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, 2003
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Commission file number 1-14201
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Sempra Energy
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(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, 2003: 208,714,412
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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," "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 Department
of Water Resources, 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.

ITEM 1. FINANCIAL STATEMENTS.

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

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

SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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, 2002 (Annual Report) and the Quarterly Report on Form 10-Q
for the three months ended March 31, 2003.

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.

As described in the notes to Consolidated Financial Statements in the
Annual Report, the California Utilities account for the economic
effects of regulation on utility operations (excluding generation
operations) in accordance with Statement of Financial Accounting
Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types
of Regulation".

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) 2003 2002 2003 2002
- -----------------------------------------------------------------
Net income $ 116 $ 147 $ 204 $ 293

Foreign currency adjustments 30 (34) 44 (128)

Minimum pension liability
adjustments -- (14) (6) (14)

Financial instruments -- 1 -- --
---------------------------------
Comprehensive income $ 146 $ 100 $ 242 $ 151
- -----------------------------------------------------------------

2. NEW ACCOUNTING STANDARDS

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, the company no
longer recognizes energy-related contracts under mark-to-market
accounting unless the contracts meet the requirements stated under SFAS
133 "Accounting for Derivative Instruments and Hedging Activities,"
which is the case for a substantial majority of the company's
contracts. 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.
Only $18 million of the $29 million had been included in net income
through December 31, 2002. However, the $18 million was net of the
after-tax effect of income-based expenses, which are not considered in
calculating the cumulative effect of the accounting change. As the
underlying transactions are completed subsequent to December 31, 2002,
and the gains or losses are recorded, the entire $29 million, plus or
minus intervening changes in market value, will be included in the
calculation of net income. On a net basis, no such realization occurred
during the six months ended June 30, 2003. In addition, the ongoing
effect of rescinding EITF 98-10 negatively impacted after-tax earnings
for the three and six months ended June 30, 2003 by an additional $7
million and $16 million, respectively. Neither the cumulative nor the
ongoing effect impacts the company's cash flow or liquidity.

Emerging Issues Task Force 02-3 "Issues Involved in Accounting for
Derivative Contracts Held for Trading Purposes and Contracts Involved
in Energy Trading and Risk Management Activities": EITF 02-3 requires
gains and losses on trading contracts to be recorded on a net basis in
the income statement, effective for financial statements covering
periods ending after July 15, 2002. This required that SES change its
method of recording trading activities from gross to net, which had no
impact on previously recorded gross margin, net income or cash provided
by operating activities. SET required no change as it was already
recording revenues from trading activities net.

Statement of Financial Accounting Standards (SFAS) 142, "Goodwill and
Other Intangible Assets": In accordance with SFAS 142, recorded
goodwill is tested for impairment. As a result, during the first
quarter of 2002, SEI recorded a pre-tax charge of $6 million related to
the impairment of goodwill associated with its two domestic
subsidiaries. Impairment losses are reflected in other operating
expenses in the Statements of Consolidated Income.

During the first quarter of 2003 SEI purchased the remaining interests
in its Mexican subsidiaries, which resulted in the recording of an
addition to goodwill of $10 million.

The change in the carrying amount of goodwill (included in noncurrent
sundry assets on the Consolidated Balance Sheets) for the six months
ended June 30, 2003 are as follows:

(Dollars in millions) SET Other Total
- ------------------------------------------------------------------
Balance as of January 1, 2003 $ 141 $ 41 $ 182
Goodwill acquired during 2003 -- 10 10
---------------------------
Balance as of June 30, 2003 $ 141 $ 51 $ 192
---------------------------

SFAS 143, "Accounting for Asset Retirement Obligations": The adoption
of SFAS 143 on January 1, 2003 resulted in the recording of an addition
of $71 million to utility plant, representing the company's share of
the San Onofre Nuclear Generating Station (SONGS) estimated future
decommissioning costs (as discounted to the present value at the dates
the units began operation), and accumulated depreciation of $41 million
related to the increase to utility plant, for a net increase of $30
million. In addition, the company recorded a corresponding retirement
obligation liability of $309 million (which includes accretion of that
discounted value to December 31, 2002) and a regulatory liability of
$215 million to reflect that SDG&E has collected the funds from its
customers more quickly than SFAS 143 would accrete the retirement
liability and depreciate the asset. These liabilities, less the $494
million recorded as accumulated depreciation prior to January 1, 2003
(which represents amounts collected for future decommissioning costs),
comprise the offsetting $30 million.

On January 1, 2003, the company recorded additional asset retirement
obligations of $20 million associated with the future retirement of a
former power plant and three storage facilities.

In accordance with SFAS 143, Sempra Energy identified several other
assets for which retirement obligations exist, but whose lives are
indeterminate. A liability for these asset retirement obligations will
be recorded if and when a life is determinable.

The change in the asset retirement obligations for the six months ended
June 30, 2003 is as follows (dollars in millions):

Balance as of January 1, 2003 $ --
Adoption of SFAS 143 329
Accretion expense 11
Payments made (7)
------
Balance as of June 30, 2003 $ 333*
======

*A portion of the obligation is included in other current liabilities
on the Consolidated Balance Sheets.

Had SFAS 143 been in effect, the asset retirement obligation liability
would have been $315 million, $338 million, $363 million and $329
million as of January 1, 2000 and December 31, 2000, 2001 and 2002,
respectively.

Except for the items noted above, the company has determined that there
is no other material retirement obligation associated with tangible
long-lived assets.

Implementation of SFAS 143 has had no effect on results of operations
and is not expected to have a significant one in the future.

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 Opinion 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 123:

Three months ended
June 30,
------------------------
2003 2002
------------------------
Net income as reported $ 116 $ 147
Stock-based employee compensation expense
reported in net income, net of tax 7 (2)
Total stock-based employee compensation
under fair value method for all awards,
net of tax (9) (1)
------------------------
Pro forma net income $ 114 $ 144
========================

Earnings per share:
Basic--as reported $ 0.56 $ 0.72
========================
Basic--pro forma $ 0.55 $ 0.70
========================
Diluted--as reported $ 0.55 $ 0.71
========================
Diluted--pro forma $ 0.54 $ 0.70
========================

Six months ended
June 30,
------------------------
2003 2002
------------------------
Net income as reported $ 204 $ 293
Stock-based employee compensation expense
reported in net income, net of tax 14 1
Total stock-based employee compensation
under fair value method for all awards,
net of tax (18) (6)
------------------------
Pro forma net income $ 200 $ 288
========================

Earnings per share:
Basic--as reported $ 0.99 $ 1.43
========================
Basic--pro forma $ 0.97 $ 1.40
========================
Diluted--as reported $ 0.98 $ 1.42
========================
Diluted--pro forma $ 0.96 $ 1.39
========================

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.
Sempra Energy is currently assessing the impact SFAS 149 will have on
its consolidated results of operations and financial position. It will
have no effect on cash flows.

SFAS 150 "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity": This statement
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and
equity. SFAS 150 requires that certain mandatorily redeemable
financial instruments currently classified in the mezzanine section of
the balance sheet be reclassified as liabilities. The company will
adopt SFAS 150 in the third quarter of 2003 by changing its
presentation of $200 million and $24 million of mandatorily redeemable
trust preferred securities and preferred stock of subsidiaries,
respectively.

FASB Interpretation No. 45 (FIN 45), "Guarantor's Accounting and
Disclosure Requirements for Guarantees": FIN 45 elaborates on the
disclosures to be made in interim and annual financial statements of a
guarantor about its obligations under certain guarantees that it has
issued. It also clarifies that at the inception of a guarantee a
guarantor is required to recognize a liability for the fair value of
the obligation undertaken in issuing a guarantee. The only significant
guarantee for which disclosure is required is that of the synthetic
lease for the Mesquite Power Plant, which is also affected by FASB
Interpretation No. 46, as described below.

FASB Interpretation No. 46 (FIN 46), "Consolidation of Variable
Interest Entities": In January 2003, the FASB issued FIN 46, which
requires the primary beneficiary of a variable interest entity's
activities to consolidate the entity. The primary beneficiary is the
party that absorbs a majority of the expected losses and/or receives a
majority of the expected residual returns of the entity's activities.
The consolidation requirements of the interpretation apply immediately
to entities created after January 31, 2003. For pre-existing entities,
they apply beginning July 1, 2003. Sempra Energy has identified two
variable interest entities for which it is the primary beneficiary. One
of the variable interest entities relates to an investment in an
unconsolidated subsidiary, Atlantic Electric & Gas Limited, that
markets power and natural gas commodities to commercial and residential
customers in the United Kingdom. The other entity is the lessor of the
Mesquite Power Plant (Mesquite Power) described below. Accordingly,
effective in the third quarter of 2003, Sempra Energy will consolidate
these entities, which is estimated to increase total assets and total
liabilities by $650 million. The company does not expect a significant
impact to income before the cumulative effect of the change in
accounting principle and estimates that the cumulative effect of the
change will be a charge of $30 million.

Mesquite Power, located near Phoenix, Arizona, is a $662 million,
1,250-megawatt (mW) project that will provide electricity to wholesale
energy markets in the Southwest. Construction began in September 2001
and the first phase of commercial operations (50-percent of the plant's
total capacity) began in June 2003. The second phase of commercial
operations (the remaining 50 percent) is expected to begin in November
2003. Expenditures as of June 30, 2003 are $612 million. A synthetic
lease agreement provides financing for all project assets owned by the
lessor. Financing under the synthetic lease in excess of $280 million
requires 103 percent collateralization through the purchase of U.S.
Treasury obligations in similar amounts. As of June 30, 2003, the
company held $315 million of U.S. Treasury obligations, which is
included in investments on the Consolidated Balance Sheets.

3. MATERIAL CONTINGENCIES

ELECTRIC INDUSTRY REGULATION

The restructuring of California's electric utility industry has
significantly affected the company's electric utility operations. The
background of this issue is described in the Annual Report. Subsequent
developments are described herein.

The power crisis of 2000-2001 has caused the California Public
Utilities Commission (CPUC) to adjust its plan for restructuring the
electricity industry. In addition, several California state agencies,
including the CPUC, the Consumer Power and Conservation Financing
Authority, and the California Energy Commission, recently adopted an
Energy Action Plan for California. The plan calls for a continuation of
regulated electricity rates and existing direct access contracts,
increased conservation, more renewable energy, and a stable regulatory
environment that encourages private investment in the state.

Subsequent to the electric capacity shortages of 2000-2001, SDG&E's
service territory has had and continues to have an adequate supply of
electricity. However, various projections of electricity demand in
SDG&E's service territory indicate that, without additional electrical
generation or reductions in electrical usage, beginning in 2005
electricity demand could begin to outstrip available resources. SDG&E's
strategy for meeting this demand is to: (1) reduce power demand through
conservation and efficiency; (2) increase the supply of electricity
from renewable sources, including wind and solar; (3) establish new
transmission lines by 2008 to import more power; and (4) provide new
electric generation by 2005 to meet the expected shortfall. SDG&E has
issued a request for proposals (RFP) to meet the electric capacity
shortfall, estimated at 69 megawatts in 2005 and increasing annually by
100 megawatts. SDG&E is ahead of the interim schedule required by
California legislation in meeting the CPUC's requirement of obtaining
20 percent of its electricity from renewable sources by 2017.

There continues to be legislative and regulatory interest in returning
the California's investor-owned utilities (IOUs) to an ownership role
for generation. At present, there is no firm guidance or set of terms
and conditions under which this might take place that would provide
adequate customer and shareholder protections, and SDG&E continues to
state that these items must be in place before it would consider an
ownership position. In anticipation of possible direction on these
matters, SDG&E has required bidders to include both power purchase and
ownership options in their response to the RFP noted above for
additional local generation beginning in 2005.

Several legislative proposals relating to utility regulation have
failed to be enacted by the California Legislature. California Senate
Bill (SB) 429 would have subjected the company and other California
energy-utility holding companies to continuing authority of the CPUC to
enforce any condition placed upon their authorizations to acquire their
California utility subsidiaries, including obligations to give first
priority to the capital requirements of the utilities as determined by
the CPUC to be necessary to meet the utilities' obligations to serve.
It would also require that the CPUC order the holding companies to
infuse into the utility subsidiaries sufficient capital, of any type
deemed necessary by the CPUC, to enable the utilities to fulfill their
service obligations. SB 888 would repeal the provisions of Assembly
Bill (AB) 1890, which enabled electric industry restructuring in
September 1996.

California Governor Davis recently announced that he is seeking a $1-
billion electric rate reduction. SDG&E's portion of this is 13.51
percent or $135 million. This rate reduction will have no effect on
SDG&E's net income and net cash flows because customer savings are
coming from lower charges by the California Department of Water
Resources (DWR), and SDG&E is merely transmitting the electricity from
the DWR to the customers, acting as a conduit for the parties. In
accordance therewith, on July 1, 2003 the DWR submitted to the CPUC a
supplemental determination of its 2003 revenue requirement. The DWR's
supplemental determination contains a $1-billion reduction in its
revenue requirement for 2003. In order to make the corresponding rate
reduction available to ratepayers as soon as possible, and consistent
with the very limited scope of this phase of this proceeding, the
procedural schedule is being expedited. A draft decision is expected by
the end of August 2003, with a final decision by September 2003.

The CPUC has undertaken a proceeding and issued numerous decisions
establishing the framework, rules and processes that would govern
SDG&E's renewed responsibility of procuring electricity for its
customers. These include decisions (1) allocating to the customers of
California's IOUs the power from the long-term contracts entered into
by the DWR, with the DWR retaining the legal and financial
responsibility for the contracts; (2) adopting an Operating Agreement
between SDG&E and the DWR to govern the terms and conditions for
SDG&E's administration of DWR contracts; (3) adopting annual
procurement plans that include securing supplies to satisfy SDG&E's
additional power requirements; (4) consideration of a 20-year resource
plan to assess SDG&E's resource needs, emphasizing the next five years;
and (5) developing the criteria by which the acceptability and recovery
of procurement transactions will be determined, including possible
development of an incentive mechanism for procurement activities.

The DWR's Operating Agreement with SDG&E, approved by the CPUC, governs
SDG&E's relationship with the DWR now that SDG&E has assumed
administration of the allocated DWR contracts. The agreement 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 its customers. Legal and financial risks
associated with these activities will continue to reside with the DWR.
However, in certain limited circumstances involving transactions in
which SDG&E, as DWR's limited agent, is selling DWR surplus energy
pursuant to the terms of the Operating Agreement, SDG&E may be
obligated to provide lines of credit in connection with the allocated
contracts. The risk associated with these lines of credit is considered
to be minimal. On April 17, 2003, SDG&E filed with the CPUC its natural
gas procurement plan related to certain DWR contracts. On July 10,
2003, the CPUC approved SDG&E's natural gas supply plan.

On July 11, 2003, the CPUC adopted a proposed decision continuing the
level of the Direct Access (DA) cost responsibility surcharge (CRS) cap
effective July 1, 2003 at 2.7 cents per kWh, subject to possible
revision in the next DA CRS cap review proceeding. In each periodic DA
CRS cap review proceeding, the cap is subject to adjustment to the
extent necessary to maintain the goal of refunding to utility customers
the full amounts to which they are entitled by the end of the DWR
contract term in 2011.

NATURAL GAS INDUSTRY RESTRUCTURING

As discussed in Note 14 of the notes to Consolidated Financial
Statements in the Annual Report, in December 2001 the CPUC issued a
decision related to natural gas industry restructuring, with
implementation anticipated during 2002. During 2002 the California
Utilities filed a proposed implementation schedule and revised tariffs
and rules required for implementation. However, on February 27, 2003,
the CPUC issued a resolution rejecting without prejudice those proposed
tariffs and rules. The resolution ordered SoCalGas to file a new
application, which would address detailed proposals for implementation
of the December 2001 decision, but also would allow reconsideration of
the December 2001 decision. SoCalGas filed such an application on June
30, 2003, and proposed some modifications to the provisions of the
December 2001 decision to respond to concerns that it could lead to
higher natural gas costs for consumers. These modifications include,
among other things, a proposal not to unbundle natural gas
transmission, a higher market price cap on receipt-point capacity
transactions in the secondary market, deferral of retail unbundling
provisions, and a proposal to litigate transmission and storage revenue
requirements in the Cost of Service case (see below). Modifications
would also remove SoCalGas' exposure to risk or reward for the sale of
receipt-point capacity. The filing proposes implementation of these
provisions on April 1, 2004 and continuing through August 31, 2006. If
the December 2001 decision is implemented, it is not expected to
adversely affect the California Utilities' earnings. A CPUC decision is
expected during 2004.

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 (CA-AZ) border during the period of
March 2000 through May 2001. If the investigation determines that the
conduct of any respondent contributed to the natural gas price spikes
at the CA-AZ border during this period, the CPUC may modify the
respondent's applicable natural gas procurement incentive mechanism,
reduce the amount of any shareholder award for the period involved,
and/or order the respondent to issue a refund to ratepayers to offset
the higher rates paid. The California Utilities, included among the
respondents to the investigation, are fully cooperating in the
investigation and believe that the CPUC will ultimately determine that
they were not responsible for the high border prices during this
period. On August 1, 2003, the Administrative Law Judge (ALJ) issued a
revised schedule with hearings scheduled to begin in March 2004 and
with a Commission decision by late 2004.

CPUC INVESTIGATION OF COMPLIANCE WITH AFFILIATE RULES

On February 27, 2003, the CPUC opened an investigation of the business
activities of SDG&E, SoCalGas and Sempra Energy to ensure that they
have complied with relevant statutes and CPUC decisions in the
management, oversight and operations of their companies. The Assigned
Commissioner and ALJ issued a ruling which suspends the procedural
schedule until the CPUC completes an independent audit to evaluate
energy-related business activities undertaken by Sempra Energy within
the service territories of SDG&E and SoCalGas, relative to holding
company systems and affiliate activities. The audit is to consider
whether these activities pose any problems for ratepayers and whether
they are consistent with the CPUC's decision, rules or orders and/or
affiliate statutes. The objective of the audit is to analyze the
adequacy of the Affiliate Rules. In accordance with existing CPUC
requirements, the California Utilities' transactions with other Sempra
Energy affiliates have been audited by an independent auditing firm
each year, with results reported to the CPUC, and there have been no
material adverse findings in those audits.

COST OF SERVICE FILING

On May 22, 2003, the assigned CPUC Commissioner modified his previously
adopted procedural schedule on the California Utilities' Cost of
Service applications to expedite a decision by approximately one month,
permitting a decision by as early as March 2004. The assigned
Commissioner also provided for additional comments to be filed on the
California Utilities' request for interim relief for the period from
January 1, 2004 to the date of the Cost of Service decision and stated
that a decision on the request would be prepared for consideration of
the full Commission. On June 3, 2003, various parties filed reply
comments supporting or opposing the motion for January 1, 2004 interim
relief. The CPUC's Office of Ratepayer Advocates' (ORA) report on the
California Utilities' filing is due on August 8, 2003.

An October 10, 2001 decision denied the California Utilities' request
to continue equal sharing between ratepayers and shareholders of the
estimated savings for the 1998 Enova-PE business combination that
created Sempra Energy and, instead, ordered that all of the estimated
2003 merger savings go to ratepayers. This decision will adversely
affect 2003 net income by $24 million at SoCalGas and $11 million at
SDG&E.

MARKET INDEXED CAPITAL ADJUSTMENT MECHANISM (MICAM)

Under MICAM, automatic adjustments are made to SDG&E's cost of capital
based on when the April-September average of single-A utility bond
rates in any given calendar year varies more than 100 basis points from
a predetermined benchmark. When this occurs, SDG&E's return on common
equity (ROE) is adjusted by one-half of the change. SDG&E must file its
annual MICAM advice letter with the CPUC on October 15, reporting how
the year's April-September average of the utility bond yield compares
to the benchmark. Any resulting change in SDG&E's ROE would go into
effect January 1 of the following year. Due to a large general decline
in interest rates, it is likely that the existing MICAM mechanism would
trigger during 2003. However, if the CPUC approves an all-party
settlement previously filed, the likelihood of a trigger this year
would be less since the benchmark rate under the settlement was changed
to the double-A utility bond rate during a different time period which
produced a lower benchmark rate.

The current MICAM benchmark, based on the April-September 1996 single-A
utility bond yield, stands at 7.97%. The MICAM benchmark that would
take effect under the settlement agreement, 7.24%, is based on the
April-September 2002 double-A utility bond yield.

Single-A utility interest rates under the existing mechanism averaged
6.40% from April through June, and an ROE adjustment would occur if the
July through September rate averages 7.53% or lower. Double-A utility
interest rates under the settlement agreement averaged 6.26% from April
through June, and an ROE reduction would occur if the July through
September rate averages 6.20% or lower.

In both versions of MICAM, every percentage point of variance between
the April-September average and the benchmark in excess of the
threshold reduces SDG&E's authorized annual net income by $5 million.

PERFORMANCE-BASED REGULATION (PBR)

On July 15, 2003, the CPUC issued a Draft Resolution (DR) approving
SDG&E's 2001 and 2002 Distribution PBR Performance Reports. If the DR
is approved by the CPUC, SDG&E would be awarded $12.2 million for
exceeding PBR benchmarks on all six of its performance indicators in
2001. SDG&E would also be awarded $6.0 million for exceeding the PBR
benchmarks on five of its six performance indicators in 2002. The total
maximum reward (or penalty) SDG&E could earn in a given year under the
Distribution PBR mechanism is $14.5 million. A final CPUC decision is
expected during the third quarter of 2003.

On March 19, 2003, the ORA issued its Monitoring and Evaluation Report
on SDG&E's natural gas procurement activities in Year 9 (August 1, 2001
through July 31, 2002). The ORA analyzed and confirmed the PBR results
put forth by SDG&E, resulting in a Year 9 shared loss of $1.9 million
and a shareholder penalty of $1.4 million, both of which were recorded
in 2002. The ORA recommended the extension of the PBR mechanism, as
modified in Years 8 and 9, to Year 10 and beyond. The ORA has stated
that the CPUC's adoption of the natural gas procurement PBR mechanism
is beneficial both to ratepayers and to shareholders of SDG&E.

On July 10, 2003, the CPUC issued a decision relative to SDG&E's Year
11 Gas PBR application, which would extend the PBR mechanism with some
modification. The decision approved the Joint Parties' Motion for an
Order Adopting Settlement Agreement filed by SDG&E and the ORA, which
will apply to Year 10 and beyond. The effect of the modifications is to
reduce slightly the potential size of future PBR rewards or penalties.

SDG&E's request for a reward of $6.7 million for the PBR natural gas
procurement period ended July 31, 2001 (Year 8) was approved by the
CPUC on January 30, 2003. Since part of the reward calculation is based
on CA-AZ natural gas border price indices, the decision reserved the
right to revise the reward in the future, depending on the outcome of
the CPUC's border price investigation (see above) and the FERC's
investigation into alleged energy price manipulation (see below).

GAS COST INCENTIVE MECHANISM (GCIM)

SoCalGas' GCIM allows SoCalGas to receive a share of the savings it
achieves by buying natural gas for customers below monthly benchmarks.
The mechanism permits full recovery of all costs within a tolerance
band above the benchmark price and refunds savings within a tolerance
band below the benchmark price. The costs outside the tolerance band
are shared between customers and shareholders.

On June 25, 2003, the assigned CPUC commissioner issued two separate,
but essentially identical, Draft Decisions in SoCalGas' GCIM Year 7 and
Year 8 proceedings. A final CPUC decision is expected during the third
quarter of 2003. If the final decision agrees with the assigned
commissioner's Draft Decisions approving the shareholder rewards of
$30.8 million for Year 7 and $17.4 million for Year 8 (subject to
refund or adjustment as determined by the Commission in the Border
Price Investigation described above), the rewards would be included in
income in the third quarter of 2003.

On June 16, 2003, SoCalGas filed an application with the CPUC
requesting a $6.3 million shareholder reward for GCIM Year 9 (April 1,
2002 through March 31, 2003). The company's natural gas purchasing
activities resulted in a net savings of $33 million to ratepayers
during Year 9, which led to the requested shareholder reward.

Performance incentives rewards are not included in the company's
earnings until CPUC approval is received.

TRANSMISSION RATE INCREASE

On May 2, 2003, the FERC accepted SDG&E's request for modification of
its Transmission Owner Tariff to adopt a rate increase. The new
transmission rates are effective October 1, 2003, and will increase the
charges for retail transmission service by $32.3 million (27 percent).
SDG&E has proposed formula-based rates which would allow the company
over a 4 to 5 year period to recover all of its recorded costs as well
as an adopted ROE. Thus, SDG&E would earn no more or no less than the
FERC-adopted ROE for the predetermined period. These new rates are
subject to refund based on the FERC's final order. The FERC staff and
intervenor testimonies are due on August 29, 2003. Litigation of the
case would result in a decision by the end of 2004.

In August 2002 the FERC issued Opinion No. 458, which effectively
disallowed SDG&E's recovery of the differentials between certain costs
paid to SDG&E under existing transmission contracts (the "Participation
Agreements") and charges assessed to SDG&E under the ISO FERC tariff.
These charges are for transmission line losses and grid management
charges attributable to energy schedules on portions of the Southwest
Powerlink. As a result, SDG&E is incurring unreimbursed cost
differentials on an ongoing basis at a rate ranging between $4 million
and $8 million per year. SDG&E has petitioned the United States Court
of Appeals for review of these FERC orders. In addition, SDG&E is
challenging the propriety of the ISO charges as applied to the portions
of the Southwest Powerlink jointly owned with Arizona Public Service
Co. and the Imperial Irrigation District in proceedings before the
FERC, and in an arbitration under the ISO tariff, the result of which
may be appealed to FERC. To the extent SDG&E prevails in these matters,
the FERC may require the ISO to refund to SDG&E all or part of the
subject charges. SDG&E has also commenced a private arbitration to
reform the Participation Agreements to remove prospectively SDG&E's
obligation to provide services giving rise to unreimbursed ISO tariff
charges.

FERC ACTIONS

The FERC is investigating prices charged to buyers in the California
Power Exchange (PX) and Independent System Operator (ISO) markets by
various electric suppliers. It 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).

In December 2002, a FERC ALJ issued preliminary findings indicating
that California owes power suppliers $1.2 billion (the $3.0 billion
that California still owes energy companies less $1.8 billion energy
companies charged California customers in excess of the FERC cap). On
March 26, 2003, the FERC largely adopted the ALJ's findings, but
expanded the basis for refunds by adopting a staff recommendation from
a separate investigation to change the natural gas proxy component of
the mitigated market clearing price that is used to calculate refunds.
The March 26 order estimates that the replacement formula for
estimating natural gas prices will increase the refund totals to more
than $3.0 billion. The precise number will not be available until the
ISO and PX recalculate the number through their settlement models based
on the final FERC instructions. California is seeking $8.9 billion in
refunds and has appealed the FERC's preliminary findings and requested
rehearing of the March 26 order. SET and other power suppliers have
joined in appeal of the FERC's preliminary findings and requested
rehearing.

SET had established reserves of $29 million for its likely share of the
original $1.8 billion. SET is unable to determine its share of the
additional refund amount. Accordingly, it has not recorded any
additional reserves but the company does not believe that any
additional amounts that SET may be required to pay would be material to
the company's financial position or liquidity.

In addition to the refund proceeding described above, the FERC is also
investigating whether there was manipulation of short-term energy
prices in the West that would constitute violations of applicable
tariffs and warrant disgorgement of associated profits. In this
proceeding, the FERC has authority to look at time periods outside of
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 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, the 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 tariff. 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 through
partnerships, alliances or other arrangements did not constitute gaming
and/or anomalous market behavior in violation of the tariffs. Remedies
for confirmed violations could include disgorgement of profits and
revocation of market-based rate authority. The FERC has encouraged the
entities to settle the issues and SET has already had such discussions.
SET estimates that the total amount of revenues attributable to the
transactions involved in these inquiries is less than $10 million. The
ISO has calculated SDG&E's gains attributable to these issues at less
than $200,000.

In addition, the FERC determined that it was appropriate to initiate an
investigation into possible economic withholding in the California ISO
and PX markets. For this purpose, the FERC used an initial screen of
$250 per mW for all bids between May 1, 2000 and October 2, 2000. Both
SDG&E and SET received data requests from the FERC staff. The FERC
staff will prepare a report to the Commission, which will be the basis
to decide whether additional proceedings are warranted. SET and SDG&E
believe that their bids and bidding procedures were consistent with ISO
and PX tariffs and protocols and applicable FERC price caps.

On June 25, 2003, the FERC issued orders upholding the company's long-
term energy contract with the DWR, as well as contracts between the DWR
and other power suppliers. The order affirmed a previous FERC
conclusion that those advocating termination or alteration of the
contract would have to satisfy a "heavy" burden of proof, and cited its
long-standing policy to recognize the sanctity of contracts. In the
order, the Commission noted that Commission and court precedent clearly
establish that allegations that contracts have become uneconomic by the
passage of time do not render them contrary to the public interest
under the Federal Power Act. The Commission pointed out that the
contracts were entered into voluntarily in a market-based environment.
The Commission found no evidence of unfairness, bad faith or duress in
the original contract negotiations. It said there was no credible
evidence that the contracts placed the complainants in financial
distress or that ratepayers will bear an excessive burden. A number of
parties have applied to the FERC for a rehearing of the decision and
may ultimately appeal the decision to the federal courts.

NUCLEAR INSURANCE

SDG&E and the other co-owners of SONGS have insurance to respond to any
nuclear liability claims related to SONGS. The insurance policy
provides $300 million in coverage, which is the maximum amount
available. In addition to this primary financial protection, the Price-
Anderson Act provides for up to $9.25 billion of secondary financial
protection if the liability loss exceeds the insurance limit. Should
any of the licensed/commercial reactors in the United States experience
a nuclear liability loss which exceeds the $300 million insurance
limit, all utilities owning nuclear reactors could be assessed under
the Price-Anderson Act to provide the secondary financial protection.
SDG&E and the other co-owners of SONGS could be assessed up to $176
million under the Price-Anderson Act. SDG&E's share would be $36
million unless default occurs by any other SONGS co-owner. In the event
the secondary financial protection limit is insufficient to cover the
liability loss, the Price-Anderson Act provides for Congress to enact
further revenue-raising measures to pay claims. These measures could
include an additional assessment on all licensed reactor operators.
SDG&E and the other co-owners of SONGS have $2.75 billion of nuclear
property, decontamination and debris removal insurance.

The coverage also provides the SONGS owners up to $490 million for
outage expenses incurred because of accidental property damage. This
coverage is limited to $3.5 million per week for the first 52 weeks,
and $2.8 million per week for up to 110 additional weeks. Coverage is
also provided for the cost of replacement power, which includes
indemnity payments for up to three years, after a waiting period of 12
weeks. The insurance is provided through a mutual insurance company
owned by utilities with nuclear facilities. Under the policy's risk
sharing arrangements, insured members are subject to retrospective
premium assessments if losses at any covered facility exceed the
insurance company's surplus and reinsurance funds. Should there be a
retrospective premium call, SDG&E could be assessed up to $7.4 million.

Both the nuclear liability and property insurance programs include
industry aggregate limits for terrorism-related SONGS losses, including
replacement power costs.

ARGENTINE INVESTMENTS

During the second quarter of 2003, SEI recorded a $9 million credit to
"accumulated other comprehensive income" to reflect the increase in the
value of the Argentine peso relative to the U.S. dollar, resulting in
total credits of $33 million for the six months ended June 30, 2003. As
of June 30, 2003, SEI has adjusted its investment in its two
unconsolidated Argentine subsidiaries downward by $190 million as a
result of the devaluation of the Argentine peso since early 2002. On
September 6, 2002, SEI initiated proceedings under the 1994 Bilateral
Investment Treaty between the United States and Argentina for recovery
of the diminution of the value of its investments resulting from
Argentine governmental actions. SEI made a request for arbitration to
the International Centre for Settlement of Investment Disputes (ICSID)
and all arbitrators have been selected. The company's claim is due in
August 2003 and a decision is expected in late 2004.

LITIGATION

Lawsuits filed in 2000 and currently consolidated in San Diego Superior
Court seek class-action certification and 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 announced that they had reached a
settlement in principle of the class actions, certain of the individual
actions, claims asserted by the California Attorney General and by
other western states, and certain complaint proceedings filed with FERC
by the CPUC and the California Energy Oversight Board. On June 26,
2003, the settlement was filed for approval with the relevant state
courts and the FERC. The settlement provides more than $1.5 billion in
consideration to be received by customers, with no effect on the income
of the utilities processing the refunds. Of these funds, the settlement
provides the following allocation for each SDG&E and SoCalGas customer
group: SDG&E Electric Customers -- $60 million, SDG&E Core Gas -- $29
million and SoCalGas Core Gas -- $36 million. Non-core natural gas
customers will go through a claims process in the courts, by which they
can establish their harm and receive a fair share of the consideration.

A similar lawsuit has been filed by the Attorney General of Arizona
alleging that El Paso and certain Sempra Energy subsidiaries unlawfully
sought to control the natural gas market in Arizona. In April 2003,
Sierra Pacific and its utility subsidiary Nevada Power jointly 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, and breach of contract and
wire fraud.

Various lawsuits, which seek class-action certification, allege that
Sempra Energy and certain company subsidiaries (SDG&E, SET and SER,
depending on the lawsuit) unlawfully manipulated the electric-energy
market. In January 2003, the applicable 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 has been appealed in
the Ninth Circuit Court of Appeal and a decision is expected by first
quarter of 2004. Similar suits filed in Washington and Oregon were
voluntarily dropped by the plaintiffs without court intervention in
June 2003. In addition, in May 2003, the Port of Seattle filed an
action alleging that a number of energy companies, including Sempra
Energy and SET, unlawfully manipulated the electric energy market and
committed wire fraud. That action is pending a motion to dismiss in
Washington Federal District Court 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.

In the fourth quarter of 2002, Sempra Energy and SoCalGas were named as
defendants in a lawsuit filed in Los Angeles Superior Court 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. On July
8, 2003, the Superior Court granted the defendants' demurrer 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.
However, the Court has provided plaintiffs with an opportunity to amend
their claims. In May 2003, a similar action was filed in San Diego
Superior Court against Sempra Energy and SET, and has been removed to
Federal District Court.

In May 2003, the San Diego Superior Court granted SER's motion for
summary judgment in its complaint for declaratory judgment regarding
its contract with the DWR (and the DWR's cross-complaint seeking to
void the 10-year energy-supply contract). In the judgment, the court
determined that "(a) Sempra is entitled to provide electrical energy
from any source, including Market Sources, (b) Sempra is not in breach
of the Agreement as framed by the pleadings in this matter, (c) DWR is
obligated to take delivery and pay for deliveries under the Agreement,
and (d) Sempra has no obligation to complete any specific Project."
Once the court enters the judgment, which it has not yet done, the DWR
has 60 days to file a notice of appeal. If the state appeals the
judgment, SER will respond according to the briefing schedule
established by the appellate court. 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 made all
payments that have been billed under the contract.

SER is a defendant in an action brought by Occidental Energy Ventures
Corporation (Occidental) with respect to the Elk Hills power project
being jointly developed by the two companies. Occidental alleges that
SER breached the joint development agreement by not providing that
Occidental would be a party to the contract with the DWR or receiving
its share of the proceeds from providing the DWR with power from Elk
Hills under the contract. The matter remains scheduled for arbitration
in the third quarter of 2003.

In May 2003 a Federal judge issued an order finding that the U.S.
Department of Energy's (DOE) abbreviated assessment of two Mexicali
power plants, including SER's TDM plant, failed to evaluate the plants'
environmental impact adequately and calls into question the U.S.
permits they received to build their cross-border transmission lines.
On July 8, 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 has until May 15,
2004, to demonstrate why the court should not set aside the permits.

In 1999 Sempra Energy and PSEG Global each acquired a 44-percent
interest in Luz Del Sur, an electric distribution company based in
Peru. Local law required that electricity assets built with government
funds be purchased by the local utility and added to rate base. The
government financed 194 projects that were subsequently transferred to
Luz Del Sur. A dispute arose between the government and Luz Del Sur
over the amount of compensation due for the projects received by Luz
Del Sur. According to the government, the total amount owed relating to
these projects was approximately $36 million. Luz Del Sur argued that
the amount was less and the matter was settled with the government for
approximately $10 million. On May 12, 2003, following a change in the
government in Peru, a criminal charge was filed against certain
government officials, and utility officials as accomplices, including
the Chief Executive Officer and Chief Financial Officer of Luz Del Sur,
alleging that the settlements did not provide the government with
adequate compensation. Luz Del Sur is currently investigating this
matter.

Except for the matters referred to above, 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 a material
adverse effect on the company's financial condition or results of
operations.

INCOME TAX ISSUES

Section 29 Income Tax Credits

The Internal Revenue Service (IRS) has recently issued Announcement
2003-46, stating it has reason to question the scientific validity of
testing procedures and results related to Section 29 income tax
credits. The notice also announced that it would suspend the issuance
of new rulings until its review is complete and that rulings could be
revoked if the IRS did not determine that the test procedures
demonstrate a significant chemical change between the feedstock coal
and the synthetic fuel.

As part of its recently commenced normal audit program for the company
for the period 1998-2001, the IRS has notified the company of its
intention to audit the synthetic fuel operations of Sempra Energy
Trading and Sempra Energy Financial. Through June 30, 2003, the company
has recorded Section 29 income tax credits of $194 million, including
$28 million and $52 million during the three months and six months
ended June 30, 2003. For the second half of 2003, the company's 2003
forecast has included additional contributions to net income of $22
million from Section 29 income tax credits, net of operating costs of
the related facilities. The company believes retroactive disallowance
of Section 29 income tax credits is unlikely.

Luz del Sur

Peruvian income-tax authorities have challenged the valuation of Luz
del Sur's assets for tax depreciation purposes. If the Peruvian
government is successful in its challenge, income-tax deductions for
depreciation will be reduced, resulting in additional income taxes,
interest and penalties aggregating as much as $16 million for the
company's share for the period being questioned (1996 through 1999) and
$12 million for subsequent periods. The company believes that it has
substantial defenses to the imposition of any additional taxes.

Spanish Holding Company

The IRS has issued Notice 2003-50, stating that regulations will be
issued that will adversely affect foreign tax credit utilization by
companies with "stapled-stock" affiliates. The company's intermediate
parent company for many of its non-domestic subsidiaries is such a
company. The most adverse resolution of this issue could result in a
charge to net income of $13 million by the company.

The company is unable to predict the net effect of the ultimate
resolution of these income tax issues.

Pending Internal Revenue Service Matters

The company is in discussions with the IRS to resolve issues related to
various prior years' returns. A recently issued Revenue Ruling dealing
with utility balancing accounts, and recent discussions with the IRS
concerning this Ruling and another matter lead the company to believe
it will be entitled to record a reduction in previously recorded income
tax expense, accrue significant interest income on overpayments of tax
in certain prior periods and reverse recorded interest associated with
the reporting of these items in other prior periods. The company
expects that these matters will be favorably resolved before year end
and estimates that the resolution will increase reported 2003 earnings
in excess of $75 million.

QUASI-REORGANIZATION

In 1993, PE divested its merchandising operations and most of its oil
and natural gas exploration and production business. In connection with
the divestitures, PE effected a quasi-reorganization for financial
reporting purposes effective December 31, 1992. Management believes the
remaining balances of the liabilities established in connection with
the quasi-reorganization are adequate.

4. SEGMENT INFORMATION

The company is a holding company, whose subsidiaries are primarily
engaged in the energy business. It has four separately managed
reportable segments comprised of SoCalGas, SDG&E, SET and SER. The
California Utilities operate in essentially separate service
territories under separate regulatory frameworks and rate structures
set by the CPUC. SoCalGas is a natural gas distribution utility,
serving customers throughout most of southern California and part of
central California. SDG&E provides electric service to San Diego and
southern Orange counties, and natural gas service to San Diego county.
SET, based in Stamford, Connecticut, is a wholesale trader of physical
and financial energy products and other commodities, and a trader and
wholesaler of metals, serving a broad range of customers in the United
States, Canada, Europe and Asia. SER develops, owns and operates power
plants and natural gas storage, production and transportation
facilities within the western and southwestern United States and Baja
California, Mexico.

The accounting policies of the segments are described in the notes to
Consolidated Financial Statements in the company's 2002 Annual Report,
and segment performance is evaluated by management based on reported
income. California utility transactions are based on rates set by the
CPUC and FERC. Other than SER's completing the construction of
combined-cycle power plants, there were no significant changes in
segment assets during the six months ended June 30, 2003.

- -----------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
------------------- ------------------
(Dollars in millions) 2003 2002 2003 2002
- -----------------------------------------------------------------------
Operating Revenues:
Southern California Gas $ 820 $ 670 $ 1,828 $ 1,402
San Diego Gas & Electric 520 414 1,082 846
Sempra Energy Trading 305 192 528 398
Sempra Energy Resources 129 116 219 139
All other 82 103 132 188
Intersegment revenues (16) (7) (26) (10)
------------------------------------------
Total $ 1,840 $ 1,488 $ 3,763 $ 2,963
- -----------------------------------------------------------------------
Net Income (Loss):
Southern California Gas* $ 37 $ 51 $ 95 $ 111
San Diego Gas & Electric* 41 51 86 104
Sempra Energy Trading 35 21 17 63
Sempra Energy Resources 5 34 15 31
All other (2) (10) (9) (16)
------------------- ----------------------
Total $ 116 $ 147 $ 204 $ 293
- -----------------------------------------------------------------------
* after preferred dividends

- --------------------------------------------------------
Balance at
------------------------
June 30, December 31,
2003 2002
- --------------------------------------------------------
Assets:
Southern California Gas $ 3,967 $ 4,079
San Diego Gas & Electric 5,464 5,123
Sempra Energy Trading 5,441 5,614
Sempra Energy Resources 1,576 1,347
All other 2,786 2,580
Intersegment receivables (1,011) (986)
------------------------
Total $ 18,223 $ 17,757
- --------------------------------------------------------

5. FINANCIAL INSTRUMENTS

Note 10 of the notes to Consolidated Financial Statements in the Annual
Report discusses the company's financial instruments, including the
adoption of SFAS 133, "Accounting for Derivative Instruments and
Hedging Activities," as amended by SFAS 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities." The effect is
to recognize all derivatives as assets or liabilities on the balance
sheet, measure those instruments at fair value, and recognize any
changes in fair value in earnings for the period that the change occurs
unless the derivative qualifies as an effective hedge that offsets
other exposures.

The company utilizes derivative financial instruments to manage its
exposure to unfavorable changes in commodity prices, which are subject
to significant and often volatile fluctuations. Derivative financial
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 or paid by the
company and, in the case of the California Utilities, their customers.
In accordance with SFAS 133, the California Utilities have elected to
account for contracts that are settled by physical delivery at
historical cost, with gains and losses reflected in the income
statement at the contract settlement date.

SET's and SES's derivative instruments are recorded at fair value
pursuant to SFAS 133 and are included in the Consolidated Balance
Sheets as trading assets or liabilities. Net gains and losses on these
derivative transactions are recorded in "Other operating revenues" in
the Statements of Consolidated Income. In October 2002, the EITF
reached a consensus to rescind Issue 98-10 "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities," which was
the basis for fair value accounting used for recording energy-trading
activities by SET and SES. The consensus requires that all new energy-
related contracts entered into subsequent to October 25, 2002 should
not be accounted for pursuant to Issue 98-10. Instead, those contracts
should be accounted for at historical cost or the lower of cost or
market, unless the contracts meet the requirements for fair value
accounting under SFAS 133.

Energy transportation and storage contracts entered into by the company
on or after October 25, 2002 are recorded at cost. Energy commodity
inventory is being recorded at the lower of cost or market. The
company's base metals and concentrates inventory continue to be
recorded at fair value as provided by Accounting Research Bulletin
Number 43. On January 1, 2003, as a result of the rescission of EITF
98-10, SET and SES recorded a cumulative effect of a change in
accounting principle, which reduced after-tax earnings by $29 million,
related to the non-derivative contracts that were recorded at fair
value under EITF 98-10 but are not covered by SFAS 133. The ongoing
effect of EITF 98-10's rescission further reduced after-tax earnings
for the six months ended June 30, 2003 by $16 million, including $7
million for the three months ended June 30, 2003. Neither of these
effects impacted cash flow or liquidity.

The carrying values of SET's trading assets and trading liabilities
approximate the following:

June 30, December 31,
(Dollars in millions) 2003 2002
- ----------------------------------------------------------------------------
TRADING ASSETS:
Unrealized gains on swaps and forwards $1,401 $1,226
OTC commodity options purchased 528 480
Due from trading counterparties 1,007 1,279
Due from commodity clearing organizations
and clearing brokers 104 49
Resale agreements 44 --
Commodities owned 1,710 1,968
------ ------
Total trading assets $4,794 $5,002
====== ======

TRADING LIABILITIES:
Unrealized losses on swaps and forwards $1,088 $ 816
OTC commodity options written 463 569
Due to trading counterparties 1,345 1,196
Repurchase obligations 1,240 1,511
------ ------
Total trading liabilities $4,136 $4,092
====== ======

Fixed-price contracts and other derivatives on the Consolidated Balance
Sheets primarily reflect the California Utilities' derivative gains and
losses related to long-term delivery contracts for purchased power and
natural gas transportation. The California Utilities have established
regulatory assets and liabilities to the extent that these gains and
losses are recoverable or payable through future rates. Other
significant derivatives recorded on the balance sheet include a fixed-
to-floating interest rate swap agreement and a contingent purchase
price obligation arising from the company's acquisition of the proposed
Hackberry, La. LNG project. Payments under the swap agreement and
changes in interest rate (LIBOR) are reflected as adjustments to long-
term debt. The contingent payments under the proposed LNG project
purchase obligation are included in property, plant and equipment. The
changes in fixed-price contracts and other derivatives on the
Consolidated Balance Sheets for the six months ended June 30, 2003 were
primarily due to the contingent purchase price obligation arising from
the company's acquisition of the proposed Hackberry, La. LNG project,
partially offset by physical deliveries under long-term purchased-power
and natural gas transportation contracts. 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 or 2002.

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.

RESULTS OF OPERATIONS

California Utility Revenues and Cost of Sales

Natural gas revenues increased to $2.1 billion for the six months ended
June 30, 2003 from $1.6 billion for the corresponding period in 2002,
and the cost of natural gas increased to $1.2 billion in 2003 from $729
million in 2002. Additionally, natural gas revenues increased to $929
million for the three months ended June 30, 2003 from $754 million for
the corresponding period in 2002, and the cost of natural gas increased
to $480 million in 2003 from $305 million in 2002. These changes were
primarily attributable to natural gas price increases, which are passed
on to customers, partially offset by reduced volumes.

Under the current regulatory framework, changes in core-market natural
gas prices for core customers (primarily residential and small
commercial and industrial customers) do not affect net income, since
core-customer rates generally recover the actual cost of natural gas on
a substantially concurrent basis and are fully balanced. 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 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 $792 million for the six months ended
June 30, 2003 from $604 million for the same period in 2002, and the
cost of electric fuel and purchased power increased to $300 million in
2003 from $140 million in 2002. Additionally, electric revenues
increased to $397 million for the three months ended June 30, 2003 from
$323 million for the same period in 2002, and the cost of electric fuel
and purchased power increased to $137 million in 2003 from $79 million
in 2002. These changes were mainly due to the effect of the DWR's
purchasing the net short position of SDG&E during 2002, changes in
electric commodity costs, the increase in authorized distribution
revenue and higher volumes in 2003. Under the current regulatory
framework, changes in commodity costs do not affect net income. The
commodity costs associated with the DWR's purchases and the
corresponding sale to SDG&E's customers were not included in the
Statements of Consolidated Income as SDG&E was merely transmitting the
electricity from the DWR to the customers, acting as a conduit to pass
through the electricity from the DWR to the customers. During 2003,
costs associated with long-term contracts allocated to SDG&E from the
DWR were likewise not included in the income statement, since the DWR
retains legal and financial responsibility for these contracts.

The tables below summarize the natural gas and electric volumes and
revenues by customer class for the six months ended June 30, 2003 and
2002.

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)

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.

Other Operating Revenues

Other operating revenues, which consist primarily of revenues at
Global, increased to $880 million for the six months ended June 30,
2003 from $725 million for the same period of 2002. These changes were
primarily due to higher revenue at SET due to increased volumes and
increased coal sales related to Section 29 income tax credits, and
increased revenues from SER, which resulted mainly from higher sales of
electricity to the DWR under the contract which recommenced in April
2002, and sales by its Twin Oaks power plant, purchased in the fourth
quarter of 2002.

Other operating revenues increased to $514 million for the three-month
period ended June 30, 2003 from $411 million for the corresponding
period of 2002 due primarily to the increased revenue at SET resulting
from increased volumes and volatility in the energy commodity markets
and the increased coal sales.

Other Cost of Sales

Other cost of sales, which consists primarily of cost of sales at
Global, increased to $515 million for the six months ended June 30,
2003 from $338 million for the six months ended June 30, 2002, and
increased to $296 million for the three months ended June 30, 2003,
from $206 million for the same period in 2002. The increase for the
six-month period was primarily due to the increased sales as noted
above for SER, and the increased activity at SET. The increase for the
quarter was primarily due to the increased activity at SET.

Other Operating Expenses

Other operating expenses increased to $963 million for the six months
ended June 30, 2003 from $890 million for the same period in 2002. Of
the total balance, $682 million and $641 million in 2003 and 2002,
respectively, represent other operating expenses at the California
Utilities. The increase was due primarily to general operating cost
increases at SoCalGas and SER.

Other operating expenses increased to $518 million for the three months
ended June 30, 2003 from $475 million for the corresponding period of
2002. Of the total balance, $364 million and $360 million in 2003 and
2002, respectively, represent other operating expenses at the
California Utilities. The increase was primarily due to increased
operating costs at SET, SER and SoCalGas.

Other Income - Net

Other income, which primarily consists of equity earnings from
unconsolidated subsidiaries and interest on regulatory balancing
accounts, decreased to $4 million for the six months ended June 30,
2003 from $27 million for the six months ended June 30, 2002. The
decrease was primarily due to SEI's foreign exchange losses, compared
to its foreign exchange gains in the prior-year period and increased
equity losses at SER and other subsidiaries, offset partially by
increased equity earnings from SEI's Argentine subsidiaries.

Income Taxes

Income tax expense decreased to $51 million for the six months ended
June 30, 2003 from $74 million for the same period of 2002. The
effective income tax rates were 18.0 percent and 20.3 percent for the
six-month periods ended June 30, 2003 and 2002, respectively. The
change was primarily due to reduced pretax income and increased income
tax credits from synthetic fuel investments in 2003 (see discussion of
Section 29 credits in Note 3), offset partially by a $25 million
favorable resolution of income-tax issues at SDG&E in the second
quarter of 2002.

In connection with its affordable-housing investments, the company has
unused tax credits dating back to 1999, which the company fully expects
to utilize in future years. At June 30, 2003, the amount of these
unused tax credits was $172 million. In addition, at June 30, 2003, the
company has $46 million of alternative minimum tax credits with no
expiration date.

Income tax expense increased to $27 million for the second quarter of
2003 compared to $15 million for the second quarter of 2002, and the
effective income tax rate increased to 18.9 percent from 9.4 percent.
This change was due to the $25 million favorable resolution of SDG&E's
income-tax issues in 2002 discussed above.

Net Income

For the six months ended June 30, net income decreased to $204 million,
or $0.98 per diluted share of common stock, in 2003 from $293 million,
or $1.42 per diluted share in 2002. Excluding the effects of the
cumulative effect of the change in accounting principle in 2003 ($0.14
per diluted share, discussed in Note 2 of the notes to Consolidated
Financial Statements) and the extraordinary item in 2002 ($0.01 per
diluted share, discussed in the Annual Report), the change in net
income in 2003 was primarily due to the $25 million after-tax benefit
in 2002 discussed above, as well as lower income from SET and SoCalGas.

Net income for the second quarter was $116 million, or $0.55 per
diluted share for 2003, compared to $147 million or $0.71 per diluted
share in 2002. The change was primarily due to lower income from SER
and SoCalGas and the 2002 tax benefit discussed above, offset partially
by increased income from SET.

Net Income by Business Unit

- -------------------------------------------------------------------------------

SOUTHERN CALIFORNIA GAS COMPANY

SoCalGas recorded net income of $95 million and $111 million for the
six-month periods ended June 30, 2003 and 2002, respectively, and net
income of $37 million and $51 million for the three-month periods ended
June 30, 2003 and 2002, respectively. The change was primarily due to
the end of sharing of the merger savings (discussed in the Annual
Report) and increased operating expenses associated with legal costs
principally related to antitrust litigation, partially offset by
increased margins and other factors.

SAN DIEGO GAS & ELECTRIC

SDG&E recorded net income of $86 million and $104 million for the six-
month periods ended June 30, 2003 and 2002, respectively, and net
income of $41 million and $51 million for the three-month periods ended
June 30, 2003 and 2002, respectively. The decreases were primarily due
to income-tax effects, primarily the $25 million after-tax benefit from
the favorable resolution of prior years' income-tax issues recorded in
the second quarter of 2002, and the end of sharing of the merger
savings, partially offset by increased margins and increased output at
SONGs.

SEMPRA ENERGY TRADING

SET recorded net income of $17 million and $63 million for the six-
month periods ended June 30, 2003 and 2002, respectively, and net
income of $35 million and $21 million for the three-month periods ended
June 30, 2003 and 2002, respectively. For purposes of comparison with
the corresponding 2002 period, net income for the six months ended June
30, 2003 would have been $61 million if not for the repeal of EITF 98-
10 as described in Note 2 of the notes to Consolidated Financial
Statements. The repeal of EITF 98-10 adversely impacted SET's results
by a cumulative effect adjustment of $28 million and an additional $16
million related to operations for the six months ended June 30, 2003,
including $7 million for the three months ended June 30, 2003.

A summary of SET's net unrealized revenues for trading activities for
the six-month periods ended June 30, 2003 and 2002 follows:

(Dollars in millions) 2003 2002
- -----------------------------------------------------------------
Balance at beginning of period $ 180 $ 405
Cumulative effect adjustment (48) --
Additions 599 186
Realized (277) (184)
------------------------------------
Balance at June 30 $ 454 $ 407
====================================

The estimated fair values for SET's trading activities as of June 30,
2003, and the periods during which net unrealized revenues are expected
to be realized, are (dollars in millions):

- -------------------------------------------------------------------------

The following table summarizes the counterparty credit quality for SET.
These amounts are net of collateral in the form of customer margin
and/or letters of credit.

June 30, December 31,
(Dollars in millions) 2003 2002
- -----------------------------------------------------------------
Counterparty credit quality*
Commodity Exchanges $ 104 $ 49
AAA 46 69
AA 340 194
A 384 316
BBB 417 559
Below investment grade 393 504
---------------------------
Total $ 1,684 $ 1,691
===========================
* Except for commodity exchanges, counterparty credit quality is
determined by rating agencies or internal models intended to
approximate rating-agency determinations.
- -----------------------------------------------------------------

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

See also the discussion concerning the CPUC's prohibition of IOUs'
procuring electricity from their affiliates in "Electric Industry
Restructuring" in Note 13 of the Annual Report.

SEMPRA ENERGY RESOURCES

SER recorded net income of $15 million and $31 million for the six-
month periods ended June 30, 2003 and 2002, respectively, and net
income of $5 million and $34 million for the three-month periods ended
June 30, 2003 and 2002, respectively. The changes were primarily due to
the pricing structure of SER's contract with the DWR, increased
interest expense due to borrowings for the new power plants, and start-
up expenses related to the new power plants.

SEMPRA ENERGY INTERNATIONAL

SEI recorded net income of $25 million and $17 million for the six-
month periods ended June 30, 2003 and 2002, respectively, and net
income of $18 million and $9 million for the three-month periods ended
June 30, 2003 and 2002, respectively. The changes were primarily due to
increased equity earnings from its Argentine subsidiaries partially
offset by the effect of foreign currency losses in 2003.

SEMPRA ENERGY SOLUTIONS

SES recorded net income of $7 million and $6 million for the six-month
periods ended June 30, 2003 and 2002, respectively, and net income of
$8 million and $5 million for the three-month periods ended June 30,
2003 and 2002, respectively.

SEMPRA ENERGY FINANCIAL

SEF invests as a limited partner in affordable-housing properties.
SEF's portfolio includes 1,300 properties throughout the United States,
including Puerto Rico and the Virgin Islands. These investments are
expected to provide income tax benefits (primarily from income tax
credits) over 10-year periods. SEF also has an investment in a limited
partnership which produces synthetic fuel from coal. See discussion of
Section 29 income tax credits in Note 3 of the Notes to Consolidated
Financial Statements under "Income Tax Issues." Whether SEF will invest
in additional properties will depend on Sempra Energy's income tax
position.

SEF recorded net income of $19 million and $14 million for the six-
month periods ended June 30, 2003 and 2002, respectively, and net
income of $8 million and $7 million for the three-month periods ended
June 30, 2003 and 2002, respectively.

CAPITAL RESOURCES AND LIQUIDITY

The company's California Utility operations are the major source of
liquidity. Funding of other business units' capital expenditures is
largely dependent on the California Utilities' paying sufficient
dividends to Sempra Energy, which, in turn, depends on the sufficiency
of those earnings in excess of utility needs.

For additional discussion, see "Factors Influencing Future Performance-
- -Electric Industry Restructuring and Electric Rates" herein and Note 3
of the notes to Consolidated Financial Statements.

At June 30, 2003, the company had $325 million in cash and $2.3 billion
in unused, committed lines of credit available, of which $388 million
was supporting commercial paper and variable-rate debt. On July 10,
2003, the CPUC issued a decision authorizing SoCalGas to issue up to
$715 million of long-term debt, of which not less than $500 million
will be used for the retirement of currently outstanding debt or
preferred stock. The decision also grants SoCalGas an exemption from
the Competitive Bidding Rule and permits SoCalGas to enter into
interest-rate swaps, caps, collars and currency-exchange contracts.

Management believes these amounts, 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
significantly reduced and/or the company was unable to issue new
securities under acceptable terms, neither of which is considered
likely, the company would be required to reduce non-utility capital
expenditures and investments in new businesses. Management continues to
regularly monitor the company's ability to adequately meet the needs of
its operating, financing and investing activities.

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 significant
dividends to Sempra Energy.

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 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 $316 million at June 30,
2003, down from $418 million at December 31, 2002. Company management
continuously monitors the level of SET's cash requirements in light of
the company's overall liquidity.

SER's projects are expected to be financed through a combination of the
existing synthetic lease, project financing, SER's borrowings and funds
from the company. Its capital expenditures over the next several years
may require some additional funding.

SEI is expected to require funding for its planned development of
liquefied natural gas (LNG) facilities and to continue the expansion of
its existing natural gas distribution operations in Mexico. While
internal funds are expected to be adequate for these purposes, the
company may decide to use project financing if that is more
advantageous.

SES is expected to require moderate amounts of cash in the near future
as its commodity and energy services businesses continue to grow.

SEF is expected to continue to be a net provider of cash through
reductions of consolidated income tax payments resulting from its
investments in affordable housing and synthetic fuel.

CASH FLOWS FROM OPERATING ACTIVITIES

Net cash provided by operating activities totaled $756 million and $754
million for the six months ended June 30, 2003 and 2002, respectively.
Offsetting factors included the higher realization in net trading
assets in 2003 and greater compensation costs paid in 2002 versus the
increases in overcollected regulatory balancing accounts in 2002
(resulting from higher natural gas usage in 2002 and the reduced rate
of recovery of the AB265 undercollection in 2003) and higher income tax
payments in 2003.

CASH FLOWS FROM INVESTING ACTIVITIES

Net cash used in investing activities totaled $639 million and $759
million for the six months ended June 30, 2003 and 2002, respectively.
The change in cash flows from investing activities was attributable to
a higher level of acquisition activity in 2002, lower capital
expenditures for the Termoelectrica de Mexicali (TDM) power plant in
2003, and loans to an unconsolidated subsidiary (Atlantic Electric &
Gas Limited) in 2003.

Capital expenditures for property, plant and equipment by the
California Utilities are estimated to be $750 million for the full year
2003 and are being financed primarily by internally generated funds and
security issuances. Construction, investment and financing programs are
continuously reviewed and revised in response to changes in
competition, customer growth, inflation, customer rates, the cost of
capital, and environmental and regulatory requirements. Capital
expenditures for property, plant and equipment by the company's other
businesses are estimated to be $550 million for the full year 2003, of
which $230 million is for SER's power plant construction and other
capital projects.

In April 2003, Sempra Energy LNG Corp., a newly created subsidiary
within the SEI business unit, completed its previously announced
acquisition of the proposed Hackberry, La. LNG project from a
subsidiary of Dynegy, Inc. Sempra Energy LNG Corp., paid Dynegy $20
million on April 23, 2003, for the first phase of the transaction,
which includes rights to the location, licensing and preliminary FERC
approval. Additional payments are contingent on meeting certain
benchmarks and milestones and the performance of the project, now known
as Cameron. The total cost of the project is expected to be
approximately $700 million. The project could begin commercial
operations in early 2007. Final FERC approval is expected by the end of
2003.

In connection with SEI's plans to develop Energia Costa Azul, an LNG
receiving terminal in Baja California, about 50 miles south of San
Diego, Mexico's national environmental agency issued the principal
onshore environmental permit to SEI in April 2003. The secondary
offshore environmental permit is pending and is expected by October
2003. Two other significant permits, an operating permit from Mexico's
Energy Regulatory Commission and a local land-use permit from the City
of Ensenada, are pending and expected to be received in the near
future. Energia Costa Azul will bring natural gas into northwestern
Mexico and southern California. The project is currently estimated to
cost $600 million and to commence commercial operations in early 2007.

CASH FLOWS FROM FINANCING ACTIVITIES

Net cash used in financing activities totaled $247 million and $78
million for the six months ended June 30, 2003 and 2002, respectively.
The change in cash flows from financing activities was attributable to
reduced long-term borrowings in 2003 partly offset by reduced
repayments of short-term debt in 2003.

In January 2003, the company issued $400 million of 10-year 6% notes
due February 2013. The bonds are not subject to a sinking fund and are
not redeemable prior to maturity except through a make-whole mechanism.
Proceeds were used to pay down commercial paper. These bonds were
assigned ratings of A- by the S&P rating agency, Baa1 by Moody's and A
by Fitch, Inc.

On January 15, 2003, $70 million of SoCalGas' $75 million 5.67% medium-
term notes were put back to the company. In March 2003, SER repaid $100
million outstanding under a line of credit. On April 7, 2003, SoCalGas
called its $100 million 7.375% first-mortgage bonds at a premium of
3.53 percent. In addition, during the six months ended June 30, 2003,
Sempra Energy Financial repaid $35 million of debt incurred to acquire
limited partnerships and SDG&E repaid $32 million of rate-reduction
bonds.

Dividends paid on common stock amounted to $104 million and $102
million for the six months ended June 30, 2003 and 2002, respectively.

In April 2003, PE amended its revolving line of credit and extended the
expiration date by an additional two years. The revolving credit
commitment, initially $500 million, declines semi-annually by $125
million until expiration on April 5, 2005 and is for the purpose of
funding loans by PE to Global. Borrowings under the agreement would
bear interest at rates varying with market rates, PE's credit ratings
and the amount of the borrowings outstanding. They would be guaranteed
by Sempra Energy and would be subject to mandatory repayment if
SoCalGas' unsecured long-term credit ratings were to cease to be at
least BBB by S&P and Baa2 by Moody's, if Sempra Energy's or SoCalGas'
debt-to-total capitalization ratio (as defined in the agreement) were
to exceed 65 percent, or if there were to be a change in law materially
and adversely affecting the ability of SoCalGas to pay dividends or
make distributions to PE. No borrowings have been made under this
agreement.

In May 2003, the California Utilities replaced their expiring $500
million, 364-day credit agreement with a substantially identical
agreement expiring on May 14, 2004. Under the agreement, each utility
may individually borrow up to $300 million, subject to a combined
borrowing limit for both utilities of $500 million. At the maturity
date, each utility may convert its then outstanding borrowings to a
one-year term loan, subject to having obtained any requisite regulatory
approvals. Borrowings under the agreement would be available for
general corporate purposes including back-up support for commercial
paper and variable-rate long-term debt, and would bear interest at
rates varying with market rates and the borrowing utility's credit
rating. The agreement requires each utility to maintain a debt-to-
total capitalization ratio (as defined in the agreement) of not to
exceed 60 percent. The rights, obligations and covenants of each
utility under the agreement are individual rather than joint with those
of the other utility, and a default by one utility would not constitute
default by the other.

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, SEI and
other businesses. Recent developments concerning the factors
influencing future performance are summarized below. Note 3 of the
notes to Consolidated Financial Statements and the Annual Report
describe events in the deregulation of California's electric and
natural gas industries and various FERC, SET and income tax issues.

Income-Tax Issues

Resolution of the income-tax issues described in Note 3 of the notes to
Consolidated Financial Statements herein could have a material impact
on results of operations for 2003, or one or more future periods.

California Utilities

Electric Industry Restructuring and Electric Rates

Supply/demand imbalances and a number of other factors resulted in
abnormally high electric-commodity costs beginning in mid-2000 and
continuing into 2001. This caused SDG&E's customer bills to be
substantially higher than normal. In response, legislation enacted in
September 2000 imposed a ceiling on the cost of electricity that SDG&E
could pass on to its small-usage customers on a current basis. SDG&E
accumulated the amount that it paid for electricity in excess of the
ceiling rate in an interest-bearing balancing account, which it
continues to collect from its customers. During the six months ended
June 30, 2003, the balance in the balancing account declined from $215
million to $174 million.

Subsequent to the electric capacity shortages of 2000-2001, SDG&E's
service territory has had and continues to have an adequate supply of
electricity. However, various projections of electricity demand in
SDG&E's service territory indicate that, without additional electrical
generation or reductions in electrical usage, beginning in 2005
electricity demand could begin to outstrip available resources. SDG&E's
strategy for meeting this demand is to: (1) reduce power demand through
conservation and efficiency; (2) increase the supply of electricity
from renewable sources, including wind and solar; (3) establish new
transmission lines by 2008 to import more power; and (4) provide new
electric generation by 2005 to meet the expected shortfall. SDG&E has
issued a request for proposals to meet the electric capacity shortfall,
estimated at 69 megawatts in 2005. SDG&E is ahead of the interim
schedule required by California legislation in meeting the requirement
of obtaining 20 percent of its electricity from renewable sources by
2017.

Operating costs of SONGS Units 2 and 3, including nuclear fuel and
related financing costs, and incremental capital expenditures are
recovered through the Incremental Cost Incentive Pricing (ICIP)
mechanism which allows SDG&E to receive approximately 4.4 cents per
kilowatt-hour for SONGS generation. Any differences between these costs
and the incentive price affect net income. This mechanism expires on
December 31, 2003. For the year ended December 31, 2002, ICIP
contributed $50 million to SDG&E's net income. The CPUC has denied the
previously approved market-based pricing for SONGS beginning in 2004
and instead provided for traditional rate-making treatment, under which
the SONGS ratebase would begin at zero, essentially eliminating
earnings from SONGS until ratebase grows. The company has applied for
rehearing of this decision, which the CPUC has not yet ruled on. The
company is in the process of litigating the SONGS revenue requirement,
primarily in conjunction with the General Rate Case of Southern
California Edison (the operator and 75-percent owner of SONGS), for
rates that begin in January 2004. (SDG&E seeks to recover approximately
95 percent of its 2004 SONGS operating & maintenance and capital
revenue requirements in that case.) The remaining five percent of the
company's SONGS revenue requirement will be litigated in SDG&E's Cost
Of Service proceeding.

See additional discussion of this and related topics, including the
CPUC's adjustment to its plan for deregulation of electricity, in Note
3 of the notes to Consolidated Financial Statements.

Natural Gas Restructuring and Rates

As discussed in the Annual Report, in December 2001 the CPUC issued a
decision related to natural gas industry restructuring, with
implementation anticipated during 2002. During 2002 the California
Utilities filed a proposed implementation schedule and revised tariffs
and rules required for implementation. However, on February 27, 2003,
the CPUC issued a resolution rejecting without prejudice those proposed
tariffs and rules. The resolution ordered SoCalGas to file a new
application, which would address detailed proposals for implementation
of the December 2001 decision, but also would allow reconsideration of
the December 2001 decision. SoCalGas filed such an application on June
30, 2003, and proposed some modifications to the provisions of the
December 2001 decision to respond to concerns that it could lead to
higher natural gas costs for consumers. Modifications proposed by
SoCalGas would also remove SoCalGas' exposure to risk or reward for the
sale of receipt-point capacity. The filing proposes implementation of
these provisions on April 1, 2004 and continuing through August 31,
2006. If the December 2001 decision is implemented, it is not expected
to adversely affect the California Utilities' results of operations,
cash flows or financial position. A CPUC decision is expected during
2004.

CPUC Investigation of Compliance with Affiliate Rules

On February 27, 2003, the CPUC opened an investigation of the business
activities of SDG&E, SoCalGas and Sempra Energy to ensure that they
have complied with relevant statutes and CPUC decisions in the
management, oversight and operations of their companies. The Assigned
Commissioner and ALJ issued a ruling which suspends the procedural
schedule until the CPUC completes an independent audit to evaluate
energy-related business activities undertaken by Sempra Energy within
the service territories of SDG&E and SoCalGas, relative to holding
company systems and affiliate activities. The audit is to consider
whether these activities pose any problems for ratepayers and whether
they are consistent with the CPUC's decision, rules or orders and/or
affiliate statutes. The objective of the audit is to analyze the
adequacy of the Affiliate Rules. In accordance with existing CPUC
requirements, the California Utilities' transactions with other Sempra
Energy affiliates have been audited by an independent auditing firm
each year, with results reported to the CPUC, and there have been no
material adverse findings in those audits.

Cost of Service Filing

On May 22, 2003, the assigned CPUC Commissioner modified his previously
adopted procedural schedule on the California Utilities' Cost of
Service applications to expedite a decision by approximately one month,
permitting a decision by as early as March 2004. The assigned
Commissioner also provided for additional comments to be filed on the
California Utilities' request for interim relief for the period from
January 1, 2004 to the date of the Cost of Service decision and stated
that a decision on the request would be prepared for consideration of
the full Commission. On June 3, 2003, various parties filed reply
comments supporting or opposing the motion for January 1, 2004 interim
relief. The CPUC's Office of Ratepayer Advocates' (ORA) report on the
California Utilities' filing is due on August 8, 2003.

An October 10, 2001 decision denied the California Utilities' request
to continue equal sharing between ratepayers and shareholders of the
estimated savings for the 1998 Enova-PE business combination that
created Sempra Energy and, instead, ordered that all of the estimated
2003 merger savings go to ratepayers. This decision will adversely
affect 2003 net income by $24 million at SoCalGas and $11 million at
SDG&E.

Sempra Energy Global Enterprises

Electric-Generation Assets

As discussed in "Cash Flows From Investing Activities" above and in the
Annual Report, the company is involved in the development of several
electric-generation projects that will significantly impact the
company's future performance. SER has approximately 2,700 megawatts of
new generation in operation or under construction. The 550-megawatt Elk
Hills power project, 50 percent owned by SER and located near
Bakersfield, California, began commercial operations in July 2003. The
1,250-megawatt Mesquite Power Plant near Phoenix, Arizona, commenced
commercial operations at 50-percent capacity in June 2003 and is
expected to reach full capacity in November 2003. Termoelectrica de
Mexicali, a 600-megawatt power plant near Mexicali, Baja California,
Mexico, commenced operations in June 2003, contingent upon resolution
of the sufficiency issue of environmental impact studies and permits
(see additional discussion under "Cash Flows from Investing
Activities"). The 305-megawatt Twin Oaks Power Plant located near
Bremond, Texas, was acquired in October 2002. El Dorado Energy, a 480-
megawatt power plant near Las Vegas, Nevada, 50 percent owned by SER,
began commercial operation in May 2000. Electricity from the plants
will be available for markets in California, Arizona, Texas and Mexico.
SER's projected portfolio of plants in the western United States and
Baja California may be used to supply power to California under SER's
agreement with the DWR.

Investments

As discussed in "Cash Flows From Investing Activities" above and in the
Annual Report, the company's investments will significantly impact the
company's future performance. During 2002, SET completed acquisitions
that added base metals trading and warehousing to its trading business.
These acquisitions include Sempra Metals Limited and Henry Bath & Son
Limited. In addition, SET acquired assets of Sempra Metals &
Concentrates Corp. and the U.S. warehousing business of Henry Bath,
Inc. and SER acquired the Twin Oaks Power Plant.

SEI is in the process of developing Energia Costa Azul, an LNG
receiving terminal in Baja California, Mexico, expected to commence
commercial operations in early 2007.

In April 2003, Sempra Energy LNG Corp. acquired the proposed Hackberry,
La. LNG project, to be renamed Cameron LNG, which could begin
commercial operations in early 2007.

On September 6, 2002, SEI initiated proceedings under the 1994
Bilateral Investment Treaty between the United States and Argentina for
recovery of the diminution of the value of its investments resulting
from governmental actions. SEI has made a request for arbitration to
the International Center for Settlement of Investment Disputes (ICSID)
and all arbitrators have been selected. The company has filed a claim
for $258 million with ICSID and has presented additional information
that may provide a basis for a larger award. A decision is expected in
late 2004.

NEW ACCOUNTING STANDARDS

Relevant pronouncements that have recently become effective or that are
yet to be effective are SFAS 142, 143, 148, 149 and 150,
Interpretations 45 and 46, EITF 02-3, and the rescission of EITF 98-10.
See discussion in Note 2 of the notes to Consolidated Financial
Statements. Pronouncements that have or potentially could have a
material effect on future earnings are described below.

In October 2002, the EITF reached a consensus to rescind Issue 98-10
"Accounting for Contracts Involved in Energy Trading and Risk
Management Activities," the basis for mark-to-market accounting used
for recording certain trading activities by SET and SES. The consensus
provided that new contracts entered into subsequent to October 25, 2002
should not be accounted for under mark-to-market accounting unless the
contracts meet the requirements stated under SFAS 133 "Accounting for
Derivative Instruments and Hedging Activities," which is the case for a
substantial majority of the company's contracts. 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. This is further described in Note 2
of the notes to Consolidated Financial Statements. One impact of the
rescission is that an enterprise that hedges its commodity risk on
items previously marked-to-market under Issue 98-10 but not covered by
SFAS 133 could have to record a loss on the hedges without being able
to record the corresponding gain on the hedged items, even though no
economic loss exists.

For SET, its earnings for the six months ended June 30, 2003 of $17
million were negatively impacted by $28 million of the cumulative-
effect adjustment and an additional $16 million related to operations
during the six-month period to reflect the ongoing effects of the
rescission of Issue 98-10. SES's six months ended June 30, 2003 results
were negatively impacted by the cumulative effect adjustment of $1
million to reflect the rescission of Issue 98-10.

SFAS 143, "Accounting for Asset Retirement Obligations" : SFAS 143,
issued in July 2001, addresses financial accounting and reporting for
legal obligations associated with the retirement of tangible long-lived
assets. It requires entities to record the fair value of a liability
for an asset retirement obligation in the period in which it is
incurred. The company adopted SFAS 143 on January 1, 2003. See further
discussion in Note 2 of the notes to Consolidated Financial Statements.

FASB Interpretation No. 46 (FIN 46), "Consolidation of Variable
Interest Entities": In January 2003, the FASB issued FIN 46 to
strengthen existing accounting guidance that addresses when a company
should consolidate a variable interest entity (VIE) in its financial
statements. The consolidation requirements of the interpretation apply
immediately to VIEs created after January 31, 2003. For Sempra Energy,
the consolidation requirements apply to pre-existing VIEs beginning
July 1, 2003.

Sempra Energy has identified two VIEs, of which one is related to the
Mesquite Power Plant and one is related to an investment in an
unconsolidated subsidiary, Atlantic Electric & Gas Limited.
Accordingly, effective July 1, 2003, Sempra Energy will consolidate
these entities, which are expected to significantly increase total
assets and total liabilities by an estimated $650 million. However, the
company does not expect a significant impact to income before the
cumulative effect of a change in accounting principle and estimates
that the cumulative effect of the change will be a charge of $30
million. See Note 2 of the notes to Consolidated Financial Statements
for further discussion.

ITEM 3. 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, 2003, and the average VaR for the six-month
period ended June 30, 2003, 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, 2003 $ 5.28 $ 7.45
Average for the six months ended 6/30/03 $ 7.79 $10.98

As of June 30, 2003, the total VaR of the California Utilities' and
SES's natural gas positions was not material.

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 within 90 days prior to the date of this report has
evaluated the effectiveness of the design and operation of the
company's disclosure controls and procedures. Based on that evaluation,
the company's Chief Executive Officer and Chief Financial Officer have
concluded that the controls and procedures are effective.

There have been no significant changes in the company's internal
controls or in other factors that could significantly affect the
internal controls subsequent to the date the company completed its
evaluation.

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Except as described in Note 3 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 VOTE

Sempra Energy's 13-member 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
13, 2003, the shareholders of Sempra Energy elected four directors for
a three-year term expiring in 2006. 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
- -------------------------------------------------------------
James G. Brocksmith, Jr. 156,575,103 18,417,791
Herbert L. Carter 151,116,141 23,876,753
William D. Jones 151,571,173 23,421,721
William G. Ouchi 147,565,155 27,427,739

Each of the following proposals received a majority of the votes cast
on the proposal and, accordingly, was approved by shareholders. The
results of the voting on the proposals were as follows:

A Compensation Committee proposal
recommending approval of the 2003 Percentage Percentage
Executive Incentive Plan. of Shares of Shares
Votes Outstanding Voted
----------- ------------ ------------
In Favor 144,196,405 69% 85%
Opposed 25,403,742 12% 15%

A shareholder proposal recommending
simple majority voting.

In Favor 82,924,874 40% 59%
Opposed 56,465,786 27% 41%

A shareholder proposal recommending
annual election of all directors.

In Favor 78,201,213 37% 56%
Opposed 61,349,322 29% 44%

The following proposal did not receive a majority of the votes cast on
the proposal and, accordingly, was not approved by shareholders. The
results of the voting on the proposal were as follows:

A shareholder proposal recommending
an independent Chairman of the Board.

Percentage Percentage
of Shares of Shares
Votes Outstanding Voted
----------- ------------ ------------

In Favor 57,376,389 27% 41%
Opposed 81,986,910 39% 59%

Additional information concerning the election of the board of
directors and other matters voted upon at the Annual Meeting is
contained in Sempra Energy's Notice of 2003 Annual Meeting of
Shareholders and Proxy Statement.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

Exhibit 10 - Material Contracts

10.1 2003 Executive Incentive Plan

10.2 Amended 1998 Long-Term Incentive Plan

Exhibit 12 - Computation of ratios

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

Exhibit 31 - Section 302 Certification

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 Certification

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, 2003:

Current Report on Form 8-K filed May 1, 2003, filing as an exhibit
Sempra Energy's press release of May 1, 2003, giving the financial
results for the three months ended March 31, 2003.

Current Report on Form 8-K filed August 7, 2003, filing as an exhibit
Sempra Energy's press release of August 7, 2003, giving the financial
results for the three months ended June 30, 2003.

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 7, 2003 By: /s/ F. H. Ault
----------------------------
F. H. Ault
Sr. Vice President and Controller