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 March 31, 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
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(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 April 30, 2003: 207,446,243
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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
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

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).

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 No. 71,
"Accounting for the Effects of Certain Types of Regulation" (SFAS 71).

COMPREHENSIVE INCOME

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

Three months
ended
March 31,
--------------
(Dollars in millions) 2003 2002
- ----------------------------------------------
Net income $ 88 $ 146
Foreign currency adjustments 14 (94)
Minimum pension liability
adjustments (6) --
Financial instruments (Note 5) -- (1)
--------------
Comprehensive income $ 96 $ 51
- ----------------------------------------------

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 recorded in 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
three months ended March 31, 2003. In addition, the effect of rescinding
EITF 98-10 negatively impacted the first quarter 2003 after-tax earnings
by an additional $9 million. Neither effect impacted 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 mark-
to-market gains and losses on trading contracts to be recorded on a net
basis in the income statement, effective for financial statements issued
for 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 was tested for impairment in 2002. 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 2003 SEI purchased the remaining interests in its Mexican
investments, 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 three months
ended March 31, 2003 was 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 March 31, 2003 $ 141 $ 51 $ 192
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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.

The change in the asset retirement obligations for the three months
ended March 31, 2003 was as follows (dollars in millions):

Balance as of January 1, 2003 $ --
Adoption of SFAS 143 329
Accretion expense 6
------
Balance as of March 31, 2003 $ 335*
======

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

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

SFAS 148 "Accounting for Stock-Based Compensation -- Transition and
Disclosure": SFAS 148 requires quarterly disclosure of the effects that
would have occurred 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(dollars in millions
except per share amounts):

Three months ended March 31,
----------------------------
2003 2002
---------- ----------
Net income as reported $ 88 $ 146
Stock-based employee compensation expense
reported in net income, net of tax 7 3
Total stock-based employee compensation
under fair value method for all awards,
net of tax (9) (5)
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Pro forma net income $ 86 $ 144
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Earnings per share:
Basic--as reported $ 0.43 $ 0.71
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Basic--pro forma $ 0.42 $ 0.70
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Diluted--as reported $ 0.42 $ 0.71
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Diluted--pro forma $ 0.41 $ 0.70
========== ==========

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 a guarantor is required to recognize, at
the inception of a guarantee, 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 46, as described below.

FASB Interpretation No. 46 (FIN 46), "Consolidation of Variable Interest
Entities": Effective in the third quarter of 2003, FIN 46 will require
inclusion on the Consolidated Balance Sheets of $585 million each of
additional property, plant and equipment and long-term debt related to
the synthetic lease for the Mesquite Power Plant currently under
construction. This inclusion will have no effect on income from the
prior periods since the plant is still under construction.

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.

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 is
preparing a request for proposals to meet the electric capacity
shortfall, estimated at 69 megawatts in 2005. In addition, SDG&E is
ahead of the interim schedule in meeting the requirement of obtaining 20
percent of its electricity from renewable sources by 2017.

The power crisis of 2000-2001 has caused the California Public Utilities
Commission (CPUC) to adjust its plan for deregulation of electricity. In
addition, several California state agencies, including the CPUC, the
Consumer Power and Conservation Financing Authority, and the Energy
Resources Conservation and Development Commission, recently issued a
draft 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.

Senate Bill 888, introduced on February 21, 2003, would repeal the
provisions of Assembly Bill 1890, which enacted electric industry
restructuring in September 1996. In addition, Senate Bill 429,
introduced on February 20, 2003, would subject the company and other
California energy-utility holding companies to the 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. The likelihood of
passage of either bill is not known.

The CPUC has undertaken a proceeding and issued several decisions
establishing the framework, rules and processes that governed SDG&E's
return to the responsibility of procuring electricity for its customers.
These include decisions (1) allocating to California's investor-owned
utilities (IOUs) the power from the long-term contracts entered into by
the California Department of Water Resources (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) adopting 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 a procurement incentive mechanism.

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 assigned 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 circumstances SDG&E may be obligated to provide
lines of credit in connection with its allocated contracts. On April 17,
2003, SDG&E filed its natural gas procurement plan related to certain
DWR contracts.

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 is required to file this new
application by June 30, 2003, but has filed a petition for modification
requesting the CPUC defer the filing of this application until October
15, 2003. If the December 2001 decision is implemented, it is not
expected to adversely affect the California Utilities' earnings.

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. Hearings have
been scheduled for the Fall of 2003 and a decision is expected in 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 CPUC will 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. In accordance with a December
16, 1997 CPUC order, the California Utilities' transactions with other
Sempra Energy affiliates have been audited each year and there have been
no adverse findings in those audits.

COST OF SERVICE

Although the California Utilities requested that a decision in their
Cost of Service applications be effective January 1, 2004, the CPUC
commissioner assigned to the applications has adopted a procedural
schedule that would prevent the CPUC from issuing a decision before the
second quarter of 2004. The California Utilities have filed a motion
seeking reconsideration of this ruling. The motion also seeks
authorization to implement an interim rate increase on January 1, 2004
to reflect an anticipated cost of service decision with any increase in
rates to be subject to refund upon the final determination by the CPUC.

PERFORMANCE-BASED REGULATION (PBR)

On March 28, 2003, SDG&E filed its 2002 Distribution PBR Performance
Report with the CPUC. For 2002, SDG&E exceeded the PBR benchmarks on
five of its six performance indicators, recording a total net reward of
$6 million out of a total possible reward of $14.5 million under the
mechanism. The reward is subject to CPUC approval.

On March 19, 2003, the CPUC's Office of Ratepayer Advocates (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. The ORA recommended the extension of the PBR mechanism, as
modified in Years 8 and 9, to Year 10. The ORA has stated that the
CPUC's adoption of the natural gas procurement PBR mechanism is
beneficial to both ratepayers and shareholders of SDG&E.

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)

On March 18, 2003, a CPUC commissioner issued a scoping memorandum in
SoCalGas' GCIM Year 7 and Year 8 proceedings, delaying decisions on GCIM
Year 7 and Year 8 until certain issues in the Border Price Investigation
are resolved (see above). This makes it unlikely that the anticipated
rewards will be recorded in 2003 earnings. SoCalGas has requested that
the CPUC approve rewards of $30.8 million and $17.4 million for GCIM
Years 7 and 8, respectively.

TRANSMISSION RATE INCREASE

On May 2, 2003, the FERC authorized SDG&E's request for modification of
its Transmission Owner Tariff (TO Tariff) to adopt a rate increase and
recover its costs ($20 million through December 31, 2002) associated
with the Valley-Rainbow transmission project. The new transmission rates
are effective October 1, 2003, and will increase the charges for retail
transmission service by $32.3 million (27 percent). The FERC has not yet
approved the rates or the Valley-Rainbow costs and the new rates are
subject to refund once the rate case is concluded.

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 obliged 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.

In December 2002, a FERC administrative law judge (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 might have overcharged
California). 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, and SET will continue to vigorously avail
itself of its rights before the FERC and the courts.

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 does not believe any additional amounts it may
be required to pay would be material to its 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. In response to the inquiry, Sempra Energy's electricity
trading subsidiaries have denied using any of these strategies. SDG&E
did disclose and explain a single de minimus 100-mW transaction for the
export of electricity out of California. In response to a related FERC
inquiry regarding natural gas trading, the California Utilities have
denied engaging in "wash" or "round trip" trading activities. The
companies are also cooperating with the FERC and other governmental
agencies and officials in their various investigations of the California
energy markets.

On March 26, 2003, the FERC released the staff's final report on the
market manipulation issue. Among other things, the staff recommends that
37 companies, including SDG&E and SET, comment on whether the FERC
should issue a "show cause" order that, if issued, would require them to
establish that their activities did not constitute "gaming" or
"anomalous market behavior" in violation of the ISO and PX tariffs. If
the FERC were to conclude that tariff violations had occurred, it could
order various remedies including recovery of profits and suspension or
termination of market-based trading authority.

In April 2003, the FERC, in response to a request by the CPUC and the
Electricity Oversight Board, scheduled an oral argument before the FERC
on May 15, 2003, relating to the long-term power contract between the
DWR and SER, as well as contracts between the DWR and other power
suppliers. The FERC had previously stated 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. It is not known when the FERC will issue a
decision on the long-term power contracts.

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 $7.2 million.

Both the nuclear liability and property insurance programs include
industry aggregate limits for SONGS losses, including replacement power
costs, resulting from acts of terrorism.

ARGENTINE INVESTMENTS

During the first quarter of 2003, SEI recorded a $24 million credit to
Accumulated Other Comprehensive Income to reflect the increase in the
value of the Argentine peso relative to the U.S. dollar. As of March 31,
2003, SEI had adjusted its investment in its two unconsolidated
Argentine subsidiaries downward by $199 million as a result of the
devaluation of the Argentine peso. 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 and all arbitrators have been selected. The company
is currently engaging outside experts to assist in the preparation and
quantification of the claim. A decision is expected in 2004 or 2005.

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. 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 Corp. 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. The terms of the
settlement remain subject to approval by the relevant state courts and
the FERC. One of the settlement terms provides that El Paso will assist
the plaintiffs in their litigation against the remaining defendants.

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 and the California
Utilities, seeking damages resulting from an alleged conspiracy to drive
up or control natural gas prices, eliminate competition and increase
market volatility.

Various lawsuits, which seek class-action certification, allege that
Sempra Energy and certain company subsidiaries 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.

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 venture 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 August 2003.

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.

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 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. There were no significant changes in segment assets
during the three months ended March 31, 2003.

- -------------------------------------------------------
Three Months Ended
March 31,
----------------------
(Dollars in millions) 2003 2002
- -------------------------------------------------------
Operating Revenues:
Southern California Gas $ 1,008 $ 732
San Diego Gas & Electric 562 427
Sempra Energy Trading 223 206
Sempra Energy Resources 90 23
All other 50 85
Intersegment revenues (10) (3)
----------------------
Total $ 1,923 $ 1,470
- -------------------------------------------------------
Net Income (Loss):
Southern California Gas* $ 58 $ 60
San Diego Gas & Electric* 45 53
Sempra Energy Trading (18) 42
Sempra Energy Resources 10 (3)
All other (7) (6)
----------------------
Total $ 88 $ 146
- -------------------------------------------------------
* after preferred dividends

- --------------------------------------------------------
Balance at
------------------------
March 31, December 31,
2003 2002
- --------------------------------------------------------
Assets:
Southern California Gas $ 4,251 $ 4,079
San Diego Gas & Electric 5,443 5,123
Sempra Energy Trading 6,185 5,614
Sempra Energy Resources 1,405 1,347
All other 2,888 2,580
Intersegment receivable (1,036) (986)
------------------------
Total $19,136 $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," which recognizes all
derivatives as either assets or liabilities on the balance sheet,
measures those instruments at fair value, and recognizes any changes in
the fair value of derivatives in earnings for the period that the change
occurs unless the derivative qualifies as an effective hedge that
offsets certain exposure.

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 by the company
and, in the case of the California Utilities, their customers. As
allowed under SFAS 133, the company has elected to take the normal
purchases and sales exception for certain contracts that are settled by
physical delivery. These contracts are accounted for at historical cost
with gains and losses reflected in the income statement at the contract
settlement date.

SET's and SES' derivative instruments are recorded at fair value 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 unless the contracts meet the requirements for mark-to-
market accounting under SFAS 133.

Except for inventory, and transportation and storage contracts held by
SET and SES, the company's transactions recorded at fair value under
EITF Issue 98-10 are still recorded at fair value based on SFAS 133. On
January 1, 2003, such inventory, and transportation and storage
contracts held by SET and SES at December 31, 2002 were recorded at cost
or the lower of cost or market. As a result, on January 1, 2003, SET and
SES recorded the initial impact of rescinding Issue 98-10 as a
cumulative effect of a change in accounting principle, which reduced
after-tax earnings by $29 million. The effect of EITF 98-10's rescission
further reduced the first quarter 2003 after-tax earnings by $9 million.
Neither of these effects impacted cash flow or liquidity.

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. Payments under the swap
agreement and changes in interest rate (LIBOR) are reflected as
adjustments to long-term debt. The changes in fixed-price contracts and
other derivatives on the consolidated balance sheets for the three
months ended March 31, 2003 were primarily due to 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 three months ended March 31, 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 $1.2 billion in 2003 from $878 million
in 2002, and the cost of natural gas distributed increased to $677
million in 2003 from $424 million in 2002. These changes were primarily
attributable to natural gas cost increases, which are passed on to
customers, partially offset by reduced volumes.

Under the current regulatory framework, changes in core-market natural
gas prices (natural gas purchased for customers that are primarily
residential and small commercial and industrial customers without
alternative fuel capability) or consumption levels do not affect net
income, since core customer rates generally recover the actual cost of
natural gas on a substantially concurrent basis and consumption levels
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 gas
against a benchmark price comprised of monthly gas indices, resulting in
shareholder rewards for costs achieved below the benchmark and
shareholder penalties when costs exceed the benchmark.

Electric revenues increased to $395 million in 2003 from $278 million in
2002, and the cost of electric fuel and purchased power increased to
$163 million in 2003 from $61 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, and changes in electric commodity costs and the
increases in authorized revenue to recover increases in sales volumes.
Under the current regulatory framework, changes in commodity costs
normally do not affect net income. The commodity costs associated with
the DWR's purchases and the corresponding sale to SDG&E's customers are
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 three months ended March 31, 2003 and 2002.

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

Electric Distribution and Transmission
(Volumes in millions of kWhs, 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 consists primarily of revenues from
Global, increased to $366 million in 2003 from $314 million in 2002.
This change was primarily due to higher revenues from SER, which
resulted mainly from sales of electricity to the DWR that occurred from
June 2001 through September 2001, and recommenced in April 2002.

Other Cost of Sales

Other cost of sales, which consists primarily of cost of sales at
Global, increased to $219 million in 2003 from $132 million in 2002,
primarily due to the increased sales as noted above for SER, and higher
storage and transportation charges for SET.

Other Operating Expenses

Other operating expenses increased to $445 million in 2003 from $410
million in 2002. Of the total balance, $318 million and $276 million in
2003 and 2002, respectively, represent other operating expenses at the
California Utilities. The change was primarily due to increased
operating expenses at SDG&E.

Other Income (Loss) - Net

Other income, which primarily consists of equity earnings from
unconsolidated subsidiaries and interest on regulatory balancing
accounts, decreased to a net expense of $5 million in 2003 from net
income of $19 million in 2002. The decrease was primarily due to SEI's
foreign exchange losses, compared to its foreign exchange gains in the
prior year period.

Income Taxes

Income tax expense decreased to $24 million in 2003 from $59 million in
2002. The effective income tax rate decreased to 17 percent in 2003 from
29 percent in 2002. The change was primarily due to reduced pretax
income and increased income tax credits from synthetic fuel investments.
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 March 31, 2003, the amount of these
unused tax credits was $159 million. In addition, at March 31, 2003, the
company has $32 million of alternative minimum tax credits with no
expiration date.

Net Income

Net income decreased to $88 million, or $0.42 per diluted share of
common stock, in 2003 from $146 million, or $0.71 per diluted share in
2002. Excluding the effects of the cumulative effect of the change in
accounting principle ($0.14 per diluted share, discussed in Note 2 of
the notes to Consolidated Financial Statements), the change in net
income in 2003 was primarily due to lower income from SET, partially
offset by improved results at SER.

Net Income by Business Unit

Three months ended March 31
- ---------------------------------------------------------------
Dollars in millions 2003 2002
- ---------------------------------------------------------------
California Utilities
Southern California Gas Company $ 58 $ 60
San Diego Gas & Electric 45 53
------ ------
Total Utilities 103 113

Global Enterprises
Sempra Energy Trading (18)* 42
Sempra Energy Resources 10 (3)
Sempra Energy International 7 8
Sempra Energy Solutions (1) 1
------ ------
Total Global Enterprises (2) 48

Sempra Energy Financial 11 7

Parent and other (24) (22)
------ ------
Consolidated $ 88 $ 146
====== ======

* For purposes of comparison with the corresponding 2002 quarter, this
amount would have been net income of $19 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 $9 million related to operations in the three months ended
March 31, 2003.
- ---------------------------------------------------------------

SOUTHERN CALIFORNIA GAS COMPANY

Net income for SoCalGas decreased to $58 million in 2003 compared to $60
million in 2002, primarily due to the end of sharing of the merger
savings (discussed in the Annual Report) partially offset by increased
margins and other factors.

SAN DIEGO GAS & ELECTRIC

Net income for SDG&E decreased to $45 million in 2003 compared to $53
million in 2002, primarily due to the end of sharing of the merger
savings and increased depreciation and operating expenses, partially
offset by a $6.7 million (pretax) natural gas procurement PBR reward.

SEMPRA ENERGY TRADING

SET recorded a net loss of $18 million in 2003 compared to income of $42
million in 2002. The change was primarily due to the change in
accounting principle of $37 million recorded during 2003, including $28
million reported as a cumulative effect adjustment, and reduced
profitability in the natural gas and power product lines, partially
offset by increased synthetic-fuel tax credits. Although volatility in
SET's markets was high, which generally has a favorable effect on SET's
results, the unusual market uncertainties during the three months ended
March 31, 2003 adversely affected SET's profitability.

A summary of SET's unrealized revenues for trading activities for the
three-month periods ending March 31, 2003 and 2002 (dollars in millions)
follows:

2003 2002
- -----------------------------------------------------------------
Balance at December 31 $ 180 $ 405
Cumulative effect adjustment (48) --
Additions 299 139
Realized 11 73
------------------------------------
Balance at March 31 $ 442 $ 617
====================================

The estimated fair values for SET's trading activities as of March 31,
2003, and the periods during which 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.

March 31, December 31,
(Dollars in millions) 2003 2002
- -------------------------------------------------------------------
Counterparty credit quality*
Commodity Exchanges $ 114 $ 49
AAA 26 69
AA 269 194
A 258 316
BBB 436 559
Below investment grade 491 504
---------------------------
Total $1,594 $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 $10 million in 2003 compared to a loss of $3
million in 2002. The change was primarily due to sales to the DWR that
recommenced in April 2002 under its long-term contract.

SEMPRA ENERGY SOLUTIONS

SES recorded a loss of $1 million in 2003 compared to income of $1
million in 2002. The decrease was primarily due to the $1 million
cumulative effect of the change in accounting principle recorded during
the first quarter of 2003.

In delivering electric and natural gas supplies to its commercial and
industrial customers, SES hedges its price exposure through the use of
exchange-traded and over-the-counter financial instruments.

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. Whether SEF will
invest in additional properties will depend on Sempra Energy's income
tax position.

SEF recorded net income of $11 million and $7 million for the three
months ended March 31, 2003 and 2002, respectively. The change was due
primarily to increased tax benefits resulting from increased synthetic
fuel production.

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 their 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 March 31, 2003, the company had $803 million in cash and $2.3 billion
in unused, committed lines of credit available, of which $498 million
was supporting commercial paper and variable-rate debt.

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 cash to or requires cash from Sempra Energy 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 Sempra Energy cash also varies with its
level of borrowing from its own sources. SET's borrowings from the
company were $260 million at March 31, 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.
Such monitoring includes the procedures discussed in "Market Risk"
below.

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 to continue the expansion of its
existing natural gas distribution operations in Mexico and its planned
development of liquefied natural gas (LNG) facilities. 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 $644 million and $177
million for the three months ended March 31, 2003 and 2002,
respectively. The increase in cash flows from operations was
attributable to the higher realization in net trading assets in 2003 and
greater compensation costs paid in the first quarter of 2002.

CASH FLOWS FROM INVESTING ACTIVITIES

Net cash used in investing activities totaled $272 million and $287
million for the three months ended March 31, 2003 and 2002,
respectively. The change in cash flows from investing activities was
attributable to lower capital expenditures, partially offset by SEI's
purchase of the third-party interests in its Mexican investments and
SER's required collateralization used to secure project funding made
under the synthetic lease agreement.

Capital expenditures and investments for the three months ended March
31, 2003, include SER's costs related primarily to the 1,250-megawatt
Mesquite Power Plant near Phoenix, Arizona (expected to commence
operations at 50-percent capacity in June 2003 and at full capacity in
December 2003); the 600-megawatt Termoelectrica de Mexicali power plant
near Mexicali, Mexico (commercial operation is scheduled for summer
2003); and the 570-megawatt Elk Hills power plant (a 50/50 joint venture
being developed with Occidental Energy Ventures Corporation) near
Bakersfield, California, which is anticipated to be completed in June
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 business 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 of
SEI, 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. The total cost of the project is expected to
be about $700 million. The project could begin commercial operations as
early as 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 2006.

CASH FLOWS FROM FINANCING ACTIVITIES

Net cash (used in) provided by financing activities totaled $(24)
million and $245 million for the three months ended March 31, 2003 and
2002, respectively. The change in cash flows from financing activities
was attributable to the 2002 increase in commercial paper and long-term
debt, whereas proceeds from the January 2003 issuance of long-term notes
of $400 million was used to repay other long-term debt and commercial
paper.

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. The remaining $5 million
matures on January 18, 2028. In March 2003, SER repaid $100 million
outstanding under a line of credit. In addition, during the three months
ended March 31, 2003, Sempra Energy Financial repaid $35 million of debt
incurred to acquire limited partnerships and SDG&E repaid $17 million of
rate-reduction bonds.

Dividends paid on common stock amounted to $52 million and $51 million
for the three-month periods ended March 31, 2003 and 2002, respectively.

On April 7, 2003, SoCalGas called its $100 million 7.375% first-mortgage
bonds at a premium of 3.53 percent.

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%, 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.

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
volatility 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.

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.

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 is
preparing a request for proposals to meet the electric capacity
shortfall, estimated at 69 megawatts in 2005. In addition, SDG&E is
ahead of the interim schedule in meeting the requirement of obtaining 20
percent of its electricity from renewable sources by 2017.

The power crisis of 2000-2001 has caused the California Public Utilities
Commission (CPUC) to adjust its plan for deregulation of electricity. In
addition, several California state agencies, including the CPUC, the
Consumer Power and Conservation Financing Authority, and the Energy
Resources Conservation and Development Commission, recently issued a
draft 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.

The CPUC has undertaken a proceeding and issued several decisions
establishing the framework, rules and processes that governed SDG&E's
return to the responsibility of procuring electricity for its customers.
These include decisions (1) allocating to California's investor-owned
utilities (IOUs) the power from the long-term contracts entered into by
the California Department of Water Resources (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) adopting 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 a procurement incentive mechanism.

See additional discussion of this and related topics in Note 3 of the
notes to Consolidated Financial Statements.

Natural Gas Restructuring and Gas 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 is required to file this new
application by June 30, 2003, but has filed a petition for modification
requesting the CPUC defer the filing of this application until October
15, 2003. If the December 2001 decision is implemented, it is not
expected to adversely affect the California Utilities' earnings.

Cost of Service

Although the California Utilities requested that a decision in their
Cost of Service applications be effective January 1, 2004, the CPUC
commissioner assigned to the applications has adopted a procedural
schedule that would prevent the CPUC from issuing a decision before the
second quarter of 2004. The California Utilities have filed a motion
seeking reconsideration of this ruling. The motion also seeks
authorization to implement an interim rate increase on January 1, 2004
to reflect an anticipated cost of service decision with any increase in
rates to be subject to refund upon the final determination by the CPUC.

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 570-megawatt Elk
Hills power project, 50 percent owned by SER and located near
Bakersfield, California, is expected to begin commercial operations in
June 2003. The 1,250-megawatt Mesquite Power Plant near Phoenix,
Arizona, is expected to commence commercial operations at 50-percent
capacity in June 2003 and at full capacity in December 2003.
Termoelectrica de Mexicali, a 600-megawatt power plant near Mexicali,
Baja California, Mexico, is expected to commence commercial operations
in the summer of 2003. The 305-megawatt Twin Oaks Power Plant located
near Bremond, Texas, was acquired in October 2002. El Dorado Energy, a
440-megawatt power plant near Las Vegas, Nevada, jointly owned by SER
and Reliant Energy, 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 are Sempra Metals Limited, Sempra Metals &
Concentrates Corp., Henry Bath & Sons Limited and Henry Bath, Inc. In
addition, SER acquired the coal-fired Twin Oaks Power Plant during 2002.

SEI is in the process of developing Energia Costa Azul, an LNG receiving
terminal in Baja California, Mexico, expected to commence commercial
operations in 2006. In April 2003, Sempra Energy LNG Corp. acquired the
proposed Hackberry, La. LNG project, to be renamed Cameron LNG, which
could begin commercial operations as early as 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 and all
arbitrators have been selected. The company is currently engaging
outside experts to assist in the preparation and quantification of the
claim. A decision is expected in 2004 or 2005.

NEW ACCOUNTING STANDARDS

New pronouncements that have recently become effective or that are yet
to be effective are SFAS 142, 143 and 148, Interpretations 45 and 46,
EITF 02-3, and the rescission of EITF 98-10. SFAS 142 affects net income
by replacing the amortization of goodwill with periodic reviews thereof
for impairment with charges against income when impairment is found.
SFAS 143 requires accounting and disclosure changes concerning legal
obligations related to future asset retirements. SFAS 148 amends SFAS
123 and adds two additional transition methods to the fair value method
of accounting for stock-based compensation. Interpretation 45 clarifies
that a guarantor is required to recognize a liability for the fair value
of obligations undertaken in issuing guarantees. Interpretation 46
addresses consolidation by business enterprises of variable-interest
entities (previously referred to as "special-purpose entities" in most
cases). 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 these items, even though no economic loss exists.

For SET, its first quarter 2003 earnings of $19 million was negatively
impacted by $37 million, including the cumulative effect adjustment of
$28 million, to reflect the rescission of Issue 98-10. SES's first
quarter 2003 breakeven results were negatively impacted by the
cumulative effect adjustment of $1 million to reflect the rescission of
Issue 98-10.

EITF Issue 02-3, "Issues Involved in Accounting for Derivative Contracts
Held for Trading Purposes and Contracts Involved in Energy Trading and
Risk Management Activities": In June 2002, EITF Issue 02-3, codified and
reconciled existing guidance on the recognition and reporting of gains
and losses on energy trading contracts and addressed other aspects of
the accounting for contracts involved in energy trading and risk
management activities. Among other things, the consensus required SES to
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.

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 has adopted SFAS 143 beginning January 1, 2003. See further
discussion in Note 2 of the notes to Consolidated Financial Statements.

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 March 31, 2003, and the average VaR for the three
months ended March 31, 2003, at the 95-percent and 99-percent confidence
intervals (one-day holding period) were as follows (in millions of
dollars):

95% 99%
------ ------
At March 31, 2003 $ 7.3 $10.3
Average for the three months ended 3/31/03 $10.0 $14.1

As of March 31, 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 companies' 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 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

Exhibit 12 - Computation of ratios

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

99.1 Statements of Registrant's Chief Executive Officer and Chief
Financial Officer pursuant to 18 U.S.C. Sec. 1350, as created by
Section 906 of the Sarbanes-Oxley Act of 2002.

(b) Reports on Form 8-K

The following reports on Form 8-K were filed after December 31, 2002:

Current Report on Form 8-K filed February 21, 2003, filing as an exhibit
Sempra Energy's press release of February 20, 2003, giving the financial
results for the three months ended December 31, 2002.

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.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly cause this report to be signed on its behalf by the
undersigned thereunto duly authorized.

SEMPRA ENERGY
-------------------
(Registrant)

Date: May 5, 2003 By: /s/ F. H. Ault
----------------------------
F. H. Ault
Sr. Vice President and Controller

CERTIFICATIONS

I, Stephen L. Baum, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Sempra Energy;

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

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

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this Quarterly Report is being
prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
Quarterly Report (the "Evaluation Date"); and

c) presented in this Quarterly Report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors
and the audit committee
of registrant's board of directors (or persons performing the equivalent
function):

a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal
controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
Quarterly Report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

May 5, 2003

/S/ STEPHEN L. BAUM
Stephen L. Baum
Chief Executive Officer

I, Neal E. Schmale, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Sempra Energy;

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

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

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:

a) designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this Quarterly Report is being
prepared;

b) evaluated the effectiveness of the registrant's disclosure controls and
procedures as of a date within 90 days prior to the filing date of this
Quarterly Report (the "Evaluation Date"); and

c) presented in this Quarterly Report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons performing
the equivalent function):

a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified
for the registrant's auditors any material weaknesses in internal
controls; and

b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
Quarterly Report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

May 5, 2003

/S/ NEAL E. SCHMALE
Neal E. Schmale
Chief Financial Officer

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