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 September 30, 2002
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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
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(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
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Common stock outstanding on October 31, 2002: 204,862,909
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ITEM 1. FINANCIAL STATEMENTS.

SEMPRA ENERGY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
Dollars in millions except per-share amounts

SEMPRA ENERGY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
Dollars in millions except per-share amounts

SEMPRA ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Dollars in millions

SEMPRA ENERGY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Dollars in millions

SEMPRA ENERGY AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
Dollars in millions

SEMPRA ENERGY AND SUBSIDIARIES
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 as
the California utilities), Sempra Energy Trading (SET), Sempra Energy
Resources (SER), Sempra Energy International (SEI), Sempra Energy
Solutions (SES) and Sempra Energy Financial (SEF). 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 company's Annual Report on Form 10-K for the year
ended December 31, 2001 (Annual Report) and Quarterly Reports on Form
10-Q for the three months ended March 31, 2002 and the three months
ended June 30, 2002.

The company's significant accounting policies are described in Note 2 of
the notes to Consolidated Financial Statements in the company's Annual
Report. The same accounting policies are followed for interim reporting
purposes.

As described in the notes to Consolidated Financial Statements in the
company's 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).

EARNINGS PER SHARE

Diluted net income per share of common stock is less than basic net
income per share of common stock due solely to the dilutive effect of
in-the-money common stock options.

BOND OFFERING

In October 2002, SoCalGas publicly offered and sold $250 million of
4.80-percent First Mortgage Bonds, maturing on October 1, 2012. The
bonds are not subject to a sinking fund and are not redeemable prior to
maturity except through a make-whole mechanism. Proceeds from the bond
sale have become part of the company's general treasury funds to
replenish amounts previously expended to refund and retire indebtedness
and will be used for working capital and other general corporate
purposes. These bonds were assigned ratings of A+ by the Standard &
Poor's rating agency, A1 by Moody's Investors Service, Inc., and AA by
Fitch, Inc.

EQUITY UNITS

During the second quarter of 2002, the company sold $600 million of
"Equity Units." Each unit consists of $25 principal amount of the
company's 5.60% senior notes due May 17, 2007 and a contract to purchase
for $25 on May 17, 2005, between .8190 and .9992 of a share of the
company's common stock (to be determined by the then-prevailing market
prices). The net proceeds of the sale were used primarily to repay a
portion of the company's short-term debt, including debt used to finance
the capital expenditure program for Sempra Energy Global Enterprises,
the holding company for most of the company's principal subsidiaries
other than the California utilities. The Equity Units are recorded as
long-term debt in the Consolidated Balance Sheets.

NEW ACCOUNTING STANDARDS

In July 2001, the Financial Accounting Standards Board (FASB) issued two
statements, SFAS 142 "Goodwill and Other Intangible Assets" and SFAS 143
"Accounting for Asset Retirement Obligations."

SFAS 142 provides guidance on how to account for goodwill and other
intangible assets after an acquisition is complete, and is effective for
fiscal years that start after December 15, 2001. SFAS 142 calls for
amortization of goodwill to cease and requires goodwill and certain
other intangibles to be tested for impairment at least annually.
Amortization of goodwill, including the company's share of amounts
recorded by unconsolidated subsidiaries, was $7 million and $18 million
for the three and nine months ended September 30, 2001, respectively. In
accordance with the transitional guidance of SFAS 142, recorded goodwill
attributable to the company was tested for impairment by comparing the
fair value to its carrying value. Fair value was determined using a
discounted cash flow methodology. 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.

Had the company been accounting for its goodwill under SFAS 142 for all
periods presented, the company's net income and earnings per share would
have been as follows (dollars in millions, except for per share
amounts):

Three Months Ended
September 30,
2002 2001
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Reported net income $ 150 $ 96
Add: goodwill amortization,
net of tax 4
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Pro forma adjusted net income $ 150 $ 100
=====================

Reported basic earnings
per share $0.73 $0.47
Add: goodwill amortization,
net of tax .02
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Pro forma adjusted basic
earnings per share $0.73 $0.49
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Reported diluted earnings
per share $0.73 $0.46
Add: goodwill amortization,
net of tax .02
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Pro forma adjusted diluted
earnings per share $0.73 $0.48
=====================

Nine Months Ended
September 30,
2002 2001
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Reported net income $ 443 $ 410
Add: goodwill amortization,
net of tax 11
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Pro forma adjusted net income $ 443 $ 421
=====================

Reported basic earnings
per share $2.16 $2.02
Add: goodwill amortization,
net of tax .05
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Pro forma adjusted basic
earnings per share $2.16 $2.07
=====================

Reported diluted earnings
per share $2.15 $2.00
Add: goodwill amortization,
net of tax .05
---------------------
Pro forma adjusted diluted
earnings per share $2.15 $2.05
=====================

Included in the Consolidated Balance Sheets at September 30, 2002 and
December 31, 2001 were $181 million and $173 million, respectively, of
unamortized goodwill related to consolidated subsidiaries, primarily SET
(included in sundry assets) and $331 million and $319 million, before
foreign currency translation adjustments ($222 million and $248 million,
including foreign currency translation adjustments) respectively, of
unamortized goodwill related to unconsolidated subsidiaries, primarily
those located in South America (included in investments). Unamortized
other intangible assets were not material at September 30, 2002 and
December 31, 2001.

SFAS 143 addresses financial accounting and reporting for obligations
associated with the retirement of tangible long-lived assets and the
associated asset retirement costs. It applies to legal obligations
associated with the retirement of long-lived assets and requires
entities to record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred. When the liability is
initially recorded, the entity increases the carrying amount of the
related long-lived asset to reflect the future retirement cost. Over
time, the liability is accreted to its present value and paid. The
capitalized cost is depreciated over the useful life of the related
asset. SFAS 143 is effective for the company beginning in 2003.

Upon adoption of SFAS 143, the company estimates that it would record an
addition of $100 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
date the various units began operation), and a corresponding retirement
obligation liability of $350 million (which includes accretion of that
discounted value to December 31, 2002). The nuclear decommissioning
trusts' balance of $498 million at September 30, 2002 represents amounts
collected for future decommissioning costs and earnings thereon, and has
a corresponding offset in accumulated depreciation ($356 million related
to SONGS Units 2 and 3) and deferred credits ($142 million related to
SONGS Unit 1). That total amount would be reduced by $450 million, based
on the $100 million depreciable base. The difference between the various
amounts will be recorded as a regulatory liability of $200 million to
reflect that SDG&E has collected the funds more quickly than SFAS 143
would accrete the retirement liability and depreciate the asset. Except
for SONGS, the company has not yet determined the effect of SFAS 143 on
its financial statements.

In August 2001, the FASB issued SFAS 144 "Accounting for the Impairment
or Disposal of Long-Lived Assets" that replaces SFAS 121, "Accounting
for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of." SFAS 144 governs the determination of whether the carrying
value of certain assets, primarily property, plant and equipment, should
be reduced. SFAS 145, "Rescission of FASB Statements No. 4, 44 and 64,
Amendment of FASB Statement No. 13 and Technical Corrections", was
issued in April 2002 and will be effective for the company on January 1,
2003. In June, 2002, the FASB issued SFAS 146 "Accounting for Costs
Associated with Exit or Disposal Activities" which nullifies EITF Issue
94-3 "Liability Recognition for Certain Employee Termination Benefits
and Other Costs to Exit an Activity," and is effective for exit or
disposal activities that are initiated after December 31, 2002. Adoption
of these statements will not have a material impact on the company's
financial statements.

In June 2002, a consensus was reached in Emerging Issues Task Force
(EITF) Issue 02-3 "Issues Related to Accounting for Contracts Involved
in Energy Trading and Risk Management Activities," which codifies and
reconciles existing guidance on the recognition and reporting of gains
and losses on energy trading contracts and addresses other aspects of
the accounting for contracts involved in energy trading and risk
management activities. Among other things, the consensus requires that
mark-to-market gains and losses on energy trading contracts should be
shown net 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. All
other Sempra Energy subsidiaries were already recording trading
activities net and required no change. The required reclassifications
will have no impact on previously recorded gross margin, net income, or
cash provided by operating activities.

In October 2002, the EITF reached a consensus to rescind Issue 98-10,
the basis for mark-to-market accounting used for recording energy-
trading activities by many companies, including SET and SES. The new
ruling requires that all new energy-related contracts entered into
subsequent to October 25, 2002 should not be accounted pursuant to Issue
98-10. Instead, those contracts should be accounted for under accrual
accounting and would not qualify for mark-to-market accounting unless
the contracts meet the requirements stated under SFAS 133 "Accounting
for Derivative Instruments and Hedging Activities." The effective date
for the full rescission of Issue 98-10 will be for fiscal periods
beginning after December 15, 2002. The effect of rescinding Issue 98-10
will be reported as a cumulative effect of a change in accounting
principle in accordance with Accounting Principles Board Opinion 20 on
January 1, 2003. The company has not yet determined the impact of this
change on the Consolidated Financial Statements, but preliminarily
believes that the majority of the revenue recorded under mark-to-market
accounting based on EITF 98-10 will still be recorded under mark-to-
market accounting based on SFAS 133.

2. MATERIAL CONTINGENCIES

ELECTRIC INDUSTRY RESTRUCTURING

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 company's Annual Report.
Subsequent developments are described herein.

SDG&E's AB 265 undercollection balance has been reduced from $392
million at December 31, 2001, to $270 million at September 30, 2002.
SDG&E has filed an application with the California Public Utilities
Commission (CPUC) for a rate surcharge to expedite recovery of this
undercollection. However, even at current rates and allocation of those
rates between the California Department of Water Resources (DWR) and
SDG&E, the balance is expected to be completely recovered by mid 2005.
Also at issue is the ownership of certain power sale profits. As
previously discussed in Note 14 of the notes to Consolidated Financial
Statements in the Annual Report, the CPUC rejected portions of a
memorandum of understanding with respect to a settlement of regulatory
issues related to electricity contracts held by SDG&E. A proposed
settlement would have granted SDG&E ownership of its power sale profits
in exchange for crediting $219 million to customers to offset a portion
of the rate-ceiling balancing account. Instead, the CPUC asserted that
all the profits associated with the contracts (which the CPUC estimated
to be $363 million) should accrue to the benefit of customers. The
company believes the CPUC's calculation of these profits is incorrect.
Moreover, the company believes that all profits associated with the
contracts properly are for the benefit of SDG&E shareholders rather than
customers. Accordingly, SDG&E has challenged the CPUC's disallowance of
profits from the contracts in both the California Court of Appeals and
in Federal District Court.

These court proceedings have been held in abeyance pending the CPUC's
consideration of another proposed settlement, which was negotiated with
the CPUC legal division in June 2002. The settlement, if approved by the
CPUC, would dispose of all issues relating to the contracts by
allocating an additional $24 million of power sale profits to customers
by a reduction of the rate-ceiling balancing account. The settlement, if
approved, would not adversely affect SDG&E's financial position,
liquidity or results of operations. A proposed CPUC decision issued in
September 2002 would reject the settlement, deny SDG&E's request for a
surcharge, and require SDG&E to reduce its AB 265 undercollection by
$130 million to reflect profits from the intermediate-term contracts
from June 2000 through January 2001. An alternate proposed decision
issued in October 2002 would essentially adopt the June 2002 settlement.
Final resolution of this matter is expected by the end of 2002. If the
settlement is not approved, SDG&E intends to proceed with its previously
instituted litigation seeking the allocation of all power sale profits
to shareholders.

On March 21, 2002, the CPUC affirmed its decision prohibiting new direct
access (DA) contracts after September 20, 2001, but rejected a proposal
to make the prohibition retroactive to July 1, 2001. Contracts in place
as of September 20, 2001 may be renewed or assigned to new parties. On
November 7, 2002, the CPUC issued a decision adopting DA exit fees with
a cap of 2.7 cents per kWh. This decision will have no effect on SDG&E's
cash flows or results of operations because any shortfall due to the cap
on the exit fees will be funded by bundled customers in current rates.

On April 4, 2002, the CPUC approved a plan that determines how much
ratepayer revenue the state's investor-owned utilities (IOUs) can
collect in 2002 for utility-retained generation. SDG&E continues to
collect the system average rate of 7.96 cents/kWh for commodity costs
(the 6.5-cent commodity rate ceiling, plus an amount sufficient to repay
the DWR for its purchases of power for utility customers). SDG&E also
collects a 0.7-cent/kWh competition transition charge (CTC). The excess,
if any, of the system average rate and CTC rate over actual costs is
used to reduce the AB 265 undercollection balance described above.

Operating costs of SONGS Units 2 and 3, including nuclear fuel and
related financing costs, and incremental capital expenditures are
recovered through a performance incentive pricing plan (ICIP) 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 and, for the nine-month period ended September
30, 2002, ICIP contributed $37 million to SDG&E's net income. The CPUC
has rejected an administrative law judge's proposed decision to end ICIP
prior to its December 31, 2003 scheduled expiration date. However, the
CPUC has also 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. SDG&E
has applied for a rehearing of this decision as contrary to market-based
pricing contemplated by the overall SONGS ratemaking mechanism adopted
by the CPUC in establishing ICIP in 1996. If SDG&E were to be granted
market-based rates, SDG&E believes the impact of the end of ICIP would
be somewhat reduced.

Since early 2001, the DWR has procured power for each of the California
IOUs and the CPUC has established the allocation of the power and the
related cost responsibility among the IOUs for that power. SDG&E's
allocation results in its overall rates being comparable to those of the
other two California electric IOUs, Southern California Edison (Edison)
and Pacific Gas and Electric (PG&E).

The CPUC intends for the utilities to take the procurement function back
from DWR by the beginning of 2003. On September 19, 2002, the CPUC
issued a decision on how the power from the long-term contracts signed
by DWR should be allocated to the customers of each of the utilities for
purposes of determining the amount of additional power each utility will
be required to procure in 2003 and thereafter to fill out its resource
needs. The reasonableness of the IOUs' administration and dispatch of
the allocated contracts will be reviewed by the CPUC in an annual
proceeding. Assembly Bill 57 (AB 57), signed by California Governor
Davis on September 24, 2002, requires the CPUC to make this
determination, and to establish procedures that will allow utilities to
recover their electric procurement costs in a timely fashion without the
need for retrospective reasonableness reviews. SDG&E believes that a
return to the procurement function in accordance with AB 57 would have
no adverse impact on its financial position or results of operations.

On August 22, 2002, the CPUC issued a decision authorizing California's
IOUs to begin buying power to cover their net short energy requirements
starting on January 1, 2003. The net short is the difference between the
amount of electricity needed to cover a utility's customer demand and
the power provided by owned generation and existing contracts, including
the long-term power contracts allocated to the customers of each IOU by
the DWR (see above). The IOUs are authorized to enter into contracts of
up to five years for power from traditional sources, and up to 15 years
for power from renewable sources. Based upon the DWR's allocation, SDG&E
will be required to purchase approximately 10 percent of its customer
requirements in 2003.

On October 24, 2002, the CPUC issued a decision in the Electric
Procurement proceeding that directs the resumption of the electric
commodity procurement function by IOUs by January 1, 2003, and begins
the implementation of recent legislation regarding procurement and
renewables portfolio standard addressed in AB 57 and SB 1078. The
decision establishes a process for review and approval of the utilities'
updated 2003 procurement plans before January 1, 2003, and long-term
(20-year) procurement plans during 2003. The CPUC has authorized the
utilities to use derivatives to manage procurement risk and to acquire a
variety of resource types including utility ownership, conventional
generation, distributed generation, self generation, demand side
resources, transmission and renewables. A renewables portfolio standard
is adopted, requiring an additional one percent of energy sales each
year to be supplied by renewable sources. A semiannual cost review and
rate revision mechanism is established, and a trigger is established for
more frequent changes if balances exceed four percent of annual, non-DWR
generation revenues, to provide for timely recovery of any
undercollections. The decision expresses interest in an approach to an
incentive mechanism that rewards or penalizes utilities relative to
their performance against a benchmark.

The CPUC has placed a moratorium on the IOUs' purchasing electricity
from their affiliates for either two years or until the CPUC completes a
rulemaking on this matter.

The State of California has commenced the sale of $11.95 billion in
revenue bonds, the proceeds of which are needed to repay monies the
state borrowed from its general fund and other short-term lenders to
purchase electricity for its residents during the energy crisis of 2001
and 2002. The bonds include a variety of variable-rate and fixed-rate
instruments with maturity dates of up to 20 years. Sale of the bonds is
expected to close in November 2002. A CPUC decision issued in October
2002 implements a separate bond charge to be passed on to the IOUs'
customers. Due to SDG&E's billable rates being limited by the CPUC, the
decision potentially could result in a revenue shortfall that would be
recorded in a balancing account until disposition in the DWR Revenue
Requirements Phase of this proceeding.

GAS INDUSTRY RESTRUCTURING

As discussed in Note 15 of the notes to Consolidated Financial
Statements in the Annual Report, in December 2001 the CPUC issued a
decision related to gas industry restructuring, with implementation
anticipated during 2002. However, implementation has been delayed and
the CPUC has ordered additional hearings.

CPUC INVESTIGATION OF ENERGY-UTILITY HOLDING COMPANIES

In January 2002, the CPUC issued a decision that broadly determined that
a holding company would be required to provide cash to a utility
subsidiary to cover its operating expenses and working capital to the
extent they are not adequately funded through retail rates. Also in
January 2002, the CPUC ruled that it had jurisdiction to create the
holding company system and, therefore, retains jurisdiction to enforce
conditions to which the holding companies had agreed. The company filed
a request for rehearing on the issues, which the CPUC denied on July 17,
2002. The company is seeking judicial review of the orders in the
California Court of Appeals. The company filed its appeal on August 19,
2002.

NUCLEAR INSURANCE

SDG&E and the other co-owners of SONGS have purchased primary insurance
of $200 million, the maximum amount available, for public-liability
claims. An additional $9.25 billion of coverage is provided by secondary
financial protection required by the Nuclear Regulatory Commission and
provides for loss sharing among utilities owning nuclear reactors if a
costly accident occurs. SDG&E and the other co-owners of SONGS could be
assessed retrospective premium adjustments of up to $176 million
(SDG&E's share is $36 million unless default occurs by any other co-
owner) in the event of a nuclear incident involving any of the licensed,
commercial reactors in the United States, if the amount of the loss
exceeds $200 million. In the event the public-liability limit stated
above is insufficient, the Price-Anderson Act provides for Congress to
enact further revenue-raising measures to pay claims, which could
include an additional assessment on all licensed reactor operators.

Insurance coverage is provided for up to $2.75 billion of property
damage and decontamination liability. This coverage also provides
indemnity payments of $3.5 million per week, for up to 52 weeks, and
then $2.8 million per week, for up to 110 weeks, for the cost of
replacement power. There is a waiting period of 12 weeks. Coverage is
provided through a mutual insurance company owned by utilities with
nuclear facilities. If losses at any of the nuclear facilities covered
by the risk-sharing arrangements were to exceed the accumulated funds
available from these insurance programs, SDG&E could be assessed
retrospective premium adjustments of up to $7.4 million.

Both the public-liability and property insurance include coverage for
SDG&E's and the other co-owners' losses resulting from acts of
terrorism.

LITIGATION

SER is a defendant in an action brought by the CPUC and the California
Electricity Oversight Board at the Federal Energy Regulatory Commission
(FERC) alleging that, because of the dysfunctional energy market in
California, the long-term power contracts entered into by the DWR should
be revised or set aside as being unjust and unreasonable. On April 24,
2002, the FERC ordered hearings on the complaints. The order requires
the complainants to satisfy a "heavy" burden of proof to support a
revision of the contracts, and cited the FERC's long-standing policy to
recognize the sanctity of contracts, from which it has deviated only in
"extreme circumstances." Hearings will begin in December 2002 under the
supervision of a FERC administrative law judge (ALJ). Settlement
negotiations are continuing. A decision from the ALJ is expected in
February 2003. The FERC expects to issue a final decision by May 2003.
Additional information regarding the contract between SER and the DWR is
included under "Sempra Energy Resources" in "Management's Discussion and
Analysis of Financial Condition and Results of Operations."

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, sought to maintain their positions in the natural gas
market by agreeing, among other things, to restrict the supply of
natural gas into Southern California. On October 16, 2002, the assigned
San Diego Superior Court judge ruled that the case can proceed with
discovery and that the California courts, rather than the FERC, have
jurisdiction in the case. This was a preliminary ruling and not a ruling
on the merits or facts of the case. The northern California cases which
only name El Paso as a defendant are scheduled for trial in September
2003 and the remainder of the cases are set for trial in January
2004. According to published reports, the Nevada Attorney General filed
a similar lawsuit in Nevada in November 2002.

Various 2000 lawsuits, which seek class-action certification, allege
that certain company subsidiaries unlawfully manipulated the electric-
energy market. These lawsuits were consolidated in San Diego Superior
Court, by order of the Judicial Council, but have recently been removed
to Federal Court where motions to remand are pending. Similar,
subsequent lawsuits are expected to be consolidated with the existing
matters in San Diego.

SER is a defendant in an action brought by Occidental Energy Ventures
(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 power to the DWR under the contract from Elk
Hills. The court has ordered that the agreement requires the matter be
arbitrated in accordance with the agreement.

SER, SET and SDG&E, along with all other sellers in the western power
market, have been named defendants in a complaint filed at the FERC by
the California Attorney General's office seeking refunds for electricity
purchases based on alleged violations of FERC tariffs. The FERC has
dismissed the complaint. The California Attorney General's office
requested a rehearing, which the FERC denied. The California Attorney
General has filed an appeal in the 9th Circuit.

Management believes the above allegations are without merit.

In connection with its investigation into California energy prices, in
May 2002 the FERC ordered all energy companies engaged in electric
energy trading activities to state whether they had engaged in "death
star," "load shift," "wheel out," "ricochet," "inc-ing load" and various
other specific trading activities as described in memos prepared by
attorneys retained by Enron Corporation and in which it was asserted
that Enron was 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, SDG&E and SoCalGas have also
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.

In October 2002, the FERC also requested the largest North American
natural gas marketers in 2001 to submit information regarding natural
gas trading data provided by these marketers to energy trade
publications in 2000 and 2001. During this period individual employees
at SET received unsolicited information requests from trade
publications, many of which were telephone inquiries seeking an
immediate telephonic response. SET has advised the FERC that, out of
several hundred communications during the relevant period, prices were
inaccurately reported by perhaps $.01 to $.02 per mmbtu on a handful of
occasions involving an area in the Rocky Mountain region. No records of
these telephone conversations exist. SET has also advised the FERC that
it has found no instances involving inaccurate written information
provided by SET to trade publications.

On May 28, 2002, SER filed a complaint for declaratory judgment in San
Diego Superior Court regarding its contract with the DWR. In addition to
other relief, SER is seeking a binding declaration from the court that,
contrary to DWR's stated position, SER is meeting the terms of the
agreement and that DWR is obligated to take delivery of and pay for
wholesale electric power, as provided for under the agreement. In
response to SER's complaint for a declaratory judgment, on July 2, 2002,
the DWR filed a cross-complaint against SER, seeking to void the 10-year
energy-supply contract by alleging that SER misrepresented its
intentions regarding the Elk Hills Power Plant as well as the other
plants currently under construction. The DWR continues to accept all
scheduled power from SER and has made all payments for such power. The
construction of the Elk Hills Power Plant is on schedule to begin
operating in the spring of 2003. See further discussion in "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" under "Sempra Energy Resources."

SET is a defendant in the action at the FERC concerning rates charged
certain utilities by sellers of electricity. Management cannot predict
the outcome of this matter.

At September 30, 2002, SET remains due approximately $100 million from
energy sales made in 2000 and 2001 through the California Independent
System Operator and the California Power Exchange markets. The
collection of these receivables depends on satisfactory resolution of
the financial difficulties being experienced by other California IOUs as
a result of the California electric industry crisis. SET has submitted
relevant claims in the Pacific Gas and Electric and in the California
Power Exchange bankruptcy proceedings. The company believes adequate
reserves have been recorded.

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 these matters
will not have a material adverse effect on the company's financial
condition or results of operations.

ARGENTINE INVESTMENTS

SEI has a $300 million investment in Argentina through its ownership of
approximately 40 percent of two natural gas operating utilities. As a
result of the decline in the value of the Argentine peso, SEI has
reduced the carrying value of its investment to $50 million by reducing
shareholders' equity by $250 million, which is included in accumulated
other comprehensive income (loss). These non-cash adjustments, which
began at the end of 2001 and are continuing, did not affect net income,
but did reduce comprehensive income and increase accumulated other
comprehensive income (loss).

The related Argentine economic decline and government responses
(including Argentina's unilateral, retroactive abrogation of utility
agreements earlier this year) are continuing to adversely affect the
operations of SEI's two unconsolidated Argentine utilities. On September
5, 2002, SEI filed for international arbitration 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 the government actions. SEI expects the International Center for
Settlement of Investment Disputes to recognize the filing and set the
matter for arbitration within two months, but resolution is expected to
take more than a year. Sempra Energy also has political-risk insurance
that could recover a portion of the diminution. If it were to become
probable that SEI would not recover at least the difference between its
pre-currency-adjustment carrying value of these investments over their
diminished value, SEI would at that time record a non-recurring charge
against net income equal to the shortfall. However, the effect on
shareholders' equity of any such charge would be reduced or eliminated
to the extent of the currency adjustments relating to SEI's Argentine
investments previously recorded in other comprehensive income.

QUASI-REORGANIZATION

In 1993, PE divested its merchandising operations and most of its oil
and 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.

3. COMPREHENSIVE INCOME

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

Three Months Nine Months
Ended Ended
September 30, September 30,
---------------------------------
(Dollars in millions) 2002 2001 2002 2001
- -----------------------------------------------------------------

Net income $ 150 $ 96 $ 443 $ 410

Foreign currency adjustments (54) (15) (182) (28)

Minimum pension liability
adjustments -- -- (14) (8)

Market-value adjustments of
financial instruments (Note 5) -- 2 -- 1

---------------------------------
Comprehensive income $ 96 $ 83 $ 247 $ 375
- -----------------------------------------------------------------

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. During
the third quarter of 2002, SER met the requirements for disclosure as a
reportable segment for the first time. The two utilities operate in
essentially separate service territories under separate regulatory
frameworks and rate structures set by the CPUC. As described in the
notes to Consolidated Financial Statements in the company's Annual
Report, SDG&E provides electric service to San Diego and southern Orange
counties and natural gas service to San Diego county. SoCalGas is a
natural gas distribution utility, serving customers throughout most of
southern California and part of central California. SET, based in
Stamford, Connecticut, is a wholesale trader of physical and financial
products, including natural gas, electricity, petroleum, petroleum
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 the same as those described
in the notes to Consolidated Financial Statements in the company's
Annual Report, and segment performance is evaluated by management based
on reported net income. Utility transactions are primarily based on
rates set by the CPUC and the FERC.

- -----------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------------------------------
(Dollars in millions) 2002 2001 2002 2001
- -----------------------------------------------------------------------------
Operating Revenues:
Southern California Gas $ 597 $ 561 $1,999 $3,036
San Diego Gas & Electric 420 333 1,254 1,973
Sempra Energy Trading 178 224 582 915
Sempra Energy Resources 136 102 275 135
Intersegment revenues (7) (5) (17) (18)
Other 60 202 245 390
-------------------------------------------------
Total $ 1,384 $1,417 $4,338 $6,431
- -----------------------------------------------------------------------------
Net Income:
Southern California Gas* $ 56 $ 57 $ 167 $ 156
San Diego Gas & Electric* 46 43 150 132
Sempra Energy Trading 10 31 73 186
Sempra Energy Resources 29 (9) 60 (14)
Other 9 (26) (7) (50)
-------------------------------------------------
Total $ 150 $ 96 $ 443 $ 410
- -----------------------------------------------------------------------------
* after preferred dividends

- --------------------------------------------------------
Balance at
------------------------
September 30, December 31,
2002 2001
- --------------------------------------------------------
Assets:
Southern California Gas $ 3,815 $ 3,762
San Diego Gas & Electric 5,646 5,444
Sempra Energy Trading 5,264 2,997
Sempra Energy Resources 1,080 577
Other 2,538 3,248
Intersegment receivables (1,170) (872)
-----------------------
Total $17,173 $15,156
- --------------------------------------------------------

5. FINANCIAL INSTRUMENTS

Note 10 of the notes to Consolidated Financial Statements in the
company's Annual Report discusses the company's financial instruments,
including the adoption of SFAS 133 and SFAS 138, accounting for
derivative instruments and hedging activities, market risk, interest-
rate risk management, energy derivatives and contracts, and fair value.
Additional activity and information since January 1, 2002 related to
financial instruments are described herein.

At September 30, 2002, $3 million in current assets, $33 million in
investments and other assets, $134 million in current liabilities and
$912 million in deferred credits and other liabilities were recorded in
the Consolidated Balance Sheets for fixed-priced contracts and other
derivatives. Regulatory assets and liabilities were established to the
extent that derivative gains and losses are recoverable or payable
through future rates. As such, $133 million in current regulatory
assets, $912 million in noncurrent regulatory assets and $1 million in
current regulatory liabilities were recorded in the Consolidated Balance
Sheets as of September 30, 2002.

For the nine months ended September 30, $2 million of losses in 2002 and
$3 million of income in 2001 were recorded in natural gas operating
revenues and $1 million of income in 2002 and $2 million of losses in
2001 were recorded in other income in the Statements of Consolidated
Income. Additionally, market value adjustments of $11 and $22 million
were made at September 30, 2002 and December 31, 2001, respectively, to
long-term debt relating to two fixed-to-floating interest rate swap
agreements. The market value adjustment in 2002 included a reversing
effect for the cancellation of one of the swap agreements on September
30, 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 company's Annual Report.

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 CPUC, the
California Legislature, the DWR, and the FERC; 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 pace 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.

See also "Factors Influencing Future Performance" below.

CAPITAL RESOURCES AND LIQUIDITY

The company's California utility operations are a major source of
liquidity. During the period beginning in the third quarter of 2000 and
continuing into the first quarter of 2001, SDG&E's liquidity and its
ability to make funds available to Sempra Energy were adversely affected
by the electric cost undercollections resulting from a temporary ceiling
on electric rates legislatively imposed in response to high electric
commodity costs. Growth in these undercollections has ceased as a result
of an agreement with the DWR, under which the DWR is obligated to
purchase SDG&E's full net short position consisting of the power and
ancillary services required by SDG&E's customers that are not provided
by SDG&E's nuclear generating facilities or its previously existing
purchase power contracts. The agreement with the DWR extends through
December 31, 2002. The CPUC is conducting proceedings intended to
establish guidelines and procedures for the resumption of electricity
procurement by SDG&E and the other California IOUs and in October 2002
issued a decision directing the resumption of the electric commodity
procurement function by the IOUs by January 1, 2003. In addition, AB 57
and implementing decisions by the CPUC provide for periodic adjustments
to rates that would reflect the costs of power and are intended to
ensure that undercollections for the commodity cannot exceed four
percent of the annual non-DWR generation revenues. See further
discussion in the company's Annual Report and the discussion of AB 57 in
Note 2 of the notes to Consolidated Financial Statements.

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 (see
below) and price fluctuations) and the length of its various trading
positions. Its status as a source or use of Sempra Energy cash also
depends on its level of borrowing from its own sources.

CASH FLOWS FROM OPERATING ACTIVITIES

For the nine-month period ended September 30, 2002, the increase in cash
flows from operations compared to the corresponding period in 2001 was
attributable to the continuing decrease in SDG&E's undercollection of
purchased-power costs (the balance of which decreased to $392 million at
December 31, 2001 and $270 million at September 30, 2002 from a high in
mid-2001 of $750 million), the decrease in prior year overcollected
regulatory balancing accounts at SoCalGas as a result of actual cost of
gas being higher than amounts collected in rates during 2001, the
decrease in trade accounts payable due to lower gas prices in 2001
compared to 2000 and the DWR's purchasing SDG&E's net short position
beginning in 2001, and the net impact of trading activities. These
factors were partially offset by decreases in trade accounts receivable
and current taxes receivable.

CASH FLOWS FROM INVESTING ACTIVITIES

For the nine-month period ended September 30, 2002, the decrease in cash
flows from investing activities compared to the corresponding period in
2001 was primarily due to various acquisitions in 2002 to expand trading
operations, increased capital expenditures and, as reflected in "other-
net" on the Condensed Statements of Consolidated Cash Flows, required
investments used to secure project funding made under a synthetic
leasing agreement.

The 2002 capital expenditures include SER's costs related primarily to
the 1,200-megawatt Mesquite Power Plant near Phoenix, Arizona (expected
to commence commercial 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 other possible power plants being
considered for development.

Capital expenditures for property, plant and equipment by the California
utilities are estimated to be $700 million for the full year 2002 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 $1 billion for the full year 2002, of which $760 million
is attributable to SER, including amounts under SER's synthetic lease
agreement and the investment in Twin Oaks Power (described below).

The expansion of SoCalGas' pipeline capacity to meet increased demand by
electric generators and commercial and industrial customers, which
increased its capital expenditures in early 2002 and in 2001 and 2000,
have been completed.

In October 2001, CMS Energy and Sempra Energy announced an agreement
to develop jointly a major new liquefied natural gas (LNG) receiving
terminal to bring natural gas supplies into northwestern Mexico and
southern California. The plant will be located on the Pacific Coast,
north of Ensenada, Baja California, Mexico. Sempra Energy has
purchased a 300-acre site for the terminal for a purchase price of
$19.7 million. As currently planned, the plant would have a send-out
capacity of approximately 1 billion cubic feet per day of natural gas
through a new 40-mile pipeline between the terminal and existing
pipelines in the San Diego/Baja California border area. Subsequently,
CMS Energy has adjusted its role in the development of the terminal
since CMS Energy's business strategy is now to reduce debt and improve
its balance sheet, which will require restraint in its capital
spending. As a result, CMS Energy will not be an equity partner in the
project, but has retained an option to participate as an equity
partner in the project at a later date. It is still expected to
participate as the LNG plant operator and will also provide technical
support during the development of the project, which is currently
estimated to commence commercial operations in 2007.

On October 31, 2002, SER completed its previously announced acquisition
of a 305-megawatt, coal-fired power plant (to be renamed Twin Oaks
Power) from Texas-New Mexico Power Company for $120 million. SER has a
five-year contract to sell substantially all of the output of the plant
and an 18-year coal supply contract.

Earlier this year, SET completed three acquisitions that add base metals
trading and warehousing to its trading business. On February 4, 2002,
SET completed the acquisition of London-based Sempra Metals Limited
(formerly Enron Metals Limited), a leading metals trader on the London
Metals Exchange, for $145 million (subject to completion of an audit).
On April 26, 2002, SET completed the acquisition of the metals
concentrates business of New York-based Sempra Metals Concentrates
(formerly a part of Enron Metals & Commodity Corp.), a leading global
trader of copper, lead and zinc concentrates, for $24 million. Also in
April 2002, SET completed the acquisition of the U.S. warehousing
business of Henry Bath, Inc. and the European and Asian assets of the
Liverpool, England-based Henry Bath Limited and subsidiaries, which
provide warehousing services for non-ferrous metals in Europe and Asia,
for a total of $30 million. These acquisitions are expected to
contribute to Sempra Energy's earnings in 2002.

CASH FLOWS FROM FINANCING ACTIVITIES

For the nine-month period ended September 30, 2002, cash flows from
financing activities decreased from the corresponding period in 2001 due
primarily to the higher drawdowns of lines of credit in the 2001 period.

In October 2002, SoCalGas publicly offered and sold $250 million of
4.80-percent First Mortgage Bonds, maturing on October 1, 2012. The
bonds are not subject to a sinking fund and are not redeemable prior to
maturity except through a make-whole mechanism. Proceeds from the bond
sale have become part of the company's general treasury funds to
replenish amounts previously expended to refund and retire indebtedness
and will be used for working capital and other general corporate
purposes. These bonds were assigned ratings of A+ by the Standard &
Poor's rating agency, A1 by Moody's Investors Service, Inc., and AA by
Fitch, Inc.

On September 30, 2002, SoCalGas cancelled a fixed-to-variable interest-
rate swap on $175 million of first mortgage bonds. The $6 million gain
on the transaction is recorded in "Deferred Credits and Other
Liabilities" on the Consolidated Balance Sheet and will be amortized
over the life of the bonds, which mature in 2025.

In August 2002, SoCalGas paid off $100 million of 6.875-percent first
mortgage bonds at maturity. In June 2002, SDG&E paid off $28 million of
7.625-percent first mortgage bonds at maturity and, in July 2002, called
$10 million of 8.5-percent first mortgage bonds.

On September 10, 2002, Sempra Energy Global Enterprises, the parent
company for most of Sempra Energy's subsidiaries other than the
California utilities, replaced its expiring $1.2 billion revolving line
of credit with a $950 million syndicated credit agreement. The new
revolving line of credit, which is also guaranteed by Sempra Energy,
expires in September 2003, at which time outstanding borrowings may be
converted to a one-year term loan. The agreement requires Sempra Energy
to maintain a debt-to-total capitalization ratio (as defined in the
agreement) of not to exceed 65 percent.

During the second quarter of 2002, the company sold $600 million in
"Equity Units." Each unit consists of $25 principal amount of the
company's 5.60% senior notes due May 17, 2007 and a contract to purchase
for $25 on May 17, 2005, between .8190 and .9992 of a share of the
company's common stock (to be determined by the then-prevailing market
price). The net proceeds of the offering were used primarily to repay a
portion of its short-term debt, including the repayment of $200 million
borrowed by SER in April 2002 and other debt used to finance the capital
expenditure program for Sempra Energy Global Enterprises.

In March 2000, the company's board of directors authorized the optional
expenditure of up to $100 million to repurchase shares of common stock
from time to time in the open market or in privately negotiated
transactions. Through September 30, 2002, the company had acquired
896,800 shares under this authorization (162,400 in 2000, 60,000 in 2001
and 674,400 in the third quarter of 2002).

In May 2002, SDG&E and SoCalGas replaced their individual revolving
lines of credit with a combined revolving credit agreement under which
each utility may individually borrow up to $300 million, subject to a
combined borrowing limit for both utilities of $500 million. Each
utility's revolving credit line expires on May 16, 2003, at which time
it may convert its then outstanding borrowings to a one-year term loan
subject to having obtained any requisite regulatory approvals relating
to long-term debt. Borrowings under the agreement, which are available
for general corporate purposes including back-up support for commercial
paper and variable-rate long-term debt, would bear interest at rates
varying with market rates and the individual borrowing utility's credit
rating. The agreement requires each utility individually 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
a default by the other. These lines of credit were unused at September
30, 2002.

On September 30, 2002, Moody's Investors Service, Inc., reduced its
ratings of the company's senior unsecured debt from A2 with a negative
outlook to Baa1 with a stable outlook. The rating of SDG&E's senior
secured debt was also reduced from Aa3 with a negative outlook to A1
with a stable outlook. In April 2002, Fitch, Inc. confirmed its prior
credit ratings of the company's senior unsecured debt at A with a stable
outlook as well as confirming its prior ratings of the company's other
debt and that of its subsidiaries; Standard & Poor's reduced its ratings
of the company's senior unsecured debt from A with a negative outlook to
A- with a stable outlook, and made corresponding adjustments in the
ratings and outlook of the company's other debt and that of its
subsidiaries; and Moody's Investors Service, Inc., confirmed its prior
ratings of the debt of SoCalGas and the short-term debt and variable
rate demand bonds of SDG&E.

RESULTS OF OPERATIONS

Net income and net income per share increased for the nine-month period
ended September 30, 2002, compared to the corresponding period in 2001,
primarily due to improved results at the California utilities and at
SER, lower interest expense, the 2001 one-time after-tax charge of $25
million for the surrender of a natural gas distribution franchise in
Nova Scotia and the income-tax matters referred to below, partially
offset by lower income in 2002 from SET as described below and the 2001
gain on sale of Energy America. Net income and net income per share
increased for the three-month period ended September 30, 2002, compared
to the corresponding period in 2001, primarily due to improved results
at SDG&E and at SER and the one-time after-tax charge of $25 million
described above, partially offset by reduced earnings at SET. The
decreases in SET's earnings were primarily due to decreased volatility
in energy commodity markets and decreased energy commodity prices during
2002.

The decreases in other operating revenues and other operating expenses
for the three-month and nine-month periods ended September 30, 2002,
compared to the corresponding periods in 2001, were primarily due to
decreased volatility in energy commodity markets during 2002 at SET and
decreased natural gas prices in Mexico for SEI, partially offset by
SER's sales to the DWR that recommenced in April 2002 under its long-
term contract. SER sold power to the DWR at a discounted rate in 2001.
Other operating expenses for the nine-month period ended September 30,
2001 also included the gain on the sale of Energy America. In addition,
other operating revenues and operating expenses for the three-month
period decreased due to the deconsolidation of a small subsidiary
earlier in 2002.

The decrease in interest expense for the three-month and nine-month
periods ended September 30, 2002, compared to the corresponding period
in 2001, was primarily due to a decrease in average outstanding debt,
decreased interest rates in 2002 and the effects of interest-rate swaps.

Income tax expense decreased for the nine-month period ended September
30, 2002, compared to the corresponding period in 2001, primarily due to
the favorable resolution of income-tax issues in the second quarter of
2002 and higher income tax expense recorded in the first quarter of 2001
related to the position of the Internal Revenue Service on a prior
year's deduction. Income tax expense increased for the three-month
period ended September 30, 2002, compared to the corresponding period in
2001, primarily due to the increased income noted above.

UTILITY OPERATIONS

The tables below summarize the natural gas and electric volumes and
revenues by customer class for the nine-month periods ended September
30, 2002 and 2001.

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

The decrease in natural gas revenue is primarily due to lower natural gas
prices and decreased transportation for electric generation plants and the
loss of approximately 100 million cubic feet per day in load on the San
Diego system when the Baja Norte pipeline began service in September 2002.

The decrease in the cost of natural gas distributed was primarily due to
lower natural gas commodity prices. Under the current regulatory framework,
changes in natural gas commodity prices do not affect net income since, as
explained more fully in the company's Annual Report, current or future
customer rates normally recover the actual commodity cost of natural gas on
a substantially concurrent basis, subject to the mechanisms under
performance-based ratemaking as explained in the Annual Report.

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

The decreases in electric revenues and in electric fuel and net purchased
power expense for the nine-month period ended September 30, 2002, compared
to the corresponding period in 2001, were primarily due to the effect of
lower electric commodity costs, which are passed on to customers without
markup, and the DWR's purchases of SDG&E's net short position beginning in
February 2001. The increase in electric fuel and net purchased power
expense for the three-month period ended September 30, 2002, compared to
the corresponding period in 2001, was primarily attributable to the DWR's
independent system operator real time market refund during the third
quarter 2001. Under the current regulatory framework, changes in commodity
costs normally do not affect net income, as explained in the Annual Report,
subject to the mechanisms under performance-based ratemaking as explained
in the Annual Report.

SEMPRA ENERGY TRADING

SET recorded net income of $73 million and $186 million for the nine-
month periods ended September 30, 2002 and 2001, respectively, and net
income of $10 million and $31 million for the three-month periods ended
September 30, 2002 and 2001, respectively. The decrease in net income
was primarily due to decreased volatility in energy commodity markets
and decreased energy commodity prices during 2002.

For the nine-month period ended September 30, 2002, SET recorded net
revenues of $582 million compared to $915 million for the corresponding
period in 2001. SET's gross revenues were $23.9 billion and $26.7
billion for the nine-month periods ended September 30, 2002 and 2001,
respectively. SET has historically recorded trading activities net, as
now required of all trading companies, based on a consensus issued by
the Emerging Issues Task Force in June 2002.

The following tables summarize SET's trading margin by geographical
region and by product line for the nine-month periods ended September
30, 2002 and 2001.

Nine Months Ended
September 30
Trading Margin (dollars in millions) 2002 2001
- --------------------------------------------------------------------
Geographical:
North America $ 226 $ 551
Europe/Asia 91 72
------------------------
Total $ 317 $ 623
========================
Product Line:
Gas $ 149 $ 206
Power 68 287
Oil/Crude & Products 35 120
Other 65 10
------------------------
Total $ 317 $ 623
========================

The estimated fair values for SET's trading activities as of September
30, 2002, 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.

September 30 December 31
(Dollars in millions) 2002 2001
- --------------------------------------------------------------------
Commodity Exchanges $ 111 $ 133
Investment Grade* 1,156 1,211
Below Investment Grade* 414 335
-------------------------
Total $1,681 $1,679
=========================
* As determined by rating agencies or internal models intended to
approximate rating-agency determinations.
- --------------------------------------------------------------------

A summary of SET's unrealized revenues for trading activities for the
three-month and nine-month periods ending September 30, 2002 (in
millions of dollars) follows:

Three months Nine months
Ended Ended
September 30, 2002 September 30, 2002
- ----------------------------------------------------------------------
Balance at beginning of period $ 407 $ 405
Additions 169 355
Realized (129) (313)
------------------------------------
Balance at September 30, 2002 $ 447 $ 447
====================================

See also the comment concerning the CPUC's prohibition of IOUs'
procuring electricity from their affiliates in "Electric Industry
Restructuring" in Note 2 of the notes to Consolidated Financial
Statements.

SEMPRA ENERGY INTERNATIONAL

Results for SEI were net income of $30 million and $11 million for the
nine-month periods ended September 30, 2002 and 2001, respectively, and
net income of $13 million and a net loss of $7 million for the three-
month periods ended September 30, 2002 and 2001, respectively. The
increases in net income were primarily due to the 2001 one-time, after-
tax charge of $25 million following the surrender of Sempra Atlantic
Gas' natural gas distribution franchise in Nova Scotia, partially offset
by reduced profitability from operations in the Argentine subsidiaries.
A discussion of the Argentine economic issue is included in Note 2 of
the notes to Consolidated Financial Statements.

The 215-mile North Baja natural gas pipeline constructed by SEI and
partner PG&E Corporation, extending from Arizona to the Rosarito
Pipeline south of Tijuana, is now operational and is expected to begin
contributing to earnings in the fourth quarter of 2002.

SEMPRA ENERGY RESOURCES

Results for SER were net income of $60 million for the nine-month period
ended September 30, 2002, compared with a net loss of $14 million for
the corresponding period in 2001, and net income of $29 million and a
net loss of $9 million for the three-month periods ended September 30,
2002 and 2001, respectively. The improvements were primarily due to
sales to the DWR that commenced in April 2002 under its long-term
contract. Losses in 2001 related to development costs of new generation
projects and selling power to the DWR at below cost in June through
September of 2001, under the long-term contract.

SER has an agreement with the DWR to supply the DWR with up to 1,900
megawatts of electricity over a ten-year period ending in September
2011. Sempra Energy's ability to increase its earnings is significantly
dependent on results to be provided by the DWR agreement. As previously
reported, the CPUC and the California Electricity Oversight Board have
filed complaints with the FERC alleging that the agreement, as well as
other agreements entered into by the DWR with other electricity
suppliers, do not provide just and reasonable rates, and seeking to
abrogate or reform the agreements. On April 24, 2002, the FERC ordered
hearings on the complaints. The order requires the complainants to
satisfy a "heavy" burden of proof to support a revision of the
contracts, and cited the FERC's long-standing policy to recognize the
sanctity of contracts, from which it has deviated only in "extreme
circumstances." Hearings will begin in December, 2002. Settlement
negotiations are ongoing. The FERC expects to issue a final decision by
May 2003.

Although the contract is subject to ongoing litigation and regulatory
proceedings, both SER and the State of California are performing under
this contract, which is scheduled to end on September 30, 2011, and SER
and the State of California are continuing discussions on the contract.
Information concerning the litigation is provided in Note 2 of the notes
to Consolidated Financial Statements.

On October 31, 2002, SER completed its previously announced acquisition
of a 305-megawatt, coal-fired power plant (to be renamed Twin Oaks
Power) from Texas-New Mexico Power Company for $120 million. SER has a
five-year contract to sell substantially all of the output of the plant
and an 18-year coal supply contract.

The 1,200-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. This project has been
financed through a synthetic lease agreement. Under this agreement, SER
is reimbursed monthly for most project costs. Through September 30,
2002, SER had received $433.6 million under this facility. All amounts
above $280 million require collateralization through purchases of
Treasury Bonds, which must be at least equal to 103 percent of the
amount drawn. That collateralization was $159.1 million at September 30,
2002, and is included in "Investments" on the Consolidated Balance
Sheets.

SER also has contracted for two turbine sets (each consisting of two gas
turbines and one steam turbine), beyond those required for its plants
currently under construction. Six additional sites, two of which are
already fully permitted, are being evaluated for potential power plant
locations and SER intends to use these turbine sets at two of these
sites.

See also the comment concerning the CPUC's prohibition of IOUs'
procuring electricity from their affiliates in "Electric Industry
Restructuring" in Note 2 of the notes to Consolidated Financial
Statements.

OTHER OPERATIONS

SES recorded net income of $11 million for the nine-month period ending
September 30, 2002, compared with a net loss of $4 million for the
corresponding period in 2001, and net income of $5 million and $0.1
million for the three-month periods ended September 30, 2002 and 2001,
respectively. The improvement resulted from increased commodity sales.

The CPUC's decisions concerning direct access, described in "Electric
Industry Restructuring" in Note 2 of the notes to Consolidated Financial
Statements, affect SES's ability to enter into contracts to sell
electricity in California.

SEF invests in limited partnerships, which own 1,300 affordable-housing
properties throughout the United States, Puerto Rico and the Virgin
Islands, and tax-advantaged synthetic fuel facilities. These investments
are expected to provide income-tax benefits, primarily from income-tax
credits. SEF recorded net income of $23 million and $20 million for the
nine-month periods ended September 30, 2002 and 2001, respectively, and
net income of $9 million and $7 million for the three-month periods
ended September 30, 2002 and 2001, respectively. SEF's future investment
policy is dependent on the company's future domestic income-tax
position.

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, SEI, SER and
other businesses. Recent developments concerning the factors influencing
future performance are summarized below. Note 2 of the notes to
Consolidated Financial Statements and the company's Annual Report
describe events in the deregulation of California's electric and natural
gas industries.

Merger Savings

In October 2001, the CPUC denied the California utilities' request to
continue equal sharing between ratepayers and shareholders of estimated
savings stemming from the 1998 merger between the California utilities'
former parent companies. Instead, the CPUC ordered that all of the
estimated 2003 merger savings go to ratepayers. The annual shareholder
portion of the pretax savings for 2002 is $41 million.

Investments

As described in the company's Annual Report, the company has various
investments and projects that will impact the company's future
performance. Earlier this year, SET completed three acquisitions that
add base metals trading and warehousing to its trading business. These
acquisitions are Sempra Metals Limited (formerly Enron Metals Limited),
Sempra Metals Concentrates (formerly a part of Enron Metals & Commodity
Corp.) and Henry Bath, and are further described in "Cash Flows From
Investing Activities." These acquisitions are expected to contribute to
Sempra Energy's earnings in 2002. In addition, on October 31, 2002, SER
completed its previously announced acquisition of a 305-megawatt, coal-
fired power plant (to be renamed Twin Oaks Power) from Texas-New Mexico
Power Company for $120 million. SER has a five-year contract to sell
substantially all of the output of the plant and an 18-year coal supply
contract.

Electric-Generation Assets

As described in the company's Annual Report, the company is involved in
the development of several electric-generation projects that will
significantly impact the company's future performance. The power plants
that SER is building in Arizona, California and Mexico are on schedule
to commence operations by the end of 2003. SER has approximately 2,400
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 March 2003. The 1,200-megawatt Mesquite Power Plant near Phoenix,
Arizona, is expected to commence commercial operations in June 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. Electricity from the plants will be available for
markets in California, Arizona and Mexico. SER's projected portfolio of
plants in the western United States and Baja California, Mexico, will
supply power to the state of California under SER's agreement with the
DWR. See further discussion above concerning negotiations with the DWR
about the contract, under "Sempra Energy Resources," concerning SER's
contract with the DWR.

Operating costs of SONGS Units 2 and 3, including nuclear fuel and
related financing costs, and incremental capital expenditures are
recovered through a performance incentive pricing plan (ICIP) 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 and, for the nine-month period ended September
30, 2002, ICIP contributed $37 million to SDG&E's net income. The CPUC
has rejected an administrative law judge's proposed decision to end ICIP
prior to its December 31, 2003 scheduled expiration date. However, the
CPUC has also 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. SDG&E
has applied for a rehearing of this decision as contrary to market-based
pricing contemplated by the overall SONGS ratemaking mechanism adopted
by the CPUC in establishing ICIP in 1996. If SDG&E were to be granted
market-based rates, SDG&E believes the impact of the end of ICIP would
be somewhat reduced.

Gas and Electric Rates

On November 7, 2002, the CPUC granted SDG&E an increase in its
authorized return on equity from 10.6 percent to 10.9 percent. This
change will result in a revenue requirement increase of $2.4 million
($1.9 million electric and $0.5 million gas), effective January 1, 2003.
The decision will increase SDG&E's overall rate of return from 8.75
percent to 8.77 percent.

SoCalGas has a Cost of Capital Trigger Mechanism under which the
company's rate of return and customer rates authorized by the CPUC are
subject to automatic cost of capital adjustments for certain changes in
interest rates. On October 8, 2002, such a trigger occurred. Therefore,
there will be an automatic downward adjustment in rates by a formula
that updates the cost of each component of SoCalGas' capital structure.
SoCalGas will file an advice letter at the CPUC and expects the filing
will reduce its annual margin effective January 1, 2003, by an amount
expected to be approximately $10 million as a result of the triggering
of this mechanism. This would reduce SoCalGas' annual after-tax income
by approximately $6 million.

The CPUC has adopted a settlement proposed by SoCalGas in a recent case
involving review of its Gas Cost Incentive Mechanism (GCIM). The CPUC
decision finds that this mechanism, which allows SoCalGas to receive a
share of the savings it achieves in buying natural gas for core
customers, should continue indefinitely. Savings are determined by
comparing the actual cost of gas purchases to a benchmark of monthly
prices. SoCalGas has requested that the CPUC approve rewards of $30.8
million and $17 million for the last two completed program years. No
rewards are included in SoCalGas' earnings until approved by the CPUC.
CPUC approval of these rewards is expected in 2003, pending the
Commission's investigation into the run-up in California border natural
gas prices during the winter of 2000-2001.

SDG&E has a Gas Procurement Performance-Based Ratemaking (PBR) mechanism
that allows SDG&E to receive a share of the savings it achieves by
buying natural gas for customers below a monthly benchmark. In March
2002, SDG&E requested a reward of $7 million for the PBR natural gas
procurement period ended July 31, 2001 (Year 8). No reward will be
included in SDG&E's earnings until it is approved by the CPUC, which is
expected by the end of 2002. In October 2002, SDG&E filed its Year 9
report for the PBR natural gas procurement period ended July 31, 2002,
reporting a $1.4 million penalty, which has been recorded as of
September 30, 2002.

On June 17, 2002, SDG&E amended its March 21, 2002 joint application
with Southern California Edison requesting the CPUC to set contribution
levels for the SONGS nuclear decommissioning trust funds. SDG&E
requested a rate increase to cover its share of total projected
increased decommissioning costs for SONGS. If approved, the current
annual contribution to SDG&E's trust funds, which is recovered in rates,
would increase to $11.5 million annually from $4.9 million. Prior to
August 1999, SDG&E's annual contribution had been $22 million.

In August 2002, the CPUC issued a resolution approving SDG&E's 2000 PBR
report. The resolution approved SDG&E's request for a total net reward
of $11.7 million (pretax), as well as SDG&E's actual 2000 rate of return
(applicable only to electric distribution and gas transportation) of
8.74 percent, which is below the authorized 8.75 percent. This resulted
in no sharing of earnings in 2000 under the PBR sharing mechanism
described in the company's Annual Report. The financial results herein
include the reward during the third quarter of 2002.

In September 2002, the CPUC issued a decision denying SoCalGas' and
SDG&E's request to combine their natural gas procurement activities at
this time, pending completion of the CPUC's ongoing investigation of
market power issues.

The California utilities will file applications with the CPUC in
December 2002 to set new base rates. A CPUC decision is expected in late
2003, with new rates to become effective January 1, 2004.

The California utilities have earned rewards for successful
implementation of Demand-Side Management programs that have been
scheduled by the CPUC for payout over several years. In a recent ruling,
a CPUC Administrative Law Judge has indicated an intent to reanalyze the
uncollected portion of past rewards earned by utilities (which have not
been included in the California utilities' income), and potentially
recompute the amount of the rewards. The California utilities will
oppose the recomputation.

NEW ACCOUNTING STANDARDS

New statements by the Financial Accounting Standards Board that have
recently become effective or are yet to be effective are numbers 142
through 146. They are described in Note 1 of the notes to Consolidated
Financial Statements. Number 142 increases net income by ending the
amortization of goodwill. Number 143 requires accounting and disclosure
changes concerning legal obligations related to future asset
retirements. Number 144 replaces number 121 in dealing with asset
impairment issues. Number 145 makes technical corrections to previous
statements and number 146 deals with exit and disposal activities,
replacing Issue 94-3 of the Emerging Issues Task Force.

In June 2002, a consensus was reached in Emerging Issues Task Force
(EITF) Issue 02-3 "Issues Related to Accounting for Contracts Involved
in Energy Trading and Risk Management Activities," which codifies and
reconciles existing guidance on the recognition and reporting of gains
and losses on energy trading contracts and addresses other aspects of
the accounting for contracts involved in energy trading and risk
management activities. Among other things, the consensus requires that
mark-to-market gains and losses on energy trading contracts should be
shown net 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. All
other Sempra Energy subsidiaries were already recording trading
activities net and required no change. The required reclassifications
will have no impact on previously recorded gross margin, net income, or
cash provided by operating activities.

In October 2002, the EITF repealed EITF Issue 98-10, the basis for mark-
to-market accounting by many companies, including SET and SES. Many of
the transactions accorded mark-to-market accounting by 98-10 will still
be accorded mark-to-market accounting based on SFAS 133 "Accounting for
Derivative Instruments and Hedging Activities." The impact of the repeal
of 98-10 for the company is not yet known, but preliminarily it believes
that the majority of the revenue recorded under mark-to-market
accounting based on EITF 98-10 will still be recorded under mark-to-
market accounting based on SFAS 133.

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. As noted in
that report, the California utilities may, at times, be exposed to
limited market risk in their natural gas purchase and sale activities as
a result of activities under SDG&E's gas Performance-Based Regulation
mechanism or SoCalGas' Gas Cost Incentive Mechanism. The risk is managed
within the parameters of the company's market-risk management and
trading framework.

The Value at Risk (VaR) for SET at September 30, 2002, and the average
VaR for the nine-month period ended September 30, 2002, at the 95-
percent and 99-percent confidence intervals (one-day holding period)
were as follows (in millions of dollars):

95% 99%
------ ------
At September 30, 2002 $7.7 $10.8
Average for the nine months ended 9/30/02 $6.1 $8.6

As of September 30, 2002, 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 2 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 10 - Material Contracts

10.1 Form of Employment Agreement between Sempra Energy and
Stephen L. Baum.

10.2 Form of Employment Agreement between Sempra Energy and
Donald E. Felsinger.

10.3 Amended and Restated Sempra Energy Deferred Compensation and
Excess Savings Plan.

Exhibit 12 - Computation of ratios

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

(b) Reports on Form 8-K

The following reports on Form 8-K were filed after June 30, 2002:

Current Report on Form 8-K filed July 24, 2002, filing as an exhibit
Sempra Energy's press release of July 23, 2002, giving the financial
results for the three-month period ended June 30, 2002.

Current Report on Form 8-K filed August 14, 2002, filing as an exhibit
Statements Under Oath of Principal Executive Officer and Principal
Financial Officer Regarding Facts and Circumstances Relating to Exchange
Act Filings pursuant to 18 U.S.C. Sec. 1350, as created by Section 906
of the Sarbanes-Oxley Act of 2002.

Current Report on Form 8-K filed October 25, 2002, filing as an exhibit
Sempra Energy's press release of October 22, 2002, giving the financial
results for the three-month period ended September 30, 2002.

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: November 8, 2002 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.

November 8, 2002

/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.

November 8, 2002

/s/ Neal E. Schmale
Neal E. Schmale
Chief Financial Officer