent
that these gains and losses are included in the calculation of future
rates. If gains and losses at the California Utilities are not
recoverable or payable through future rates, the California Utilities
will apply hedge accounting if certain criteria are met. If a contract
no longer meets the requirements of SFAS 133, the unrealized gains and
losses and the related regulatory asset or liability will be amortized
over the remaining contract life.

The changes in Fixed-price Contracts and Other Derivatives on the
Consolidated Balance Sheets for the six months ended June 30, 2004 were
primarily due to the settlement of the contingent purchase price
obligation arising from the company's acquisition of the proposed
Cameron liquefied natural gas (LNG) project and the physical deliveries
under long-term purchased-power and natural gas transportation
contracts.

For the six months ended June 30, 2004, pre-tax income from
transactions associated with fixed-price contracts and other
derivatives included $13 million for the settlement of the Cameron
contingency, which occurred during the first quarter. The transactions
associated with fixed-price contracts and other derivatives had no
material impact to the Statements of Consolidated Income for the six
months ended June 30, 2003.

17

Trading Assets and Trading Liabilities

Trading Assets and Trading Liabilities primarily arise from the
activities of SET. SET derives revenue from market making and trading
activities, as a principal, in natural gas, electricity, petroleum,
petroleum products, metals and other commodities, for which it quotes
bid and ask prices to other market makers and end users. It also earns
trading profits as a dealer by structuring and executing transactions
that permit its counterparties to manage their risk profiles. SET
utilizes derivative instruments to reduce its exposure to unfavorable
changes in market prices, which are subject to significant and often
volatile fluctuation. These instruments include futures, forwards,
swaps and options, and represent contracts with counterparties under
which payments are linked to or derived from energy market indices or
on terms predetermined by the contract, which may or may not be
financially settled by SET. Sempra Energy guarantees many of SET's
transactions.

Trading instruments are recorded by SET on a trade-date basis and the
majority of such derivative instruments are adjusted daily to current
market value with gains and losses recognized in Other Operating
Revenues on the Statements of Consolidated Income. Trading Assets or
Trading Liabilities include amounts due from commodity clearing
organizations, amounts due to or from trading counterparties,
unrealized gains and losses from exchange-traded futures and options,
derivative over-the-counter (OTC) swaps, forwards and options.
Unrealized gains and losses on OTC transactions reflect amounts that
would be received from or paid to a third party upon settlement of the
contracts. Unrealized gains and losses on OTC transactions are reported
separately as assets and liabilities unless a legal right of setoff
exists under an enforceable netting arrangement. Other derivatives
which qualify as hedges are accordingly recorded under hedge
accounting.

Futures and exchange-traded option transactions are recorded as
contractual commitments on a trade-date basis and are carried at fair
value based on closing market quotations. Commodity swaps and forward
transactions are accounted for as contractual commitments on a trade-
date basis and are carried at fair value derived from dealer quotations
and underlying commodity exchange quotations. OTC options purchased and
written are recorded on a trade-date basis. OTC options are carried at
fair value based on the use of valuation models that utilize, among
other things, current interest, commodity and volatility rates, as
applicable. Energy commodity inventory is being recorded at the lower
of cost or market; however metals inventories continue to be recorded
at fair value in accordance with ARB 43, "Restatement and Revision of
Accounting Research Bulletins."

18

The carrying values of SET's trading assets and trading liabilities are
as follows:
June 30, December 31,
(Dollars in millions) 2004 2003
- -----------------------------------------------------------------------
Trading Assets
Unrealized gains on swaps and forwards $ 1,577 $ 1,043
OTC commodity options purchased 594 459
Due from trading counterparties 1,594 2,183
Due from commodity clearing organizations
and clearing brokers 160 134
Commodities owned 1,107 1,420
Other 5 1
------- -------
Total $ 5,037 $ 5,240
======= =======
- -----------------------------------------------------------------------
Trading Liabilities
Unrealized losses on swaps and forwards $ 1,444 $ 1,095
OTC commodity options written 312 226
Due to trading counterparties 1,991 2,195
Repurchase obligations 375 866
Commodities not yet purchased -- 56
------- -------
Total $ 4,122 $ 4,438
======= =======
- -----------------------------------------------------------------------

At SET, market risk arises from the potential for changes in the value
of physical and financial instruments resulting from fluctuations in
prices and basis for natural gas, electricity, petroleum, petroleum
products, metals and other commodities. Market risk is also affected by
changes in volatility and liquidity in markets in which these
instruments are traded.

SET's credit risk from physical and financial instruments as of June
30, 2004 is represented by their positive fair value after
consideration of collateral. Options written do not expose SET to
credit risk. Exchange traded futures and options are not deemed to have
significant credit exposure since the exchanges guarantee that every
contract will be properly settled on a daily basis.

19

The following table summarizes the counterparty credit quality and
exposure for SET at June 30, 2004 and December 31, 2003, expressed in
terms of net replacement value. These exposures are net of collateral
in the form of customer margin and/or letters of credit of $983 million
and $569 million at June 30, 2004 and December 31, 2003, respectively.

June 30, December 31,
(Dollars in millions) 2004 2003
- ------------------------------------------------------------------------
Counterparty credit quality*
Commodity exchanges $ 160 $ 134
AAA 9 5
AA 277 310
A 581 463
BBB 542 345
Below investment grade 427 357
------- -------
Total $ 1,996 $ 1,614
======= =======

* As determined by rating agencies or internal models intended to
approximate rating-agency determinations.

NOTE 6. REGULATORY MATTERS

ELECTRIC INDUSTRY REGULATION

The restructuring of California's electric utility industry has
significantly affected the company's electric utility operations. In
addition, the power crisis of 2000-2001 caused the California Public
Utilities Commission (CPUC) to adjust its plan for restructuring the
electricity industry. The background of these issues is described in
the Annual Report.

The California Department of Water Resources' (DWR) operating agreement
with SDG&E, approved by the CPUC, provides that SDG&E is acting as a
limited agent on behalf of the DWR in undertaking energy sales and
natural gas procurement functions under the DWR contracts allocated to
SDG&E's customers. Legal and financial responsibility associated with
these activities continues to reside with the DWR. Therefore, the
revenues and costs associated with the contracts are not included in the
Statements of Consolidated Income.

On May 27, 2004, the CPUC denied Southern California Edison's (Edison)
Petition to Modify the CPUC decision that allocates charges related to
the DWR bonds issued in connection with the power crisis to customers
of California's three investor-owned utilities (IOUs) based on energy
usage. Edison did not appeal the decision on its application for
rehearing to the courts and, therefore, the decision has become final
and unappealable.

In October 2003, the CPUC initiated a proceeding to consider a
permanent methodology for allocating the DWR's revenue requirement
beginning in 2004 through the remaining life of the DWR contracts. An
interim allocation based on the current 2003 methodology was utilized
beginning January 1, 2004, and will remain in effect until a decision
is reached on a permanent methodology. In April 2004, Edison, Pacific

20

Gas & Electric (PG&E) and a northern California consumer advocacy group
proposed a limited joint settlement to allocate the DWR revenue
requirement among the IOUs. This settlement proposes to shift more than
$1 billion in additional costs to SDG&E customers and would have a
significant impact on commodity rates over the remaining eight-year
life of the DWR contracts. On July 19, 2004, the CPUC issued a proposed
decision and an alternate decision recommending permanent allocations
of DWR contract costs to the IOUs. Neither proposed decision would
adopt the settlement; instead, both would permanently allocate 12.5
percent of the fixed costs of the contracts to SDG&E for the remaining
life of the contracts (2004-2013). This would shift a total of $976
million in additional costs to SDG&E customers over an eight-year
period. Although these proposed decisions would have no effect on
SDG&E's net income, they would adversely affect its customer rates and
SDG&E's cash flows. In the near term the effect on SDG&E's cash flows
would be minor, but would become significant in the later years unless
rate ceilings were increased to provide more-contemporaneous recovery.
The CPUC may consider these draft decisions at its August 19, 2004
meeting.

SDG&E's long-term resource plan identifies the forecasted needs for
capacity resources within its service territory to support transmission
grid reliability. An updated 10-year resource plan was filed on July 9,
2004, in a CPUC proceeding to consider utility resource planning,
including energy efficiency, contracted power, demand response,
qualifying facilities, renewable generation and distributed generation.
SDG&E's updated long-term resource plan incorporates the resources
approved as a result of the May 2003 Request for Proposals (RFP)
discussed below, and recognizes updated goals to reach 20% renewable
resources by 2010. The updated plan recommends a 500-kV transmission
line addition in 2010.

In order to satisfy SDG&E's recognized near-term need for grid
reliability and capacity, in May 2003 SDG&E issued an RFP for the years
2005-2007 for at least 69 MW of electric capacity in 2005 increasing to
291 MW in 2007.

As a result of its RFP, in October 2003, SDG&E filed a motion
requesting CPUC authorization to enter into five new electric resource
contracts (including two under which SDG&E would take ownership, on a
turnkey basis, of new generating assets, including a 550-MW plant
(Palomar) being developed by SER for completion in 2006), as more fully
described in the Annual Report. A June 9, 2004 CPUC decision approved
all five proposed contracts, along with an additional demand response
contract. The decision authorized SDG&E to recover the costs of both
contracted resources and turnkey resources, but did not adopt SDG&E's
specific cost recovery, ratemaking and revenue requirement proposals
for the proposed turnkey resources. On July 15, 2004, three parties
filed requests for rehearing of the decision. SDG&E filed its response
on July 30, 2004, opposing the request. The CPUC is expected to rule on
the requests in the next few months. In August 2004, SDG&E will file
its revenue requirement and ratemaking proposals for the 45-MW
combustion turbine which SDG&E will acquire as a turnkey project (Ramco
facility) and will file for the Palomar facility later in 2004. The
decision did not approve SDG&E's proposals for a return on equity (ROE)
for SDG&E's new generation investments higher than SDG&E's ROE on
distribution assets, an equity offset for the debt equivalency of

21

purchase power contracts, and an equity buildup for construction. These
matters may be re-introduced for consideration in future CPUC
proceedings.

NATURAL GAS INDUSTRY RESTRUCTURING (GIR)

As discussed in the Annual Report, in December 2001 the CPUC issued a
decision related to GIR, with implementation anticipated during 2002.
On April 1, 2004, after many delays and changes, the CPUC issued a
decision that adopts tariffs to implement the 2001 decision. However,
by that same decision, the CPUC stayed implementation of the GIR
tariffs until it issues a decision in Phase I of the Natural Gas Market
Order Instituting Ratemaking (OIR) discussed below. At that time, the
CPUC will reconcile the GIR market structure with whatever structure
results from the Phase I decision of the Natural Gas Market OIR. The
stayed decision, if implemented, would unbundle the costs of SoCalGas'
backbone transmission system from rates and result in revising noncore
balancing account treatment to exclude the balancing of SoCalGas'
backbone transmission costs and place SoCalGas at risk for recovery of
$80 million for transmission and $81 million for storage (current
dollars). The decision would create firm tradable rights for the
transmission system. Other noncore costs/revenues would continue to be
fully balanced until the decision in the next Biennial Cost Allocation
Proceeding (BCAP) discussed below.

NATURAL GAS MARKET OIR

The CPUC's Natural Gas Market OIR was approved on January 22, 2004, and
will be addressed in two concurrent phases. The schedule calls for a
Phase I decision by September 2004 and a Phase II decision by the end
of 2004. Further discussion of Phase I and Phase II is included in the
Annual Report. The focus of the Gas OIR is the period from 2006 to
2016. Since GIR (discussed above) would end in August 2006 and there is
overlap between GIR and the OIR issues, a number of parties (including
SoCalGas) have requested the CPUC not to implement GIR.

The California Utilities have made comprehensive filings in the OIR
outlining a proposed market structure that will help create access to
new natural gas supply sources (such as LNG) for California. In the
Phase I filing, SoCalGas and SDG&E proposed a framework to provide firm
tradable access rights for intrastate natural gas transportation;
provide SoCalGas with continued balancing account protection for
intrastate transmission and distribution revenues, thereby eliminating
throughput risk; and integrate the transmission systems of SoCalGas and
SDG&E so as to have common rates and rules. The California Utilities
have proposed that the investments necessary to access new sources of
supply be included in ratebase and that the total amount of the
investments would not exceed $200 million.

In addition, the California Utilities have filed a recommended
methodology and framework to be used by the CPUC for granting pre-
approval of new interstate transportation agreements. A draft Phase I
decision was issued on July 20, 2004. The draft decision recommends
that the utilities' pre-approval procedures be approved with some
modifications and that several issues, including supply access rate
treatment, firm access rights and transmission system integration, be

22

addressed by separate applications. A final CPUC decision in Phase I is
expected in September 2004.

COST OF SERVICE FILINGS

In 2002, the California Utilities filed Cost Of Service applications
with the CPUC, seeking rate increases reflecting forecasts of 2004
capital and operating costs, as further discussed in the Annual Report.
The California Utilities are requesting revenue increases of $101
million. On December 19, 2003, settlements were filed with the CPUC for
SoCalGas and SDG&E that, if approved, would resolve most of the Cost of
Service issues. A CPUC decision is expected later this year. The
SoCalGas settlement would reduce rate revenues by $33 million from 2003
rate revenues. The SDG&E settlement would reduce its electric rate
revenues by $19.6 million from 2003 rate revenues and increase its
natural gas rate revenues by $1.8 million from 2003 rate revenues. A
CPUC order has provided that the new rates will be retroactive to
January 1, 2004. Beginning in the first quarter of 2004, the California
Utilities generally are recognizing revenue consistent with the
proposed settlements, except for amounts related to pension costs,
which are pending the CPUC decision and CPUC acceptance of a related
compliance filing. Resolution of the pension matter consistent with the
proposed settlement would result in the recording of additional income
at that time. To the extent, if any, that the final CPUC decision
varies from the method used to recognize revenue prior to that
decision, an accounting adjustment will be recorded at that time. To
date, the impacts of accounting consistent with the settlement have not
had a material effect on the financial statements.

The remaining issues are included in Phase II of the Cost of Service
proceeding. In addition to recommending changes in the performance-
based regulation (PBR) formulas, the CPUC's Office of Ratepayers
Advocates (ORA) also proposed the possibility of performance penalties,
without the possibility of performance awards. Hearings took place in
June 2004. On July 21, 2004, all of the active parties in Phase II who
dealt with post test year ratemaking and performance incentives filed
for adoption of an all-party settlement agreement for most of the Phase
II issues, including annual inflation adjustments and revenue sharing.
The agreement does not cover performance incentives. The settlement
requires the California Utilities to file their next rate cases based
on a 2008 test year. For the interim years of 2005-2007, the Consumer
Price Index will be used to adjust the escalatable authorized base rate
revenues within identified floors and ceilings. It is anticipated that
the CPUC will address this matter in its decision related to Phase II
of this proceeding expected by year-end 2004.

The California Utilities had filed for continuation of existing PBR
mechanisms for service quality and safety that would otherwise expire
at the end of 2003. In January 2004, the CPUC issued a decision that
extended 2003 service and safety targets through 2004, but did not
determine the applicability of rewards or penalties.

Edison has received the CPUC's decision on its Cost of Service
application. This decision sets rates for San Onofre Nuclear Generating
Station (SONGS), 20 percent of which is owned by SDG&E. As discussed in
the Annual Report, SDG&E's SONGS ratebase restarted at $0 on January 1,
2004 and, therefore, SDG&E's earnings from SONGS will generally be

23

limited to a return on new capital additions. Edison has applied for
permission to replace SONGS' steam generator, which would increase the
total cost of SONGS by an estimated $800 million ($160 million for
SDG&E). SDG&E has the option of not participating in the project and
has informed Edison of its intention to exercise this option. This
would reduce SDG&E's ownership percentage in SONGS. The reduction in
SDG&E's ownership percentage is subject to arbitration, which is
expected to occur prior to year-end. If the proposed reduction of
SDG&E's ownership percentage resulting from the arbitration is
unacceptable, SDG&E could elect to participate in the replacement
project.

PERFORMANCE-BASED REGULATION

As further described in the Annual Report, under PBR, the CPUC requires
future income potential to be tied to achieving or exceeding specific
performance and productivity goals, rather than relying solely on
expanding utility plant to increase earnings. PBR, demand-side
management (DSM) and Gas Cost Incentive Mechanism (GCIM) rewards are
not included in the company's earnings before CPUC approval is
received.

The only incentive reward approved during the first six months of 2004
was $6.3 million related to SoCalGas' Year 9 GCIM, which was approved
on February 26, 2004. This reward is subject to refunds based on the
outcome of the Border Price Investigation. The cumulative amount of
rewards subject to refund based on the outcome of the Border Price
Investigation described below is $65.1 million.

At June 30, 2004, the following performance incentives were pending
CPUC approval and, therefore, were not included in the company's
earnings (dollars in millions):

Program SoCalGas SDG&E Total
- -----------------------------------------------------------
DSM/Energy Efficiency* $ 10.9 $ 37.7 $ 48.6
2003 Distribution PBR -- 8.2 8.2
GCIM/natural gas PBR 2.4 1.5 3.9
2003 safety .5 -- .5
- -----------------------------------------------------------
Total $ 13.8 $ 47.4 $ 61.2
- -----------------------------------------------------------

* Dollar amounts shown do not include interest, franchise fees or
uncollectible amounts.

SOUTHERN CALIFORNIA FIRES

Several major wildfires that began on October 26, 2003 severely damaged
SDG&E's infrastructure, causing a significant number of customers to be
without utility services. On October 27, 2003, then governor Gray Davis
declared a State of Emergency for the State of California. The
declaration authorized the establishment of catastrophic event
memorandum accounts (CEMA) to record all incremental costs (costs not
already included in rates) associated with the repair of facilities and
the restoration of service. Incremental electric distribution and
natural gas related costs are recovered through the CEMA. Electric

24

transmission related costs are recovered through the annual FERC true-
up proceeding. Total costs incurred related to the wildfires were $66
million, of which $58 million is under CPUC jurisdiction while $8
million is electric transmission subject to FERC jurisdiction. Of that
$58 million, $38 million is incremental and recoverable through the
CEMA.

On June 28, 2004, SDG&E filed its CEMA application to recover
incremental operating and maintenance costs and capital costs
associated with the fire. In that application, SDG&E is requesting a
revenue requirement of $20 million effective January 1, 2005, which
includes $16 million in expenses recorded through May 31, 2004 and
estimated to be incurred through the end of 2004, plus an additional $4
million for its capital-related costs, which will continue in future
years until the $22 million of capital costs and the authorized return
thereon are recovered. The company expects no significant effect on
earnings from the fires.

COST OF CAPITAL

Effective January 1, 2003, SoCalGas' authorized ROE is 10.82 percent
and its return on ratebase (ROR) is 8.68 percent. Effective January 1,
2003, SDG&E's authorized ROE is 10.9 percent and its ROR is 8.77
percent, for SDG&E's electric distribution and natural gas businesses.
The electric-transmission cost of capital is determined under a
separate FERC proceeding. As discussed in the Annual Report, these
rates will continue to be effective until 2008 unless market interest-
rate changes are large enough to trigger an automatic adjustment. In
SDG&E's case, the Moody's Aa utility bond yield as published by Mergent
Bond Record must average less than 6.24 percent or greater than 8.24
percent during the April-September timeframe of any given year to
trigger an automatic adjustment. The Moody's Aa utility bond yield
averaged 6.35 percent during the April-July 2004 time period and was
6.08 percent on July 30, 2004. SoCalGas' automatic adjustment occurs
when the 12-month trailing average of 30-year Treasury bond rates and
the Global Insight forecast of the 30-year Treasury bond rate 12 months
ahead vary by greater than 150 basis points from the benchmark, which
is currently 5.38 percent. The 12-month trailing average was 5.11
percent at June 30, 2004.

BIENNIAL COST ALLOCATION PROCEEDING

The BCAP determines the allocation of authorized costs between
customer classes for natural gas transportation service provided by
the California Utilities and adjusts rates to reflect variances in
customer demand as compared to the forecasts previously used in
establishing transportation rates. SoCalGas and SDG&E filed with the
CPUC their 2005 BCAP applications in September 2003, requesting
updated transportation rates effective January 1, 2005. In November
2003, an Assigned Commissioner Ruling delayed the BCAP applications
until a decision is issued in the GIR implementation proceeding. As a
result of the April 1, 2004 decision on GIR implementation as
described in "Natural Gas Industry Restructuring," above, on May 27,
2004 the Administrative Law Judge (ALJ) in the 2005 BCAP issued a
decision dismissing the BCAP applications. The California Utilities
would be required to file new BCAP applications after the stay of the
GIR implementation decision is lifted. As a result of the deferrals

25

and the forecasted significant decline in noncore gas throughput on
SoCalGas' system, in December 2002 the CPUC issued a decision
approving 100 percent balancing account protection for SoCalGas' risk
on local transmission and distribution revenues from January 1, 2003
until the CPUC issues its next BCAP decision. SoCalGas is seeking to
continue this balancing account protection in the Natural Gas OIR
proceeding.

BORDER PRICE INVESTIGATION

In November 2002, the CPUC instituted an investigation into the
Southern California natural gas market and the price of natural gas
delivered to the California-Arizona border between March 2000 and May
2001. If the investigation determines that the conduct of any party to
the investigation, including the California Utilities, contributed to
the natural gas price spikes, the CPUC may modify the party's natural
gas procurement incentive mechanism, reduce the amount of any
shareholder award for the period involved, and/or order the party to
issue a refund to ratepayers. Hearings began on June 29, 2004 and
continued through July 15, 2004. A draft decision is expected in
October 2004. The CPUC may hold a second round of hearings to consider
whether Sempra Energy or any of its non-utility subsidiaries
contributed to the price spikes. Final decisions are expected by late
2004. The company believes that the CPUC will find that the California
Utilities acted in the best interests of its core customers and that
none of the Sempra Energy companies was responsible for the price
spikes. The ORA filed testimony supporting the GCIM and the actions of
SoCalGas during this period. The actions of other Sempra Energy
companies are to be considered in a separate phase of the
investigation, for which the schedule has been suspended.

CPUC INVESTIGATION OF ENERGY-UTILITY HOLDING COMPANIES

The CPUC has initiated an investigation into the relationship between
California's IOUs and their parent holding companies. The CPUC broadly
determined that it could, in appropriate circumstances, require the
holding company to provide cash to a utility subsidiary to cover its
operating expenses and working capital to the extent they are not
adequately funded through retail rates. This would be in addition to
the requirement of holding companies to cover their utility
subsidiaries' capital requirements, as the IOUs previously acknowledged
in connection with the holding companies' formations. In January 2002,
the CPUC ruled on jurisdictional issues, deciding that the CPUC had
jurisdiction to create the holding company system and, therefore,
retains jurisdiction to enforce conditions to which the holding
companies had agreed.

In an opinion issued May 21, 2004, the California Court of Appeal
upheld the CPUC's assertion of limited enforcement jurisdiction, but
concluded that the CPUC's interpretation of the "first priority"
condition (that the holding companies could be required to infuse cash
into the utilities as necessary to meet the utilities' obligation to
serve) was not ripe for review at this time. On June 30, 2004, the
company requested review of the Court of Appeal's decision on the
jurisdictional issue by the California Supreme Court. To date, the
Supreme Court, which has discretionary authority to grant or deny
review, has not acted upon this request.

26

RECOVERY OF CERTAIN DISALLOWED TRANSMISSION COSTS

In August 2002, the FERC issued Opinion No. 458, which effectively
disallowed SDG&E's recovery of the differentials between certain
payments to SDG&E by its co-owners of the Southwest Powerlink (SWPL)
under the Participation Agreements and charges assessed to SDG&E under
the California Independent System Operator (ISO) FERC tariff for
transmission line losses and grid management charges related to energy
schedules of Arizona Public Service Co. (APS) and the Imperial
Irrigation District (IID), its SWPL co-owners. As a result, SDG&E is
incurring unreimbursed costs of $4 million to $8 million per year.
After SDG&E petitioned the United States Court of Appeals for review of
this order, the court remanded the case back to the FERC for further
consideration. FERC issued its Order on Remand on May 6, 2004. Although
it corrected several misstatements in its earlier opinions, FERC
essentially reaffirmed its original conclusions. After the Court of
Appeals rejected FERC's argument that SDG&E and other petitioners were
required to file for rehearing of the Order on Remand, the parties
jointly asked the court to set a schedule for completion of briefing.
The Court of Appeals has not yet ruled on this joint motion.

On July 6, 2001, in a separate matter related to ISO charges giving
rise to most of the cost differentials described above, SDG&E filed an
arbitration claim against the ISO, claiming the ISO should not charge
SDG&E for the transmission losses attributable to energy schedules on
the APS and the IID portions of the SWPL. The independent arbitrator
found in SDG&E's favor, awarding to SDG&E all amounts claimed, which
totaled $22 million, including interest, as of the time of the award.
The ISO appealed this result to the FERC and a FERC decision is
expected in 2004. SDG&E has also commenced a private arbitration to
reform the Participation Agreements to remove prospectively SDG&E's
obligation to provide the services that result in unreimbursed ISO
tariff charges. On April 6, 2004, the ISO filed its reply brief to
SDG&E's brief and the matter was submitted to the FERC. In addition,
APS, IID and Edison filed briefs in support of SDG&E's arbitration
award.

FERC ACTIONS

Refund Proceedings

The FERC is investigating prices charged to buyers in the California
Power Exchange (PX) and ISO markets by various electric suppliers. The
FERC is seeking to determine the extent to which individual sellers
have yet to be paid for power supplied during the period of October 2,
2000 through June 20, 2001 and to estimate the amounts by which
individual buyers and sellers paid and were paid in excess of
competitive market prices. Based on these estimates, the FERC could
find that individual net buyers, such as SDG&E, are entitled to refunds
and individual net sellers, such as SET, are required to provide
refunds. To the extent any such refunds are actually realized by SDG&E,
they would reduce SDG&E's rate-ceiling balancing account. To the extent
that SET is required to provide refunds, they could result in payments
by SET after adjusting for any amounts still owed to SET for power
supplied during the relevant period (or receipts if refunds are less
than amounts owed to SET).

27

In December 2002, a FERC ALJ issued preliminary findings indicating
that the California PX and ISO owe power suppliers $1.2 billion (the
$3.0 billion that the California PX and ISO still owe energy companies
less $1.8 billion that the energy companies charged California
customers in excess of the preliminarily determined competitive market
clearing prices). On March 26, 2003, the FERC adopted its ALJ's
findings, but changed the calculation of the refund by basing it on a
different estimate of natural gas prices. The March 26 order estimates
that the replacement formula for estimating natural gas prices will
increase the refund obligations from $1.8 billion to more than $3
billion.

The FERC recently released additional instructions and ordered the ISO
and PX to recalculate the precise number through their settlement
models. California is seeking $8.9 billion in refunds from its
electricity suppliers and has appealed the FERC's preliminary findings
and requested rehearing of the March 26 order. In March 2004, the
Attorney General of California requested the Ninth Circuit Court of
Appeals to compel the FERC to comply with the Court's earlier orders,
contending that the FERC had violated an August 2002 court order that
should have resulted in larger refunds to California and that the FERC
had failed to properly weigh evidence of market manipulation by power
companies when deciding the refunds due California ratepayers. SET and
other power suppliers have joined in appeal of the FERC's preliminary
findings and requested rehearing.

The company previously had established reserves for its likely share of
the original $1.8 billion. During the quarter ended June 30, 2004, the
company recorded additional reserves to reflect the estimated effect of
the FERC's revising the benchmark prices to be used by the FERC in
assessing the affect of the alleged actions.

Manipulation Investigation

The FERC is also investigating whether there was manipulation of short-
term energy markets in the West that would constitute violations of
applicable tariffs and warrant disgorgement of associated profits. In
this proceeding, the FERC's authority is not confined to the October 2,
2000 through June 20, 2001 period relevant to the refund proceeding. In
May 2002, the FERC ordered all energy companies engaged in electric
energy trading activities to state whether they had engaged in various
specific trading activities in violation of the PX and ISO tariffs
(generally described as manipulating or "gaming" the California energy
markets).

On June 25, 2003, the FERC issued several orders requiring various
entities to show cause why they should not be found to have violated
California ISO and PX tariffs. First, FERC directed 43 entities,
including SET and SDG&E, to show cause why they should not disgorge
profits from certain transactions between January 1, 2000 and June 20,
2001 that are asserted to have constituted gaming and/or anomalous
market behavior under the California ISO and/or PX tariffs. Second, the
FERC directed more than 20 entities, including SET, to show cause why
their activities during the period January 1, 2000 to June 20, 2001 did
not constitute gaming and/or anomalous market behavior in violation of
the tariffs. Remedies for confirmed violations could include

28

disgorgement of profits and revocation of market-based rate authority.
The FERC has encouraged the entities to settle the issues and on
October 31, 2003, SET agreed to pay $7.2 million in full resolution of
these investigations. That liability was recorded as of December 31,
2003. The entire proceeding, including the settlement, received final
FERC approval on July 28, 2004. SDG&E and the FERC resolved the matter
through a settlement which documents the ISO's finding that SDG&E did
not engage in market activities in violation of the ISO or PX tariffs,
and in which SDG&E agreed to pay $27,792 into a FERC-established fund
to conclude the matter as to SDG&E.

SDG&E has also worked with the California PX to address questions
raised in connection with certain ancillary service capacity
transactions that the PX carried out on behalf of SDG&E. SDG&E believes
that its data show that all of these transactions were legitimate and
that SDG&E always had capacity available to support its sales in the
ISO's ancillary service capacity markets. The PX has petitioned the
FERC, asking that the PX be dismissed from the show-cause proceeding.
The FERC has not yet acted on the PX's request.

On June 25, 2003, the FERC determined that it was appropriate to
initiate an investigation into possible physical and economic
withholding in the California ISO and PX markets. On August 1, 2003,
the FERC staff issued an initial report that determined there was no
need to further investigate particular entities, including SET, for
physical withholding of generation. For the purpose of investigating
economic withholding, the FERC used an initial screen of all bids
exceeding $250 per megawatt between May 1, 2000 and October 2, 2000.
Both SDG&E and SET received data requests from the FERC staff and
provided responses. In May 2004, based on the results of its
investigation, the FERC's Office of Market Oversight and Investigation
informed SDG&E and SET that their bidding procedures are no longer
being investigated by the FERC.

Settlement of Claims Associated with FERC's Investigations

During June and July, 2004, three settlements of claims associated with
FERC's investigations were announced. One settlement, in which SDG&E
will receive a net payment of $11.5 million, resolves all but a few
claims against The Williams Companies and Williams Power Company for
the period May 1, 2000 through June 20, 2001 and was approved by the
FERC on July 2, 2004. Another settlement, in which SDG&E will receive a
net payment of $13.8 million, resolves all claims against Dynegy, NRG
Energy and West Coast Power LLC for the period January 1, 2000 through
June 20, 2001 and has been submitted to the FERC for approval. A third
settlement, in which SDG&E will receive a net payment of $14.7 million,
resolves specified claims against Duke Energy for the period January 1,
2000 though June 20, 2001 and will be submitted to the FERC for
approval in the next few months. In all cases, the majority of the
funds would be received within 20 days of receiving FERC approval with
the remainder contingent on certain actions by the FERC, the ISO and
the PX. Receipt of the remaining amount by SDG&E would take place at
the conclusion of the FERC refund proceeding, now expected to be in
early 2006. These funds would be received for the benefit of SDG&E's
bundled customers and will reimburse SDG&E for the costs of litigating
this matter. Claims alleged against SET are still pending.

29

NOTE 7. CONTINGENCIES

NUCLEAR INSURANCE

SDG&E and the other owners of SONGS have insurance to respond to
nuclear liability claims related to SONGS. Detail to the coverage is
provided in the Annual Report. As of June 30, 2004, the secondary
financial protection provided by the Price-Anderson Act is $10.5
billion if the liability loss exceeds the insurance limit of $300
million. In addition, the maximum SDG&E could be assessed is $8.8
million should there be a retrospective premium call under the risk
sharing arrangements of the nuclear property, decontamination and
debris removal insurance policy.

Both the nuclear liability and property insurance programs subscribed
to by members of the nuclear power generating industry include industry
aggregate limits for non-certified acts, as defined by the Terrorism
Risk Insurance Act, of terrorism-related SONGS losses, including
replacement power costs. An industry aggregate limit of $300 million
exists for liability claims, regardless of the number of non-certified
acts affecting SONGS or any other nuclear energy liability policy or
the number of policies in place. An industry aggregate limit of $3.24
billion exists for property claims, including replacement power costs,
for non-certified acts of terrorism affecting SONGS or any other
nuclear energy facility property policy within twelve months from the
date of the first act. These limits are the maximum amount to be paid
to members who sustain losses or damages from these non-certified
terrorist acts. For certified acts of terrorism, the individual policy
limits stated above apply.

SPENT NUCLEAR FUEL

SONGS owners have responsibility for the interim storage of spent
nuclear fuel generated at San Onofre, until it is accepted by the DOE
for final disposal. Spent nuclear fuel is stored in the San Onofre
Units 1, 2 and 3 Spent Fuel Pools (SFP) and the San Onofre Independent
Spent Fuel Storage Installation (ISFSI). Movement of Unit 1 spent fuel
from the Unit 3 SFP to the ISFSI was completed in late 2003. Movement
of Unit 1 spent fuel from the Unit 1 SFP to the ISFSI is scheduled to
be completed by late 2004 and from the Unit 2 SFP to the ISFSI by late
2005. With these moves, there will be sufficient space in the Unit 2
and 3 SFPs to meet plant requirements through mid-2007 and mid-2008,
respectively.

ARGENTINE INVESTMENTS

As a result of the devaluation of the Argentine peso at the end of 2001
and subsequent declines in the value of the peso, SEI reduced the
carrying value of its investment downward by a cumulative total of $197
million as of June 30, 2004 and December 31, 2003. These non-cash
adjustments continue to occur based on fluctuations in the Argentine
peso. They do not affect net income, but increase or decrease other
comprehensive income (loss) and accumulated other comprehensive income
(loss).

A decision is expected in 2005 on SEI's arbitration proceedings under
the 1994 Bilateral Investment Treaty between the United States and

30

Argentina for recovery of the diminution of the value of SEI's
investments that has resulted from Argentine governmental actions.
Sempra Energy also has a $48.5 million political-risk insurance policy
under which it filed a claim to recover a portion of the investments'
diminution in value.

LITIGATION

Except for the matters referred to below, neither the company nor its
subsidiaries are party to, nor is their property the subject of, any
material pending legal proceedings other than routine litigation
incidental to their businesses. Management believes that none of these
matters will have further material adverse effect on the company's
financial condition or results of operations.

DWR Contract

In 2003, SER was awarded judgment in its favor in the state civil
action between SER and the DWR, in which the DWR sought to void its 10-
year contract under which the company sells energy to the DWR. The DWR
filed an appeal of this ruling in January 2004. A decision by the
appellate court is expected during 2005.

The DWR continues to accept all scheduled power from SER and, although
it has disputed billings in an immaterial amount and the manner of
certain deliveries, it has paid all amounts that have been billed under
the contract. However, in 2004, the DWR has commenced an arbitration
proceeding, disputing SER's performance on various operational matters.
Among other proposed remedies, the DWR has requested a declaration by
the arbitration panel that SER's inadequate performance constitutes a
material breach of the agreement permitting it to terminate the
contract. SER believes these claims are without merit.

Antitrust Litigation

Class-action and individual lawsuits filed in 2000 and currently
consolidated in San Diego Superior Court seek damages, alleging that
Sempra Energy, SoCalGas and SDG&E, along with El Paso Energy Corp. (El
Paso) and several of its affiliates, unlawfully sought to control
natural gas and electricity markets. In March 2003, plaintiffs in these
cases and the applicable El Paso entities (whose cases involved
unrelated claims not applicable to Sempra Energy, SoCalGas or SDG&E)
announced that they had reached a $1.7 billion settlement, of which
$125 million is allocated to customers of the California Utilities. The
Court approved that settlement in December 2003. The proceeding
against Sempra Energy and the California Utilities has not been settled
and continues to be litigated. On July 22, 2004, the court heard oral
argument on a motion for summary judgment brought by Sempra Energy and
the California Utilities and is expected to issue a decision in August
2004. Trial is set for September 7, 2004.

Natural Gas Cases: Lawsuits have been filed by the Attorneys General
of Arizona and Nevada, alleging that El Paso and certain Sempra Energy
subsidiaries unlawfully sought to control the natural gas market in
their respective states. In October 2003, the Nevada state court denied
defendants' motion to dismiss the complaint. On April 12, 2004, the
Sempra Energy defendants filed a motion for reconsideration. In April

31

2003, Sierra Pacific Resources and its utility subsidiary Nevada Power
filed a lawsuit in U.S. District Court in Las Vegas against major
natural gas suppliers, including Sempra Energy, the California
Utilities and other company subsidiaries, seeking damages resulting
from an alleged conspiracy to drive up or control natural gas prices,
eliminate competition and increase market volatility, breach of
contract and wire fraud. On January 27, 2004, the U.S. District Court
dismissed the Sierra Pacific Resources case against all of the
defendants, determining that this is a matter for the FERC to resolve.
The court granted plaintiffs' request to amend their complaint, which
they did. On July 15, 2004, Sempra Energy filed another motion to
dismiss, which is scheduled to be heard on September 23, 2004.

Electricity Cases: Various lawsuits, which seek class-action
certification, allege that Sempra Energy and certain subsidiaries
(SDG&E, SET and SER, depending on the lawsuit) unlawfully manipulated
the electric-energy market. In January 2003, the federal court granted
a motion to dismiss a similar lawsuit on the grounds that the claims
contained in the complaint were subject to the Filed Rate Doctrine and
were preempted by the Federal Power Act. That ruling was appealed to
the Ninth Circuit Court of Appeals and oral argument was heard on June
14, 2004. In addition, in May 2003, the Port of Seattle filed a similar
complaint against a number of energy companies (including Sempra
Energy, SER and SET). That action was dismissed by the San Diego
Federal District Court in May 2004. Plaintiff has appealed the
decision. In May and June 2004, two new cases were filed in federal
court alleging substantially identical claims to those in Port of
Seattle against Sempra Energy and certain subsidiaries (SDG&E, SER and
SET depending on the lawsuit).

SER, SET and SDG&E, along with all other sellers in the western power
market, have been named defendants in a complaint filed at the FERC by
the California Attorney General's office seeking refunds for
electricity purchases based on alleged violations of FERC tariffs. The
FERC has dismissed the complaint. The California Attorney General filed
an appeal in the Ninth Circuit of Appeals and oral argument was heard
in October 2003. No decision has yet been rendered.

Price Reporting Practices

In May 2003 and February 2004, actions against various trade
publications and other energy companies, alleging that energy prices
were unlawfully manipulated by defendants' reporting artificially
inflated natural gas prices to trade publications and by entering into
wash trades, were filed in San Diego Superior Court against Sempra
Energy and SET. Both actions have been removed to Federal District
Court. Another lawsuit containing identical allegations was filed
against Sempra Energy and SET in Federal District Court in November of
2003. On July 8, 2004, the City and County of San Francisco and the
County of Santa Clara and on July 18, 2004 the County of San Diego
brought similar actions in San Diego Superior Court against Sempra
Energy, SET, SoCalGas and SDG&E. In addition, in August 2003, a lawsuit
was filed in the Southern District of New York against Sempra Energy
and SES, alleging that the prices of natural gas options traded on the
NYMEX were unlawfully increased under the Federal Commodity Exchange
Act by defendants' manipulation of transaction data provided to natural
gas trade publications. In November of 2003, another suit containing

32

identical allegations was filed and consolidated with the New York
action. Subsequently, plaintiffs dismissed Sempra Energy and SES from
these cases. On January 20, 2004, plaintiffs filed an amended
consolidated complaint that named SET as a defendant in this lawsuit.
In March 2004, defendants filed a motion to dismiss the action. No
hearing date has been set by the Court.

Other

The Utility Consumers' Action Network (UCAN), a consumer-advocacy group
which had requested a CPUC rehearing of a CPUC decision concerning the
allocation of certain power contract gains between SDG&E customers and
the company, appealed the CPUC's rehearing denial to the California
Court of Appeal. On July 12, 2004, the Court of Appeal affirmed the
CPUC's decision. UCAN has 40 days to appeal.

In May 2003, a federal judge issued an order finding that the
Department of Energy's (DOE) abbreviated assessment of two Mexicali
power plants, including SER's Termoelectrica de Mexicali (TDM) plant,
failed to evaluate the plants' environmental impact adequately and
called into question the U.S. permits they received to build their
cross-border transmission lines. In July 2003, the judge ordered the
DOE to conduct additional environmental studies and denied the
plaintiffs' request for an injunction blocking operation of the
transmission lines, thus allowing the continued operation of the TDM
plant. The DOE undertook to perform an Environmental Impact Study,
which is expected to be completed in December 2004.

The Peruvian appellate court has affirmed the dismissal of the charges
against officers of Luz del Sur S.A.A. (Luz del Sur), a company
affiliate, and others concerning the price of utility assets acquired
by Luz del Sur from the Peruvian government.

At June 30, 2004, SET remains due approximately $100 million from
energy sales made in 2000 and 2001 through the ISO and the PX markets.
The collection of these receivables depends on several factors,
including the FERC refund case. The company believes adequate reserves
have been recorded.

Customers of the California Utilities will receive benefits under
a settlement with El Paso resolving a number of civil and
administrative proceedings surrounding the high natural gas and
electric prices experienced in several Western states during the March
2000 through May 2001 period. A total amount of settlement funds of
$40.7 million to SoCalGas' core gas customers, $33.3 million to SDG&E's
core gas customers and $66.6 million to SDG&E's electric customers will
be received over a period of 20 years. An initial lump sum payment of
$42 million was received in June 2004, which will be followed by 19
annual payments.

33

INCOME TAX ISSUES

Section 29 Income Tax Credits

On July 1, 2004, SEF sold its investment in an enterprise that earns
Section 29 income tax credits. That investment comprised one-third of
Sempra Energy's Section 29 participation and was sold because the
company's alternative minimum tax position defers utilization of the
credits in the determination of income taxes currently payable. The
sale will have a minor negative affect on the company's recorded income
in the future, but will have a minor positive affect on its cash flow.

The IRS recently concluded its examinations of the company's Section 29
income tax credits for certain years, reporting no change in the
credits. From acquisition of the facilities in 1998 through December
31, 2003, the company has generated Section 29 income tax credits of
$251 million. In addition, the company has generated Section 29 tax
credits of $51 million for the six months ended June 30, 2004, of which
$27 million occurred in the second quarter. The company believes
disallowance of its Section 29 income tax credits is unlikely.

NOTE 8. SEGMENT INFORMATION

The company is a holding company, whose subsidiaries are primarily
engaged in the energy business. It has four separately managed
reportable segments: SoCalGas, SDG&E, SET and SER, which are described
in the Annual Report.

The accounting policies of the segments are described in the notes to
Consolidated Financial Statements in the Annual Report, and segment
performance is evaluated by management based on reported income. There
were no significant changes in segment assets during the six months
ended June 30, 2004.

34

ITEM 2.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion should be read in conjunction with the
financial statements contained in this Form 10-Q and "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" contained in the Annual Report.

OVERVIEW

Sempra Energy is a Fortune 500 energy services holding company. Its
business units provide a wide spectrum of value-added electric and
natural gas products and services to a diverse range of customers.
Operations are divided between delivery services, comprised of the
California utility subsidiaries, and Sempra Energy Global Enterprises.

RESULTS OF OPERATIONS

Net income and operating income for the three months and for the six
months ended June 30, 2004 were up substantially from the corresponding
periods of 2003. The following table summarizes the major factors
affecting the comparisons for both periods.

35

California Utility Revenues and Cost of Sales

Natural gas revenues increased to $2.3 billion for the six months ended
June 30, 2004 from $2.1 billion for the corresponding period in 2003,
and the cost of natural gas increased to $1.3 billion in 2004 from $1.2
billion in 2003. These increases were primarily attributable to natural
gas cost increases, which are passed on to customers, and increased
volumes. Additionally, natural gas revenues were relatively unchanged
at $947 million for the quarter ended June 30, 2004 compared to $929
million for the corresponding period in 2003, and the cost of natural
gas was relatively unchanged at $482 million in 2004 compared to $480
million in 2003. Higher natural gas costs in the second quarter of 2004
were offset by lower gas sales volumes.

Under the current regulatory framework, the cost of natural gas
purchased for customers and the variations in that cost are passed
through to the customers on a substantially concurrent basis. However,
SoCalGas' GCIM allows SoCalGas to share in the savings or costs from
buying natural gas for customers below or above monthly benchmarks. The
mechanism permits full recovery of all costs within a tolerance band
above the benchmark price and refunds all savings within a tolerance
band below the benchmark price. The costs or savings outside the
tolerance band are shared between customers and shareholders. In
addition, SDG&E's natural gas procurement PBR mechanism provides an
incentive mechanism by measuring SDG&E's procurement of natural gas
against a benchmark price comprised of monthly natural gas indices,
resulting in shareholder rewards for costs achieved below the benchmark
and shareholder penalties when costs exceed the benchmark.

Electric revenues increased to $801 million for the six months ended
June 30, 2004 from $792 million for the same period in 2003, and the
cost of electric fuel and purchased power decreased to $282 million in
2004 from $300 million in 2003. The increase in revenues was the
result of higher volumes and higher operating costs that are recovered
in rates via balancing accounts, offset by more power being provided by
the DWR as discussed in Note 6 of the notes to Consolidated Financial
Statements, while the decrease in the cost of electric fuel and
purchased power was mainly due to more power being provided by the DWR.
Additionally, electric revenues increased to $420 million for the
quarter ended June 30, 2004 from $397 million for the same period in
2003, and the cost of electric fuel and purchased power increased to
$155 million in 2004 from $137 million in 2003. These changes were
mainly due to higher volumes. Under the current regulatory framework,
changes in commodity costs normally do not affect net income.

In 2002, the California Utilities filed Cost Of Service applications
with the CPUC, seeking rate increases reflecting forecasts of 2004
capital and operating costs, as further discussed in the Annual Report.
In accordance with generally accepted accounting principles, the
California Utilities are generally recognizing 2004 revenue consistent
with the proposed settlements, except for amounts related to pension
costs which are pending the CPUC decision and CPUC acceptance of a
related compliance filing. Resolution of the pension matter consistent
with the proposed settlement would result in the recording of
additional income at that time. To the extent, if any, that the final
CPUC decision varies from the method used to recognize revenue prior to
that decision, an accounting adjustment will be recorded at that time.

36

To date, the impacts of accounting consistent with the settlement have
not had a material effect on the financial statements.

The tables below summarize the natural gas and electric volumes and
revenues by customer class for the six months ended June 30, 2004 and
2003.

Natural Gas Sales, Transportation and Exchange
(Volumes in billion cubic feet, dollars in millions)

Electric Distribution and Transmission
(Volumes in millions of kilowatt hours, dollars in millions)

37

Although commodity-related revenues from the DWR's purchasing of
SDG&E's net short position or from the DWR's allocated contracts are
not included in revenue, the associated volumes and distribution
revenue are included herein.

Beginning in 2004, off-system sales are accounted for as a reduction of
the cost of purchased power.

Other Operating Revenues

Other operating revenues, which consist primarily of revenues at
Global, increased to $1.3 billion for the six months ended June 30,
2004 from $880 million for the same period of 2003, and increased to
$629 million for quarter ended June 30, 2004 from $514 million for the
same period of 2003. These changes were primarily due to higher
revenues at SER resulting from increased volumes of contract sales
associated with energy produced by the new generating plants. The
increase for the six-month period was also due to higher revenues at
SET resulting from increased commodity revenue from metals and
petroleum.

Other Cost of Sales

Other cost of sales, which consists primarily of cost of sales at
Global, increased to $702 million for the six months ended June 30,
2004 from $515 million for the same period of 2003, and increased to
$375 million for the quarter ended June 30, 2004, from $296 million for
the same period in 2003. The increases were primarily due to costs
related to the higher sales for SER as noted above.

Other Operating Expenses

Other operating expenses increased to $1.1 billion for the six months
ended June 30, 2004 from $1.0 billion for the same period in 2003,
including $716 million and $682 million in 2004 and 2003, respectively,
related to the California Utilities. The increase was primarily due to
higher operating costs at SET related to increased trading activity,
the new generating plants coming on line and litigation expenses.
Additionally, increases were due to nuclear refueling costs at SONGS
and increases in other operating expenses at the California Utilities.

Other operating expenses increased to $546 million for the quarter
ended June 30, 2004 from $518 million for the same period in 2003,
including $374 million and $364 million in 2004 and 2003, respectively,
related to the California Utilities. The change was due primarily to
the increased litigation costs, nuclear refueling costs at SONGS and
increases in other operating expenses at the California Utilities.

Other Income - Net

Other income, which primarily consists of equity earnings from
unconsolidated subsidiaries and interest on regulatory balancing
accounts, increased to $18 million for the six months ended June 30,
2004 from $4 million for the same period of 2003, and increased to $13
million for the quarter ended June 30, 2004 from $9 million for the
same period of 2003. The increase for the six-month period was
primarily due to the $8 million after tax gain on the settlement of an

38

unpaid portion of the purchase price of the proposed Cameron LNG
project for an amount less than the liability (which had been recorded
as a derivative) and increased equity earnings at SEI, including $5
million from the partial sale of Luz del Sur. The increase for the
quarter was due to lower regulatory interest expense at SoCalGas and
the increased equity earnings at SEI.

Interest Income

Interest income increased to $33 million for the six months ended June
30, 2004 from $22 million for the same period of 2003 due primarily to
interest from the Internal Revenue Service during the first quarter of
2004.

Interest Expense

Interest expense increased to $160 million for the six months ended
June 30, 2004 from $145 million for the same period of 2003, and
increased to $80 million for the quarter ended June 30, 2004 from $71
million for the same period of 2003. The increases were primarily the
result of the reclassification of preferred dividends on mandatorily
redeemable trust preferred securities and preferred stock of
subsidiaries to interest expense as a result of the adoption on July 1,
2003 of SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of Liabilities and Equity," as well as higher
capitalized interest at SER in 2003.

Income Taxes

Income tax expense increased to $88 million for the six months ended
June 30, 2004 from $51 million for the same period of 2003. The
corresponding effective income tax rates were 20.1 percent and 17.9
percent, respectively. Additionally, income tax expense increased to
$31 million for the second quarter of 2004 compared to $27 million for
the second quarter of 2003, and the effective income tax rate increased
to 19.6 percent in 2004 from 19.0 percent in 2003. The changes were due
primarily to higher taxable income and the higher effective income tax
rate in 2004, despite the reduction in estimated income tax liabilities
for certain prior years. Discussion of Section 29 income tax credits is
provided in Note 7 herein and in Note 7 of the notes to Consolidated
Financial Statements of the Annual Report.

Discontinued Operations

During the first quarter of 2004 Sempra Energy's Board of Directors
approved management's plan to dispose of the company's interest in AEG.
On April 27, 2004, the company disposed of AEG at a $2 million loss net
of income taxes. Including the $2 million loss on disposal, AEG's
losses were $32 million ($0.14 per diluted share) and $8 million ($0.04
per diluted share), respectively, for the six months and three months
ended June 30, 2004. Note 4 of the notes to Consolidated Financial
Statements provides further details.

During 2003, the company accounted for its investment in AEG under the
equity method of accounting. As such, for the six-month and three-month
periods ended June 30, 2003, the company recorded its share of AEG's
net loss as a $6 million and $3 million loss, respectively, in Other

39

Income - Net on the Statements of Consolidated Income. Additionally,
the company recorded offsetting interest income of $1 million for both
periods. Effective December 31, 2003, AEG was consolidated as a result
of the adoption of FIN 46. This is discussed further in Note 2 herein
and in the Annual Report.

Net Income

Net income for the six months ended June 30 increased to $318 million,
or $1.37 per diluted share of common stock, in 2004 from $204 million,
or $0.98 per diluted share in 2003. Additionally, net income for the
second quarter was $121 million, or $0.52 per diluted share for 2004,
compared to $116 million or $0.55 per diluted share in 2003. Unusual
items affecting these comparisons are provided in the first table in
this section. Although net income increased for both periods, earnings
per share were impacted by dilution from the issuance of 16.5 million
additional shares in the fourth quarter of 2003.

The only differences between basic and diluted earnings per share are
the effects of common stock options and the Equity Units, discussed in
Note 12 of the Annual Report.

Net Income by Business Unit

40

SOUTHERN CALIFORNIA GAS COMPANY

SoCalGas recorded net income of $106 million and $95 million for the
six-month periods ended June 30, 2004 and 2003, respectively, and net
income of $50 million and $37 million for the quarters ended June 30,
2004 and 2003, respectively. The changes were primarily due to improved
operating results in 2004.

SAN DIEGO GAS & ELECTRIC

SDG&E recorded net income of $80 million and $86 million for the six-
month periods ended June 30, 2004 and 2003, respectively, and net
income of $30 million and $41 million for the quarters ended June 30,
2004 and 2003, respectively. The decreases were primarily due to the
absence of the 2003 Incremental Cost Incentive Pricing for SONGS and
performance-based regulation gains and higher operating costs, offset
by higher revenues.

SEMPRA ENERGY TRADING

SET recorded net income of $99 million and $45 million for the six-
month periods ended June 30, 2004 and 2003, respectively, excluding the
cumulative effect of the change in accounting principle of ($28)
million in 2003. Additionally, SET recorded net income of $40 million
and $35 million for the quarters ended June 30, 2004 and 2003,
respectively. The increases were primarily attributable to higher
trading margin on metals and petroleum, offset by litigation expenses.

A summary of SET's unrealized revenues for trading activities for the
six months ended June 30, 2004 and 2003 follows:

(Dollars in millions) 2004 2003
- -----------------------------------------------------------------
Balance at December 31 $ 269 $ 180
Cumulative effect adjustment -- (48)
Additions 701 599
Realized (369) (277)
----------------------
Balance at June 30 $ 601 $ 454
- -----------------------------------------------------------------

41

The estimated fair values for SET's trading activities as of June 30,
2004, and the periods during which unrealized revenues are expected to
be realized, are (dollars in millions):

* The present value of unrealized revenue to be received or (paid) from
outstanding OTC contracts.
** Cash (paid) or received associated with open exchange contracts.

SET's Value at Risk (VaR) amounts are described in Item 3.

The CPUC's prohibition of IOUs' procuring electricity from their
affiliates is discussed in "Electric Industry Regulation" in Note 13 of
the Annual Report.

SEMPRA ENERGY RESOURCES

SER recorded net income of $59 million and $15 million for the six-
month periods ended June 30, 2004 and 2003, respectively, and net
income of $22 million and $5 million for the quarters ended June 30,
2004 and 2003, respectively. The changes were primarily due to higher
volumes of contract sales associated with energy produced by the new
generating plants, offset by litigation costs.

During March 2004 the El Dorado generating plant, 50% owned by SER,
suffered significant damage to a transformer requiring the plant to
cease operations temporarily. Replacement equipment was installed and
the plant was placed back into service at the end of May. Insurance
claims have been filed for the cost of repairs, replacement and related
project losses.

SEMPRA ENERGY INTERNATIONAL/LNG
SEI/SELNG recorded net income of $32 million and $25 million for the
six-month periods ended June 30, 2004 and 2003, respectively, and net
income of $15 million and $18 million for the quarters ended June 30,
2004 and 2003, respectively. The increase for the six-month period was
due primarily to the settlement of an unpaid portion of the purchase

42

price of the proposed Cameron LNG project for an amount less than the
liability (which had been recorded as a derivative). Additionally, the
changes for both periods were impacted by a gain on the sale of a
portion of SEI's interests in Luz del Sur, a Peruvian electric utility,
and increased earnings from the company's Gasoducto Bajanorte natural
gas pipeline, offset by the impact of changes in estimates for certain
income tax issues in the second quarter of 2004 and start-up costs at
SELNG.

SEMPRA ENERGY SOLUTIONS

SES recorded a net loss of $1 million and net income of $8 million for
the six-month periods ended June 30, 2004 and 2003, respectively,
excluding the cumulative effect of the change in accounting principle
of ($1) million in 2003. SES recorded net income of $3 million and $8
million for the quarters ended June 30, 2004 and 2003, respectively.
The decreases in 2004 were primarily due to lower net commodity
revenues.

SEMPRA ENERGY FINANCIAL

SEF recorded net income of $16 million and $19 million for the six-
month periods ended June 30, 2004 and 2003, respectively, and net
income of $6 million and $8 million for the quarters ended June 30,
2004 and 2003, respectively.

PARENT AND OTHER

Net losses for Parent and Other were $41 million and $60 million for
the six-month periods ended June 30, 2004 and 2003, respectively, and
$37 million and $36 million for the quarters ended June 30, 2004 and
2003, respectively. The six-month period improved primarily because of
increased interest income in 2004 and the change in estimate of federal
and state income tax liabilities for certain prior years.

CAPITAL RESOURCES AND LIQUIDITY

The company's California Utility operations are the major source of
liquidity. Funding of other business units' capital expenditures is
significantly dependent on the California Utilities' paying sufficient
dividends to Sempra Energy and on SET's liquidity requirements, which
fluctuate significantly.

At June 30, 2004, the company had $1.2 billion in cash and $2.6 billion
in available unused, committed lines of credit. Total available unused,
committed lines of credit increased to $3.1 billion at July 31, 2004.
See "Cash Flows from Financing Activities" for discussion on changes in
credit facilities in 2004.

Management believes these amounts and cash flows from operations and new
security issuances will be adequate to finance capital expenditure
requirements, shareholder dividends, any new business acquisitions or
start-ups, and other commitments. If cash flows from operations were to
be significantly reduced or the company were to be unable to issue new
securities on acceptable terms, neither of which is considered likely,
the company would be required to reduce non-utility capital expenditures

43

and investments in new businesses. Management continues to regularly
monitor the company's ability to finance the needs of its operating,
financing and investing activities in a manner consistent with its
intention to maintain strong, investment-quality credit ratings. Rating
agencies and others that evaluate a company's liquidity generally
consider a company's capital expenditures and working capital
requirements in comparison to cash from operations, available credit
lines and other sources available to meet liquidity requirements.

At the California Utilities, cash flows from operations and from new and
refunding debt issuances are expected to continue to be adequate to meet
utility capital expenditure requirements and provide dividends to Sempra
Energy. In June 2004, SDG&E received CPUC approval of its plans to
purchase from SER a $456 million, 550-MW generating facility to be
constructed in Escondido, California. As a result, the level of SDG&E's
dividends to Sempra Energy is expected to be significantly lower during
the construction of the facility to enable SDG&E to increase its equity
in preparation for the purchase of the completed facility.

SET provides or requires cash as the level of its net trading assets
fluctuates with prices, volumes, margin requirements (which are
substantially affected by credit ratings and commodity price
fluctuations) and the length of its various trading positions. Its
status as a source or use of cash also varies with its level of
borrowing from its own sources. SET's intercompany borrowings were
$461 million at June 30, 2004, up from $359 million at December 31,
2003. SET's external debt was $72 million at June 30, 2004. In June
2004, SET obtained a $1 billion revolving line of credit. Additional
information on the line of credit is provided in "Cash Flows from
Financing Activities." Company management continuously monitors the
level of SET's cash requirements in light of the company's overall
liquidity.

SELNG will require funding for its planned development of LNG receiving
facilities. While funding from the company is expected to be adequate
for these requirements, the company may decide to use project financing
if that is believed to be advantageous.

SEI is expected to require funding from the company and/or external
sources to continue the expansion of its existing natural gas
distribution operations in Mexico and its planned development of
pipelines to serve LNG facilities expected to be developed in Baja
California, Mexico; Hackberry, Louisiana; and Port Arthur, Texas, as
discussed in "Cash Flows From Investing Activities," below.

SER's projects are expected to be financed through a combination of
project financing, SER's cash from operations and borrowings, and funds
from the company.

In the longer term, SEF is expected to again be a net provider of cash
through reductions of consolidated income tax payments resulting from
its investments in affordable housing. However, that was not true in
2003 and will not be true in the near term, while the company is in an
alternative minimum tax position.

44

CASH FLOWS FROM OPERATING ACTIVITIES

Net cash provided by operating activities totaled $652 million and $758
million for the six months ended June 30, 2004 and 2003, respectively.
The change was attributable to an increase in net trading assets in 2004
compared to a decrease in 2003, partially offset by higher net income
and a higher decrease in accounts receivable in 2004.

For the six months ended June 30, 2004, the company made pension plan
contributions of $9 million and payments for other postretirement
benefit plans of $30 million.

CASH FLOWS FROM INVESTING ACTIVITIES

Net cash provided by (used in) investing activities totaled $12 million
and $(641) million for the six months ended June 30, 2004 and 2003,
respectively. The change was primarily attributable to proceeds from the
sale of U.S. Treasury obligations which previously securitized the
Mesquite synthetic lease. The collateral was no longer necessary as SER
bought out the lease in January 2004. The decrease in cash used in
investing activities was also due to lower investments primarily as a
result of completion of the Elk Hills and Mesquite power plants. In
addition, the company had proceeds of $112 million from the disposal of
AEG's discontinued operations.

On April 1, 2004, SEI and PSEG Global, an unaffiliated company, sold a
portion of their interests in Luz del Sur for a total of $62 million.
Each party had a 44-percent interest in Luz del Sur prior to the sale
compared to a 38-percent interest after the sale was completed. SEI
recognized an after-tax gain of $5 million as a result of the sale.

Starting in 2003 and through the end of the second quarter of 2004, SET
spent $77 million related to the development of Bluewater Gas Storage,
LLC. SET owns the rights to develop the facility and to utilize its
capacity to store natural gas for customers who buy, sell or transport
natural gas to Michigan. The FERC-regulated, market-based-pricing
facility started injecting natural gas during the second quarter of
2004.

On April 16, 2004, the company announced the acquisition of land and
associated rights for the development of a salt-cavern natural gas
storage facility in Evangeline Parish, Louisiana. This facility,
operating as the Pine Prairie Energy Center, will consist of three salt
caverns with a total capacity of 24 billion cubic feet (bcf) of natural
gas and is expected to begin operations by the fourth quarter of 2005
and to cost approximately $175 million. The company is currently
negotiating contracts to sell the capacity of this facility. FERC
approval for the construction and operation of the facility is pending.
On July 20, 2004, the company announced that it had acquired the rights
to develop a salt-cavern natural gas storage facility located in
Calcasieu Parish, Louisiana, called "Liberty," that is expected to have
capacity of 17 bcf.

On April 21, 2004, SELNG announced plans to develop and construct a new
$600 million LNG receiving terminal near Port Arthur, Texas. The
terminal would be capable of processing 1.5 bcf of natural gas per day
and could be expanded to 3 bcf per day. The company is currently in the

45

process of obtaining FERC approval for the construction of the terminal.
The project is expected to begin construction in 2006 with start-up
slated for 2009.

On July 1, 2004, Sempra Energy Partners and Carlyle/Riverstone, an
energy and power-focused equity fund, completed their acquisition of ten
power plants from American Electric Power (AEP), including the Coleto
Creek Power Station, a 632-MW coal-fired power plant in Goliad County,
Texas, for $430 million and advanced additional working capital. $355
million of the purchase price was provided by project financing which is
non-recourse to the joint venture partners. Excluding the Coleto Creek
Power Station, the transaction included the acquisition of five
operating power plants with generating capacity of 1,318 MW and four
inactive power plants (capable of generating 1,863 MW) in Texas. The
joint venture partners have sold one of the inactive power plants.
Coleto Creek Power Station and the eight other power plants retained by
the partners will comprise the newly formed Topaz Power Partners, a
50/50 joint venture. In addition, the joint venture partners have
entered into several power sales agreements for 572 MW of Coleto Creek
Power Station's capacity. The weighted-average life of the contracts is
4.3 years.

The company expects to make capital expenditures and investments of $1.2
billion in 2004, of which $511 million had been expended as of June 30,
2004. Significant capital expenditures and investments are expected to
include $750 million for California utility plant improvements and $100
million for the development of LNG regasification terminals. These
expenditures and investments are expected to be financed by cash flows
from operations and security issuances.

In connection with the importation of additional sources of natural gas
into Southern California, for which the California Utilities have made
filings with the CPUC, the California Utilities could install capital
facilities estimated at up to $200 million over three years, starting in
2005, in order to connect with new delivery locations. The expenditures
would be included in utility ratebases or would be reimbursed by LNG
project developers dependent on CPUC review of the projects and on the
outcome of the Gas Market Order Instituting Investigation Phase II
proceeding.

CASH FLOWS FROM FINANCING ACTIVITIES

Net cash provided by (used in) financing activities totaled $54 million
and $(247) million for the six months ended June 30, 2004 and 2003,
respectively. The change was due to higher long-term debt issuances and
a net increase in short-term debt, partially offset by higher long-term
debt payments in 2004.

In May 2004, the company issued $600 million of senior unsecured notes,
consisting of $300 million of 4.75-percent fixed-rate, five-year notes
and $300 million of four-year, floating-rate notes. The proceeds of the
issuance were used to repay $500 million of debt maturing July 1, 2004,
and for general corporate purposes. In June 2004, SDG&E issued $251
million of first mortgage bonds and applied the proceeds in July to
refund an identical amount of first mortgage bonds and related tax-
exempt industrial development bonds of a shorter maturity. The bonds,
which mature in 2034 ($176 million) and in 2039 ($75 million), bear

46

interest at rates that are periodically reset through auction
procedures. They secure the repayment of tax-exempt industrial
development bonds of an identical amount, maturity and interest rate
issued by City of Chula Vista, the proceeds of which were loaned to
SDG&E and repaid with payments on the first mortgage bonds. In January
2004, SER purchased the assets of Mesquite Trust, the owner of the
Mesquite Power plant, thereby extinguishing $630 million of debt
outstanding. Also in 2004, SoCalGas repaid $175 million of first
mortgage bonds.

In May 2004, the California Utilities obtained a combined $500 million
three-year syndicated revolving credit facility to replace their
expiring 364-day facility of a like amount. Under the facility, each
utility may borrow up to $300 million, subject to a combined borrowing
limit of $500 million. Borrowings would bear interest at rates varying
with market rates and the borrowing utility's credit rating. The
agreement requires each utility to maintain, at the end of each
quarter, a ratio of total indebtedness to total capitalization (as
defined in the agreement) of no more than 60 percent. Borrowings under
the agreement would be individual obligations of the borrowing utility
and a default by one utility would not constitute a default or preclude
borrowings by the other.

In May 2004, the company entered into an interest-rate swap agreement
that effectively changed the interest rate on $300 million of 7.95%
notes (issued in February 2000) from fixed to floating. The swap is set
to expire in 2010, the same year the related debt matures.

In June 2004, SET obtained a two-year syndicated revolving line of
credit providing for extensions of credit (consisting of borrowings,
letters of credit and other credit support accommodations) to SET and
certain of its affiliates of up to $1 billion. The amount of credit
extended on a non-guaranteed basis is limited by the amount of a
borrowing base consisting of receivables, inventories and other assets
of SET that secure the credit facility and are valued for purposes of
the borrowing base at varying percentages of current market value.
Credit utilization above the borrowing base (up to a maximum of $500
million) is guaranteed by Sempra Energy subject to the overall $l
billion credit limit. Non-guaranteed extensions of credit bear
interest and fees that vary with SET's tangible net worth and
guaranteed extensions bear interest and fees varying with Sempra
Energy's credit ratings. Extensions of credit are subject to the
absence of any development or event that has had or would reasonably be
expected to have a material adverse effect on SET. The facility also
requires SET to meet certain financial tests at the end of each quarter
(including a current ratio, leverage ratio and minimum consolidated net
worth tests) and (while guaranteed borrowings are outstanding) also
requires Sempra Energy to meet, at the end of each quarter and as
defined in the credit facility, a leverage ratio of consolidated
indebtedness to consolidated total capitalization of not more than .65
to 1. It also imposes certain other limitations on SET including
limitations on other indebtedness, capital expenditures, liens,
transfers of assets, investments, loans, advances, dividends, other
distributions, modifications of risk-management policies and
transactions with affiliates. The facility replaced $490 million of
SET's $764 million uncommitted credit lines. At June 30, 2004

47

outstanding extensions of credit under the facility totaled $371
million.

In July 2004, Global obtained a $1.5 billion three-year syndicated
revolving credit facility to replace its expiring $500 million
revolving credit facility and the expiring $400 million revolving
credit facility of SER. Global continues to have a substantially
identical $500 million three-year revolving credit facility that
expires in 2006. Borrowings under each facility would be guaranteed by
Sempra Energy and bear interest at rates varying with market rates and
Sempra Energy's credit rating. Each facility requires Sempra Energy to
maintain, at the end of each quarter, a ratio of total indebtedness to
total capitalization (as identically defined in each facility) of no
more than 65 percent.

FACTORS INFLUENCING FUTURE PERFORMANCE

Base results of the company in the near future will depend primarily on
the results of the California Utilities, while earnings growth and
variability will result primarily from activities at SET, SER, SELNG
and SEI. Notes 6 and 7 of the notes to Consolidated Financial
Statements herein and Notes 13 through 15 of the Annual Report describe
events in the deregulation of California's electric and natural gas
industries and various FERC, SET and income tax issues.

California Utilities

Note 6 of the notes to Consolidated Financial Statements contains
discussions of electric and natural gas restructuring and rates, the
pending cost of service filings and the CPUC's investigation of
compliance with affiliate rules.

Sempra Energy Global Enterprises

Electric-Generation Assets

As discussed in more detail in "Cash Flows From Investing Activities,"
the company is involved in the expansion of its electric-generation
capabilities, including the AEP-related acquisition noted above, which
will significantly impact the company's future performance.

Investments

As discussed in "Cash Flows From Investing Activities," the company's
investments will significantly impact the company's future performance.

SELNG is in the process of developing Energia Costa Azul, an LNG
receiving terminal in Baja California, Mexico; the Cameron LNG
receiving terminal in Hackberry, Louisiana; and the Port Arthur LNG
receiving terminal near Port Arthur, Texas. The viability and future
profitability of this business unit is dependent upon numerous factors,
including the relative prices of natural gas in North America and from
LNG suppliers located elsewhere, negotiating sale and supply contracts
at adequate margins, and completing cost-effective construction of the
required facilities.

48

Beginning in 2003, SET started expanding its natural gas storage
capacity by developing Bluewater Gas Storage, LLC. In April 2004, SET
announced the acquisition of land and associated rights for the
development of a salt-cavern natural gas storage facility in Evangeline
Parish, Louisiana. In July 2004, the company announced that it had
acquired the rights to develop a salt-cavern gas storage facility
located in Calcasieu Parish, Louisiana. Additional information
regarding these activities is provided above in "Cash Flows From
Investing Activities."

The Argentine economic decline and government responses (including
Argentina's unilateral, retroactive abrogation of utility agreements
early in 2002) are continuing to adversely affect the company's
investment in two Argentine utilities. Information regarding this
situation is provided in Note 7 of the notes to Consolidated Financial
Statements.

NEW ACCOUNTING STANDARDS

Relevant pronouncements that have recently become effective and have
had a significant effect on the company are SFAS Nos. 143, 149 and 150,
FIN 45 and 46, and EITF 98-10, as discussed in Note 2 of the notes to
Consolidated Financial Statements. Pronouncements that have or are
likely to have a material effect on future earnings are described
below.

EITF Issue 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities": In accordance with the EITF's
rescission of Issue 98-10 by the release of Issue 02-3, the company no
longer marks to market energy-related contracts unless the contracts
meet the requirements stated under SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities," and SFAS 149, "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities." A
substantial majority of the company's contracts do meet these
requirements. Upon adoption of this consensus on January 1, 2003, the
company recorded the initial effect of rescinding Issue 98-10 as a
cumulative effect of a change in accounting principle, which reduced
after-tax earnings by $29 million.

SFAS 143, "Accounting for Asset Retirement Obligations": Beginning in
2003, SFAS 143 requires entities to record liabilities for future costs
expected to be incurred when assets are retired from service, if the
retirement process is legally required. It also requires most energy
utilities, including the California Utilities, to reclassify amounts
recovered in rates for future removal costs not covered by a legal
obligation from accumulated depreciation to a regulatory liability.
Further discussion is provided in Note 2 of the notes to Consolidated
Financial Statements.

SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": SFAS 149 amends and clarifies accounting for
derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities under SFAS 133.
Under SFAS 149, natural gas forward contracts that are subject to
unplanned netting do not qualify for the normal purchases and normal
sales exception, whereby derivatives are not required to be marked to

49

market when the contract is usually settled by the physical delivery of
natural gas. The company has determined that all natural gas contracts
are subject to unplanned netting and as such, these contracts will be
marked to market. In addition, effective January 1, 2004, power
contracts that are subject to unplanned netting and that do not meet
the normal purchases and normal sales exception under SFAS 149 will be
further marked to market. Implementation of SFAS 149 on July 1, 2003
did not have a material impact on reported net income.

FIN 46, "Consolidation of Variable Interest Entities an interpretation
of ARB No. 51": In January 2003, the FASB issued FIN 46 to strengthen
existing accounting guidance that addresses when a company should
consolidate a VIE in its financial statements.

Adoption of FIN 46 on December 31, 2003 resulted in the consolidation
of two VIEs for which Sempra Energy is the primary beneficiary. One of
the VIEs (Mesquite Trust) was the owner of the Mesquite Power plant for
which the company had a synthetic lease agreement. (The company bought
out the lease in January 2004.) The other VIE relates to the investment
in AEG. Sempra Energy consolidated these entities in its financial
statements at December 31, 2003. During the first quarter of 2004
Sempra Energy's Board of Directors approved management's plan to
dispose of AEG. Note 4 of the notes to Consolidated Financial
Statements provides further discussion on this matter and the disposal
of AEG's discontinued operations, which occurred in April 2004.

In accordance with FIN 46, the company has deconsolidated a wholly
owned subsidiary trust from its financial statements at December 31,
2003.

Further discussion regarding FIN 46 is provided in Note 2 of the notes
to Consolidated Financial Statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There have been no significant changes in the risk issues affecting the
company subsequent to those discussed in the Annual Report.

The VaR for SET at June 30, 2004, and the average VaR for the six
months ended June 30, 2004, at the 95-percent and 99-percent confidence
intervals (one-day holding period) were as follows (in millions of
dollars):
95% 99%
- ------------------------------------------------------
At June 30, 2004 $ 5.6 $ 7.9
Average for the six months
ended June 30, 2004 $ 6.1 $ 8.5
- ------------------------------------------------------

As of June 30, 2004, the total VaR of the California Utilities' and
SES' positions was not material.

50

ITEM 4. CONTROLS AND PROCEDURES

The company has designed and maintains disclosure controls and
procedures to ensure that information required to be disclosed in the
company's reports under the Securities Exchange Act of 1934 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 company's
management, including its Chief Executive Officer and Chief Financial
Officer, as appropriate, to allow timely decisions regarding required
disclosure. In designing and evaluating these controls and procedures,
management recognizes that any system of controls and procedures, no
matter how well designed and operated, can provide only reasonable
assurance of achieving the desired objectives and necessarily applies
judgment in evaluating the cost-benefit relationship of other possible
controls and procedures. In addition, the company has investments in
unconsolidated entities that it does not control or manage and,
consequently, its disclosure controls and procedures with respect to
these entities are necessarily substantially more limited than those it
maintains with respect to its consolidated subsidiaries.

Under the supervision and with the participation of management,
including the Chief Executive Officer and the Chief Financial Officer,
the company evaluated the effectiveness of the design and operation of
the company's disclosure controls and procedures as of June 30, 2004,
the end of the period covered by this report. Based on that evaluation,
the company's Chief Executive Officer and Chief Financial Officer
concluded that the company's disclosure controls and procedures were
effective at the reasonable assurance level.

There has been no change in the company's internal controls over
financial reporting during the company's most recent fiscal quarter
that has materially affected, or is reasonably likely to materially
affect, the company's internal controls over financial reporting.

ITEM 5. OTHER INFORMATION

On June 9, 2004, Donald E. Felsinger was named Sempra Energy's
president and chief operating officer and was also elected to its board
of directors. The company's succession plan contemplates that Mr.
Felsinger will become chief executive officer upon Stephen L. Baum's
retirement at the end of January 2006. As part of the management
succession plan, executive vice president and chief financial officer,
Neal Schmale, was also elected to the board of directors. The
succession plan contemplates that Mr. Schmale will become chief
operating officer when Mr. Felsinger becomes chief executive officer.

Also on June 9, 2004, Denise K. Fletcher became a member of the board
of directors. Ms. Fletcher is a director of Orbitz and Unisys
Corporation. She has served as a senior vice president and chief
financial officer of MasterCard International and a senior vice
president and chief financial officer of Bowne & Company.

51

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

SDG&E and the County of San Diego are in the process of negotiating the
remaining terms of a settlement relating to alleged environmental law
violations by SDG&E and its contractors in connection with the
abatement of asbestos-containing materials during the demolition of a
natural gas storage facility that was completed in 2001. The expected
settlement would involve payments by SDG&E of less than $750,000.

Except as described above and in Notes 6 and 7 of the notes to
Consolidated Financial Statements, neither the company nor its
subsidiaries are party to, nor is their property the subject of, any
material pending legal proceedings other than routine litigation
incidental to their businesses.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Sempra Energy's board of directors is divided into three classes whose
terms are staggered so that the term of one class expires at each Annual
Meeting of Shareholders. At the annual meeting on May 4, 2004, the
shareholders of Sempra Energy elected three directors for a three-year
term expiring in 2007. The name of each nominee and the number of shares
voted for and withheld from the election of each director were as
follows:

Nominees Votes For Votes Withheld
Stephen L. Baum 185,453,797 12,446,837
Wilford D. Godbold, Jr. 184,841,895 13,058,739
Richard G. Newman 187,100,591 10,800,043

The results of the voting on the other proposals considered at the
annual meeting were as follows:

(a) management proposal for the reapproval of long-term incentive plan
performance goals.

In favor 166,145,134
Opposed 27,931,314

(b) management proposal for the ratification of independent auditors.

In favor 187,193,487
Opposed 7,149,577

(c) shareholder proposal recommending that each director be elected
annually.

In favor 102,810,350
Opposed 58,380,870

(d) shareholder proposal regarding shareholder rights plan.

In favor 106,527,100
Opposed 54,176,636

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(e) shareholder proposal limiting auditor services.

In favor 27,809,978
Opposed 132,792,660

(f) shareholder proposal regarding independent chairman of the board.

In favor 68,124,252
Opposed 92,860,896

The two approved shareholder proposals constitute recommendations to
the board of directors and will be considered by the board prior to the
next annual meeting of shareholders.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

Exhibit 12 - Computation of ratios

12.1 Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends.

Exhibit 31 -- Section 302 Certifications

31.1 Statement of Registrant's Chief Executive Officer pursuant
to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

31.2 Statement of Registrant's Chief Financial Officer pursuant
to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.

Exhibit 32 -- Section 906 Certifications

32.1 Statement of Registrant's Chief Executive Officer pursuant
to 18 U.S.C. Sec. 1350.

32.2 Statement of Registrant's Chief Financial Officer pursuant
to 18 U.S.C. Sec. 1350.

(b) Reports on Form 8-K

The following reports on Form 8-K were filed after March 31, 2004:

Current Report on Form 8-K filed April 29, 2004, filing as an exhibit
Sempra Energy's press release of April 29, 2004, giving the financial
results for the quarter ended March 31, 2004.

Current Report on Form 8-K filed August 5, 2004, filing as an exhibit
Sempra Energy's press release of August 5, 2004, giving the financial
results for the quarter ended June 30, 2004.

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SIGNATURE

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: August 5, 2004 By: /s/ F. H. Ault
----------------------------
F. H. Ault
Sr. Vice President and Controller