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, 2003
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Commission file number 1-14201
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Sempra Energy
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(Exact name of registrant as specified in its charter)

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

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

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

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

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

Common stock outstanding on October 31, 2003: 226,236,056
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INFORMATION REGARDING FORWARD-LOOKING STATEMENTS

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

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

ITEM 1. FINANCIAL STATEMENTS.

SEMPRA ENERGY 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
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. GENERAL

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

The accompanying Consolidated Financial Statements have been prepared
in accordance with the interim-period-reporting requirements of Form
10-Q. Results of operations for interim periods are not necessarily
indicative of results for the entire year. In the opinion of
management, the accompanying statements reflect all adjustments
necessary for a fair presentation. These adjustments are only of a
normal recurring nature. Certain changes in classification have been
made to prior presentations to conform to the current financial
statement presentation.

Information in this Quarterly Report is unaudited and should be read in
conjunction with the Annual Report on Form 10-K for the year ended
December 31, 2002 (Annual Report) and the Quarterly Reports on Form 10-Q
for the three months ended March 31, 2003 and June 30, 2003.

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

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

COMPREHENSIVE INCOME

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

Three months Nine months
ended ended
September 30, September 30,
---------------------------------
(Dollars in millions) 2003 2002 2003 2002
- -----------------------------------------------------------------

Net income $ 211 $ 150 $ 415 $ 443

Foreign currency adjustments (13) (54) 31 (182)

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

---------------------------------
Comprehensive income $ 198 $ 96 $ 440 $ 247
- -----------------------------------------------------------------

2. NEW ACCOUNTING STANDARDS

Emerging Issues Task Force (EITF) 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities": In
accordance with the EITF's rescission of Issue 98-10 by the release of
Issue 02-3, the company no longer recognizes energy-related contracts
under mark-to-market accounting unless the contracts meet the
requirements stated under SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities," which is the case for a
substantial majority of the company's contracts. On January 1, 2003,
the company recorded the initial effect of Issue 98-10's rescission as
a cumulative effect of a change in accounting principle, which reduced
after-tax earnings by $29 million. Only $18 million of the $29 million
had been included in net income through December 31, 2002. However, the
$18 million was net of the after-tax effect of income-based expenses,
which are not considered in calculating the cumulative effect of the
accounting change. As the underlying transactions are completed
subsequent to December 31, 2002, and the gains or losses are recorded,
the entire $29 million, plus or minus intervening changes in market
value, will be included in the calculation of net income. On a net
basis, $6 million of the $29 million was realized during the nine
months ended September 30, 2003, all of which occurred in the third
quarter. Neither the cumulative nor the ongoing effect impacts the
company's cash flow or liquidity.

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

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

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

(Dollars in millions) SET Other Total
- ------------------------------------------------------------------
Balance as of January 1, 2003 $ 141 $ 41 $ 182
Goodwill acquired during 2003 -- 10 10
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Balance as of September 30, 2003 $ 141 $ 51 $ 192
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SFAS 143, "Accounting for Asset Retirement Obligations": The adoption
of SFAS 143 on January 1, 2003 resulted in the recording of an addition
to utility plant of $71 million, representing the company's share of
the San Onofre Nuclear Generating Station's (SONGS) estimated future
decommissioning costs (as discounted to the present value at the dates
the units began operation), and accumulated depreciation of $41 million
related to the increase to utility plant, for a net increase of $30
million. In addition, the company recorded a corresponding retirement
obligation liability of $309 million (which includes accretion of that
discounted value to December 31, 2002) and a regulatory liability of
$215 million to reflect that SDG&E has collected the funds from its
customers more quickly than SFAS 143 would accrete the retirement
liability and depreciate the asset. These liabilities, less the $494
million recorded as accumulated depreciation prior to January 1, 2003
(which represents amounts collected for future decommissioning costs),
comprise the offsetting $30 million.

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

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

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

Balance as of January 1, 2003 $ --
Adoption of SFAS 143 329
Accretion expense 17
Payments (12)
------
Balance as of September 30, 2003 $ 334*
======

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

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

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

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

SFAS 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets": In August 2001, the FASB issued SFAS 144, which supercedes a
prior accounting standard related to the accounting for the impairment
or disposal of long-lived assets. However, SFAS 144 retains the
fundamental provisions of the impairment standard regarding
recognition/measurement of impairment of long-lived assets to be held
and used and measurement of long-lived assets to be disposed of by
sale. SFAS 144 applies to all long-lived assets, including discontinued
operations. Under SFAS 144 the company is required to reduce the
carrying value of assets to fair value and recognize asset impairment
charges in the event that the carrying value of such assets exceeds the
estimated future undiscounted cash flows attributable to such assets.

During the third quarter of 2003, the company recorded a $77 million
non-cash impairment charge ($47 million after-tax) to write down the
carrying value of the assets of Frontier Energy, a small North Carolina
utility subsidiary, as a result of reductions in actual and previously
anticipated sales of natural gas by this utility. This charge is
included in other operating expenses in the Statements of Consolidated
Income. In applying the provisions of SFAS 144, management determined
the fair value of such assets based on its estimate of discounted
future cash flows.

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

SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": SFAS 149 amends and clarifies accounting for
derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities under SFAS 133.
The adoption of SFAS 149 did not have an effect on the company's
consolidated results of operations and financial position.

SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity": This statement
establishes standards for how an issuer classifies and measures certain
financial instruments with characteristics of both liabilities and
equity. SFAS 150 requires that certain mandatorily redeemable financial
instruments previously classified in the mezzanine section of the
balance sheet be reclassified as liabilities. The company has adopted
SFAS 150 beginning July 1, 2003 by reclassifying $200 million and $23
million of mandatorily redeemable trust preferred securities and
preferred stock of subsidiaries, respectively, to deferred credits and
other liabilities.

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

FASB Interpretation No. 46 (FIN 46), "Consolidation of Variable Interest
Entities": In January 2003, the FASB issued FIN 46, which requires the
primary beneficiary of a variable interest entity's activities to
consolidate the entity. The consolidation requirements of the
interpretation apply immediately to entities created after January 31,
2003. During October 2003, the FASB deferred the implementation date for
pre-existing variable interest entities until the end of the first
interim or annual period ending after December 15, 2003.

Sempra Energy has identified two variable interest entities for which it
is the primary beneficiary. One of the variable interest entities
relates to an investment in an unconsolidated subsidiary, Atlantic
Electric & Gas Limited (AEG), that markets power and natural gas
commodities to commercial and residential customers in the United
Kingdom. As currently written, FIN 46 would require Sempra Energy to
record 100% of AEG's operations, whereas it now records only its share
of AEG's net operating results. The other entity is the lessor of the
Mesquite Power Plant (Mesquite Power) described below. Accordingly, if
the FASB's deliberations during the deferral period do not result in the
exclusion of these entities from FIN 46's definitions, Sempra Energy
will consolidate these entities in its financial statements during the
fourth quarter of 2003. This is estimated to increase total assets and
total liabilities by $700 million. The company expects implementation to
result in an after-tax charge for the cumulative effect from the change
in accounting principle to be approximately $17 million and no change to
operating income.

Mesquite Power, located near Phoenix, Arizona, is a $675 million, 1,250-
megawatt (mw) project that provides electricity to wholesale energy
markets in the Southwest. Construction began in September 2001 and the
first phase of commercial operations (50-percent of the plant's total
capacity) began in June 2003. The second phase of commercial operations
(the remaining 50 percent) is expected to begin in November 2003.
Expenditures as of September 30, 2003 are $641 million. A synthetic
lease agreement provides financing for all project assets owned by the
lessor. Financing under the synthetic lease in excess of $280 million
requires 103 percent collateralization by U.S. Treasury obligations in
similar amounts. As of September 30, 2003, the company held $350 million
of U.S. Treasury obligations, which is included in investments on the
Consolidated Balance Sheets.

3. MATERIAL CONTINGENCIES

ELECTRIC INDUSTRY REGULATION

The restructuring of California's electric utility industry has
significantly affected the company's electric utility operations and
the power crisis of 2000-2001 caused the California Public Utilities
Commission (CPUC) to adjust its plan for restructuring the electricity
industry. The background of this issue is described in the Annual
Report. Subsequent developments are described herein.

Various projections of electricity demand in SDG&E's service territory
indicate that, without additional electrical generation and transmission
and reductions in electrical usage, beginning in 2005 electricity demand
could begin to outstrip available resources. SDG&E has issued a request
for proposals (RFP) to meet the electric capacity shortfall, estimated
at 69 megawatts in 2005 and increasing annually by approximately 100
megawatts, and has filed a proposed plan at the CPUC for meeting these
capacity requirements.

On October 7, 2003, SDG&E applied to the CPUC for approval of its RFP
results. SDG&E's electric procurement plan contemplates (i) procuring
643 megawatts of energy and demand reduction resources (73 megawatts
beginning in 2005 with contracts extending through 2020 and 570
megawatts beginning in 2007 and extending through 2017); (ii) acquiring
601 megawatts of new generation, including a 555-megawatt power plant in
Escondido, California, to be constructed by SER for completion in 2006;
and (iii) constructing new transmission lines. The capital cost related
to this proposed plan is approximately $640 million and the plan
includes a mix of energy supply sources, including renewable resources.
Hearings will be held during the fourth quarter of 2003 and a CPUC
decision is expected during the first half of 2004. In connection with
the possible return to a generation-ownership role for investor-owned
utilities (IOUs), SDG&E required bidders to include both power purchase
and SDG&E ownership options in their response to the RFP noted above.

The California Department of Water Resources' (DWR) Operating Agreement
with SDG&E, approved by the CPUC, governs SDG&E's administration of the
allocated DWR contracts. The agreement provides that SDG&E is acting as
a limited agent on behalf of the DWR in undertaking energy sales and
natural gas procurement functions under the DWR contracts allocated to
SDG&E's customers. Legal and financial risks associated with these
activities will continue to reside with the DWR. However, in certain
limited circumstances involving transactions in which SDG&E, as DWR's
limited agent, is selling DWR surplus energy pursuant to the terms of
the Operating Agreement, SDG&E may be obligated to provide lines of
credit in connection with the allocated contracts. The risk associated
with these lines of credit is considered to be minimal. Since the DWR
retains legal and financial responsibility for the contracts allocated
to SDG&E, the costs associated with the contracts were not included in
the Statements of Consolidated Income during 2003. On July 10, 2003, the
CPUC approved SDG&E's natural gas supply plan related to certain DWR
contracts for the five-month period May 1, 2003 to September 30, 2003.
On August 15, 2003, SDG&E filed with the CPUC its natural gas supply
plan related to certain DWR contracts for the six-month period October
1, 2003 to March 31, 2004. CPUC action on this filing is pending.

On September 4, 2003, the CPUC approved a $1-billion refund to
consumers of the three major California IOUs as a result of the DWR's
lowering its revenue requirement for 2003. The refund is being returned
to customers in the form of a one-time bill credit. SDG&E's portion is
13.51 percent or about $135 million. The bill credit will have no
effect on SDG&E's net income and net cash flows because customer
savings are coming from lower charges by the DWR, and SDG&E is merely
transmitting the electricity from the DWR to the customers, without
taking title to the electricity.

The final true-up of DWR's 2001/2002 energy costs among California's
three major investor-owned electric utilities could result in SDG&E's
customers being allocated up to $60 million of additional costs or
having their allocation reduced by as much as $100 million. In either
case, SDG&E would account for any adjustment in its commodity balancing
account, which would be repaid to its customers or collected from its
customers in the near future. Either change in allocation would have a
short-term effect on SDG&E's cash flow (positive or negative as the
case may be), but would not otherwise affect its results of operations.

On August 21, 2003, the CPUC denied a rehearing requested by opponents
of its December 2002 decision that had approved a settlement with SDG&E
allocating between SDG&E customers and shareholders the profits from
intermediate-term purchase power contracts that SDG&E had entered into
during the early stages of California's electric utility industry
restructuring. As previously reported, the settlement provided $199
million of these profits to customers, by reductions to balancing
account undercollections in prior years. The settlement provided the
remaining $173 million of profits to SDG&E shareholders, of which $57
million had been recognized for financial reporting purposes in prior
years. As a result of the decision, SDG&E recognized additional after-
tax income of $65 million in the third quarter of 2003. On September 25,
2003 the Utility Consumers' Action Network (UCAN), a consumer-advocacy
group which had requested the CPUC rehearing, appealed the decision to
the California Court of Appeals. On October 24, 2003, SDG&E and the
Commission filed responses with the court to the UCAN appeal, setting
forth the reasons why there is no issue of law for the court to consider
and that the appeal should be denied. UCAN has twenty days to file a
reply. Acceptance of any appeal is at the discretion of the court. There
is no deadline by which the court must act.

On July 11, 2003, the CPUC adopted a proposed decision continuing the
level of the Direct Access (DA) cost responsibility surcharge (CRS) cap
effective July 1, 2003 at 2.7 cents per kWh, subject to possible
revision in the next DA CRS cap review proceeding. In each periodic DA
CRS cap review proceeding, the cap is subject to adjustment to the
extent necessary to maintain the goal of refunding to utility customers
the full amounts to which they are entitled by the end of the DWR
contract term in 2011. The DA CRS has no impact on SDG&E; however, the
surcharge may affect SES's ability to attract and maintain customers in
California.

NATURAL GAS INDUSTRY RESTRUCTURING

As discussed in Note 14 of the notes to Consolidated Financial
Statements in the Annual Report, in December 2001 the CPUC issued a
decision related to natural gas industry restructuring, with
implementation anticipated during 2002. During 2002 the California
Utilities filed a proposed implementation schedule and revised tariffs
and rules required for implementation. However, on February 27, 2003,
the CPUC issued a resolution rejecting without prejudice those proposed
tariffs and rules. The resolution ordered SoCalGas to file a new
application, which would address detailed proposals for implementation
of the December 2001 decision, but also would allow reconsideration of
the December 2001 decision. SoCalGas filed such an application on June
30, 2003, and proposed some modifications to the provisions of the
December 2001 decision to respond to concerns that it could lead to
higher natural gas costs for consumers.

The modifications include, among other things, a proposal not to
unbundle natural gas transmission, a higher market price cap on
receipt-point capacity transactions in the secondary market, deferral
of retail unbundling provisions, and a proposal to litigate
transmission and storage revenue requirements in the Cost of Service
case (see below). The proposed modifications would also remove
SoCalGas' exposure to risk or reward for the sale of receipt-point
capacity. The filing proposes implementation of these provisions on
April 1, 2004 and continuing through August 31, 2006. On September 29,
2003, the CPUC issued a ruling indicating that the proceeding will
initially only consider implementation of the original December 2001
decision, but the Assigned Commissioner said he will informally look at
the alternatives proposed by SoCalGas. The matter has been set for
hearing and a CPUC decision is expected by January 2004. If the
December 2001 decision is implemented, it is not expected to have a
material effect on the California Utilities' earnings.

BORDER PRICE INVESTIGATION

In November 2002, the CPUC instituted an investigation into the
Southern California natural gas market and the price of natural gas
delivered to the California-Arizona (CA-AZ) border during the period of
March 2000 through May 2001. If the investigation determines that the
conduct of any respondent contributed to the natural gas price spikes
at the CA-AZ border during this period, the CPUC may modify the
respondent's applicable natural gas procurement incentive mechanism,
reduce the amount of any shareholder award for the period involved,
and/or order the respondent to issue a refund to ratepayers to offset
the higher rates paid. The California Utilities, included among the
respondents to the investigation, are fully cooperating in the
investigation and believe that the CPUC will ultimately determine that
they were not responsible for the high border prices during this
period. On August 1, 2003, the Administrative Law Judge (ALJ) issued a
revised schedule with hearings scheduled to begin in March 2004 and
with a Commission decision by late 2004.

CPUC INVESTIGATION OF COMPLIANCE WITH AFFILIATE RULES

On February 27, 2003, the CPUC opened an investigation of the business
activities of SDG&E, SoCalGas and Sempra Energy to ensure that they
have complied with relevant statutes and CPUC decisions in the
management, oversight and operations of their companies. On September
18, 2003, the Commission suspended the procedural schedule until the
CPUC completes an independent audit to evaluate energy-related business
activities undertaken by Sempra Energy within the service territories
of SDG&E and SoCalGas, relative to holding company systems and
affiliate activities. The audit will be combined with the annual
affiliate audit and should be completed by the end of 2004. The scope
of the audit will be broader than the annual affiliate audit. In
addition to an evaluation of compliance with CPUC rules and
requirements, this audit will assess the potential for conflicts
between the interests of Sempra Energy and the interests of the
California Utilities and their ratepayers, and examine whether business
activities undertaken by the utilities and/or their holding company and
affiliates pose potential problems or unjust or unreasonable impacts on
utility customers.

COST OF SERVICE FILING

As previously reported, the California Utilities have filed cost of
service applications with the CPUC seeking rate increases designed to
reflect forecasts of 2004 capital and operating costs. The California
Utilities are requesting revenue increases of approximately $121
million. The CPUC's Office of Ratepayer Advocates (ORA) filed its
prepared testimony in the applications on August 8, 2003, recommending
rate decreases that would reduce annual revenues by $162 million from
their current level. UCAN has proposed rates for SDG&E and The Utility
Reform Network (TURN) has proposed rates for SoCalGas that would reduce
annual revenues by $88 million and $178 million, respectively, from
their current level. Hearings are expected to conclude by the end of
this month. The procedural schedule for the cost of service
applications permits a decision as early as March 2004, and the
California Utilities have filed a petition for interim rate relief for
the period from January 1, 2004 until the effective date of the
decision. On November 3, 2003, the CPUC ALJ released a Proposed
Decision that would authorize the California Utilities to create a
memorandum account as of January 1, 2004, to record the difference
between existing rates and those that are later authorized in the
Commission's final decision in this case. The difference would then be
amortized in rates. The full Commission can vote on the Proposed
Decision as soon as December 4, 2003. The California Utilities have
also filed for continuation through 2004 of existing PBR mechanisms for
service quality and safety that would otherwise expire at the end of
2003.

MARKET INDEXED CAPITAL ADJUSTMENT MECHANISM (MICAM)

MICAM has the potential to revise a utility's rates to reflect changes
in market interest rates. On September 4, 2003, the CPUC approved an
all-party settlement that modified the MICAM such that the possibility
of a MICAM-caused reduction in SDG&E's authorized return on common
equity for 2004 has been eliminated.

PERFORMANCE-BASED REGULATION (PBR)

On August 21, 2003, the CPUC issued a final resolution approving
SDG&E's 2001 and 2002 Distribution PBR Performance Reports. SDG&E was
awarded $12.2 million for exceeding PBR benchmarks on all six of its
performance indicators in 2001, and $6.0 million for exceeding the PBR
benchmarks on five of its six performance indicators in 2002. These
rewards were included in income in the third quarter of 2003. The total
maximum reward (or penalty) SDG&E could earn in a given year under the
Distribution PBR mechanism is $14.5 million.

On July 16, 2003, SDG&E filed an Advice Letter requesting approval of a
shareholder penalty of $1.4 million for Year 9 (August 1, 2001 through
July 31, 2002) of its Gas Procurement PBR mechanism. The $1.4 million
penalty was recorded in 2002 and is consistent with the ORA's March 19,
2003 Monitoring and Evaluation Report on SDG&E's natural gas
procurement activities in Year 9. In its report, the ORA recommended
the extension of the PBR mechanism, as modified in Years 8 and 9, to
Year 10 and beyond, and stated that the CPUC's adoption of the natural
gas procurement PBR mechanism is beneficial both to ratepayers and to
shareholders of SDG&E.

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

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

GAS COST INCENTIVE MECHANISM (GCIM)

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

On August 21, 2003, the CPUC approved SoCalGas' GCIM Years 7 and 8
shareholder rewards of $30.8 million and $17.4 million, respectively,
subject to refund or adjustment as determined by the Commission in the
Border Price Investigation described above. These rewards have been
included in income in the third quarter of 2003.

On June 16, 2003, SoCalGas filed an application with the CPUC
requesting a $6.3 million shareholder reward for GCIM Year 9 (April 1,
2002 through March 31, 2003). The company's natural gas purchasing
activities resulted in a net savings of $32.7 million to ratepayers
during Year 9, which led to the requested shareholder reward. This
application is pending before the CPUC, with approval expected in the
first half of 2004.

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

DEMAND SIDE MANAGEMENT (DSM) AND ENERGY EFFICIENCY AWARDS

Since the 1990s, IOUs have been eligible to earn awards for
implementing and administering energy conservation and efficiency
programs. The California Utilities have offered these programs to
customers and have consistently achieved significant earnings
therefrom. On October 16, 2003, the CPUC issued a decision that the
pre-1998 DSM earnings mechanism would not be reopened. Therefore, the
CPUC will not redetermine the uncollected portion of past awards earned
by the IOUs and will not be recomputing the amounts of the awards, but
may adjust such amounts consistent with the application of known,
standard measurement and verification protocols.

The CPUC has consolidated the 2000, 2001, 2002 and 2003 award
applications. On May 2, 2003, the CPUC released an RFP to conduct a
review of the IOUs' studies used as the basis for the awards claims.
The review should be completed by the second quarter of 2004. All
outstanding claims are on hold pending completion of the independent
review. As of September 30, 2003, the California Utilities had $46
million in DSM/energy efficiency rewards requested but pending CPUC
approval and had $29 million in rewards for which it has not yet
requested approval.

BLYTHE GAIN ON SALE

The ORA is proposing to use a risk analysis to allocate the 2001 gain
on the sale of SDG&E's surplus property in Blythe, California rather
than the time in rate base versus out of rate base methodology proposed
by SDG&E and historically used by the CPUC. SDG&E's proposal would
allocate $3.1 million to ratepayers, whereas the ORA proposes to
allocate $14.4 million. This issue is being addressed in the Cost of
Service filing described above. A decision is expected as early as
March 2004.

TRANSMISSION RATE INCREASE

SDG&E's retail-related rates applicable to transmission service were
set based on a 1998 test year, at a level that during 2002 was
substantially lower than needed to maintain an adequate return on
equity (ROE). Consequently, SDG&E filed revised rates on March 7,
2003, proposing a formula rate that would allow, through June 2007, the
full recovery of all transmission-related rate base and expenses on a
trued-up basis. Thus, SDG&E would earn no more nor no less than its
transmission cost of service at the FERC-adopted ROE for the
predetermined period. On May 2, 2003, the FERC accepted SDG&E's request
for modification of its Transmission Owner Tariff to adopt a rate
increase, subject to hearing and, if appropriate, refunds. New
transmission rates, which are subject to refund based on the FERC's
final order, became effective October 1, 2003.

On October 9, 2003, SDG&E filed a proposed settlement agreement with
the FERC, supported by the FERC trial staff, the CPUC and the
Independent System Operator (ISO). As a result of the settlement,
SDG&E's ROE would be 11.25 percent, rather than the 13 percent SDG&E
requested. SDG&E's revenue requirements for its retail and wholesale
customers for the initial 12-month period beginning October 1, 2003,
would be $142.1 million and $135.6 million, respectively, rather than
the $149.5 million and $143.7 million requested. The settlement
contemplates that SDG&E will fully recover its cancelled Valley-Rainbow
Project costs of $19 million over a ten-year amortization period
without interest. The transmission rate formula is to be in effect
through June 30, 2007. A final decision is not expected before late
November 2003.

In August 2002 the FERC issued Opinion No. 458, which effectively
disallowed SDG&E's recovery of the differentials between certain costs
paid to SDG&E under existing transmission contracts (the Participation
Agreements) and charges assessed to SDG&E under the ISO FERC tariff for
transmission line losses and grid management charges related to its
Southwest Powerlink. SDG&E had previously been recovering these costs
by charging them through the Transmission Revenue Balancing Account,
but Opinion No. 458 rejected this approach and required SDG&E to refund
the cost differentials so recovered. SDG&E's request for rehearing was
denied. As a result, SDG&E is incurring unreimbursed costs of $4
million to $8 million per year. SDG&E has petitioned the United States
Court of Appeals for review of these FERC orders and has submitted to
the FERC a refund plan which would refund $21 million to transmission
customers via the Transition Cost Balancing Account. This refund
arrangement is subject to FERC acceptance, which is pending. In
addition, SDG&E is challenging the propriety of the ISO charges as
applied to the portions of the Southwest Powerlink jointly owned with
Arizona Public Service Co. and the Imperial Irrigation District in
proceedings before the FERC, and in an arbitration under the ISO
tariff. On October 27, 2003, an independent arbitrator found in SDG&E's
favor on this matter. The ISO has the right to appeal this result to
the FERC. To the extent SDG&E prevails in these matters, the FERC may
require the ISO to refund to SDG&E all or part of the costs. SDG&E has
also commenced a private arbitration to reform the Participation
Agreements to remove prospectively SDG&E's obligation to provide
services giving rise to unreimbursed ISO tariff charges.

FERC ACTIONS

DWR Contract

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

Refund Proceedings

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

In December 2002, a FERC ALJ issued preliminary findings indicating
that the California PX and ISO owe power suppliers $1.2 billion (the
$3.0 billion that the California PX and ISO still owe energy companies
less $1.8 billion that the energy companies charged California
customers in excess of the preliminarily determined competitive market
clearing prices). On March 26, 2003, the FERC largely adopted the ALJ's
findings, but expanded the basis for refunds by adopting a staff
recommendation from a separate investigation to change the natural gas
proxy component of the mitigated market clearing price that is used to
calculate refunds. The March 26 order estimates that the replacement
formula for estimating natural gas prices will increase the refund
obligations from $1.8 billion to more than $3 billion. The FERC
recently released its final instructions, and the ISO and PX have five
months to recalculate the precise number through their settlement
models. California is seeking $8.9 billion in refunds and has appealed
the FERC's preliminary findings and requested rehearing of the March 26
order. SET and other power suppliers have joined in appeal of the
FERC's preliminary findings and requested rehearing.

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

Manipulation Investigation

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

On June 25, 2003, the FERC issued several orders requiring various
entities to show cause why they should not be found to have violated
California ISO and PX tariffs. First, FERC directed 43 entities,
including SET and SDG&E, to show cause why they should not disgorge
profits from certain transactions between January 1, 2000 and June 20,
2001 that are asserted to have constituted gaming and/or anomalous
market behavior under the California ISO and/or PX tariffs. Second, the
FERC directed more than 20 entities, including SET, to show cause why
their activities during the period January 1, 2000 to June 20, 2001
through partnerships, alliances or other arrangements did not
constitute gaming and/or anomalous market behavior in violation of the
tariffs. Remedies for confirmed violations could include disgorgement
of profits and revocation of market-based rate authority. The FERC has
encouraged the entities to settle the issues. SET has had such
discussions with the FERC staff. On October 31, 2003, SET agreed to pay
$7.2 million in full resolution of these investigations. The entire
amount has been recorded as of September 30, 2003. The agreement is
subject to final approval by the FERC and could be decided as early as
December 2003. SDG&E agreed to pay $28 thousand into a FERC-established
fund on behalf of customers in order to bring its case to closure. FERC
approval is pending.

On June 25, 2003, the FERC also determined that it was appropriate to
initiate an investigation into possible physical and economic
withholding in the California ISO and PX markets. For this purpose,
FERC used an initial screen of $250 per MW for all bids between May 1,
2000 and October 2, 2000. Both SDG&E and SET received data requests
from the FERC staff and have provided responses. FERC staff will
prepare a report to the Commission, which will be the basis to decide
whether additional proceedings are warranted. SET and SDG&E believe
that their bids and bidding procedures were consistent with ISO and PX
tariffs and protocols and applicable FERC price caps. On August 1,
2003, FERC staff issued an initial report that determined there was no
need to further investigate particular entities, including SET, for
physical withholding of generation.

Price Reporting Practices

On September 26, 2003, FERC sent a survey to 266 companies concerning
natural gas and electric price reporting practices. The survey is
being conducted in support of FERC's "Policy Statement on Natural Gas
and Electric Price Indices" issued in July 2003, to measure industry
progress in voluntary reporting of energy trade data to publishers of
energy price indices. Responses to the survey were provided on behalf
of SoCalGas, SDG&E and SET, and jointly by SER and SES. A second
survey is expected to be conducted in March 2004 in FERC's continuing
effort to monitor energy price reporting. The Commodity Futures Trading
Commission is also inquiring of numerous companies, including SET, as
to possible price reporting discrepancies.

NUCLEAR INSURANCE

SDG&E and the other co-owners of SONGS have insurance to respond to any
nuclear liability claims related to SONGS. The insurance policy
provides $300 million in coverage, which is the maximum amount
available. The Price-Anderson Act provides for up to $10.6 billion of
secondary financial protection if the liability loss exceeds the
insurance limit. Should any of the licensed/commercial reactors in the
United States experience a nuclear liability loss which exceeds the
$300 million insurance limit, all utilities owning nuclear reactors
could be assessed under the Price-Anderson Act to provide the secondary
financial protection. SDG&E and the other co-owners of SONGS could be
assessed up to $201 million under the Price-Anderson Act. SDG&E's share
would be $40 million unless default occurs by any other SONGS co-owner.
In the event the secondary financial protection limit is insufficient
to cover the liability loss, Congress could impose an additional
assessment on all licensed reactor operators.

SDG&E and the other co-owners of SONGS have $2.75 billion of nuclear
property, decontamination and debris removal insurance. The coverage
also provides the SONGS owners up to $490 million for outage expenses
incurred because of accidental property damage. This coverage is
limited to $3.5 million per week for the first 52 weeks, and $2.8
million per week for up to 110 additional weeks. Coverage is also
provided for the cost of replacement power, which includes indemnity
payments for up to three years, after a waiting period of 12 weeks. The
insurance is provided through a mutual insurance company owned by
utilities with nuclear facilities. Under the policy's risk sharing
arrangements, SDG&E could be assessed up to $7.4 million if losses at
any covered facility exceed the insurance company's surplus and
reinsurance funds.

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

ARGENTINE INVESTMENTS

During the third quarter of 2003, SEI recorded a $4 million negative
adjustment to Accumulated Other Comprehensive Income (Loss), resulting
in a net positive adjustment of $29 million for the nine months ended
September 30, 2003. The net $29 million change reflected the increase
in the value of the Argentine peso relative to the U.S. dollar.

As of September 30, 2003, SEI has adjusted its investment in its two
unconsolidated Argentine subsidiaries downward by $194 million as a
result of the devaluation of the Argentine peso since early 2002. On
September 6, 2002, SEI initiated proceedings under the 1994 Bilateral
Investment Treaty between the United States and Argentina for recovery
of the diminution of the value of its investments resulting from
Argentine governmental actions. SEI made a request for arbitration to
the International Centre for Settlement of Investment Disputes (ICSID)
and all arbitrators have been selected. A preliminary hearing was held
on July 3, 2003, establishing a timeline for arbitration. On September
4, 2003, SEI filed its legal brief with ICSID outlining its claims in
more detail and is now awaiting a response from the Argentine
government. A decision is expected in late 2004.

LITIGATION

During the third quarter of 2003, the company recorded additional
charges against income for litigation costs and possible resolution of
certain cases. Management believes that none of these matters will have
further material adverse effect on the company's financial condition or
results of operations. Except for the matters referred to below,
neither the company nor its subsidiaries are party to, nor is their
property the subject of, any material pending legal proceedings other
than routine litigation incidental to their businesses.

DWR Contract

In May 2003, the San Diego Superior Court granted SER's motion for
summary judgment in its complaint for declaratory judgment regarding
its contract with the DWR (and the DWR's cross-complaint seeking to
void the 10-year energy-supply contract). In the judgment, the court
determined that "(a) Sempra is entitled to provide electrical energy
from any source, including Market Sources, (b) Sempra is not in breach
of the Agreement as framed by the pleadings in this matter, (c) DWR is
obligated to take delivery and pay for deliveries under the Agreement,
and (d) Sempra has no obligation to complete any specific Project."
Judgment was entered in SER's favor on August 14, 2003. On August 27,
2003, the DWR filed a motion for a new trial claiming irregularities in
the Court's judgment. On October 15, 2003, the Court clarified its
earlier summary judgment ruling and effectively denied the motion for
new trial. The DWR has filed a notice of appeal on the August 14, 2003
judgment and the October 15, 2003 orders by the Court. The DWR
continues to accept all scheduled power from SER and, although it has
disputed billings in an immaterial amount and the manner of certain
deliveries, it has made all payments that have been billed under the
contract.

Antitrust Litigation

Lawsuits filed in 2000 and currently consolidated in San Diego Superior
Court seek class-action certification and damages, alleging that Sempra
Energy, SoCalGas and SDG&E, along with El Paso Energy Corp. (El Paso)
and several of its affiliates, unlawfully sought to control natural gas
and electricity markets. In March 2003, plaintiffs in these cases and
the applicable El Paso entities announced that they had reached a $1.5
billion settlement, of which $125 million is allocated to customers of
the California Utilities. The proceeding against Sempra Energy and the
California Utilities has not been settled and continues to be
litigated.

Natural Gas Cases: Similar lawsuits have been filed by the Attorney
General of Arizona and the Attorney General of Nevada alleging that El
Paso and certain Sempra Energy subsidiaries unlawfully sought to
control the natural gas market in their respective states. In April
2003, Sierra Pacific Resources and its utility subsidiary Nevada Power
filed a lawsuit in U.S. District Court in Las Vegas against major
natural gas suppliers, including Sempra Energy, the California
Utilities and other company subsidiaries, seeking damages resulting
from an alleged conspiracy to drive up or control natural gas prices,
eliminate competition and increase market volatility, breach of
contract and wire fraud.

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

Price Reporting Practices

In the fourth quarter of 2002, Sempra Energy and SoCalGas were named as
defendants in a lawsuit filed in Los Angeles Superior Court against
various trade publications and other energy companies alleging that
energy prices were unlawfully manipulated by defendants' reporting
artificially inflated natural gas prices to trade publications. On July
8, 2003, the Superior Court granted the defendants' demurrer on the
grounds that the claims contained in the complaint were subject to the
Filed Rate Doctrine and were preempted by the Federal Power Act.
Plaintiffs have filed an amended complaint, and in September 2003
defendants filed a demurrer to the amended complaint. In May 2003, a
similar action was filed in San Diego Superior Court against Sempra
Energy and SET, and has been removed to Federal District Court. In
addition, in August 2003, a lawsuit was filed in the Southern District
of New York against Sempra Energy and SES, alleging that the prices of
natural gas options traded on the NYMEX were unlawfully increased under
the federal Commodity Exchange Act by defendants' manipulation of
transaction data to natural gas trade publications.

Other

SER was a defendant in an action brought by Occidental Energy Ventures
Corporation (Occidental) with respect to the Elk Hills power project
being jointly developed by the two companies. On September 30, 2003,
the arbitration proceeding found in favor of SER, determining that SER
had not breached its joint development contract with Occidental.

In May 2003, a Federal judge issued an order finding that the U.S.
Department of Energy's (DOE) abbreviated assessment of two Mexicali
power plants, including SER's Termoelectrica de Mexicali (TDM) plant,
failed to evaluate the plants' environmental impact adequately and
called into question the U.S. permits they received to build their
cross-border transmission lines. On July 8, 2003, the judge ordered the
DOE to conduct additional environmental studies and denied the
plaintiffs' request for an injunction blocking operation of the
transmission lines, thus allowing the continued operation of the TDM
plant. The DOE has until May 15, 2004, to demonstrate why the court
should not set aside the permits.

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

INCOME TAX ISSUES

Section 29 Income Tax Credits

Earlier in the year the Internal Revenue Service (IRS) issued
Announcement 2003-46, stating it has reason to question the scientific
validity of testing procedures and results related to Section 29 income
tax credits. The notice also announced that it would suspend the
issuance of new rulings until its review is complete and that rulings
could be revoked if the IRS did not determine that the test procedures
demonstrate a significant chemical change between the feedstock coal
and the synthetic fuel. The IRS has now completed its review and on
October 29, 2003, it announced that it will be issuing private letter
rulings based on the previous requirements. The Permanent Subcommittee
on Investigations of the U.S. Senate's Committee on Governmental
Affairs has expressed interest in investigating the issue.

As part of its recently commenced normal audit program for the company
for the period 1998-2001, the IRS notified the company of its intention
to audit the synthetic fuel operations of SET and SEF. Through
September 30, 2003, the company has recorded Section 29 income tax
credits of $224 million, including $28 million and $80 million during
the three months and nine months ended September 30, 2003,
respectively. The company believes retroactive disallowance of Section
29 income tax credits is unlikely.

Luz del Sur

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

Spanish Holding Company

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

Pending Internal Revenue Service Matters

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

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

RECENT SOUTHERN CALIFORNIA FIRES

Several major wildfires that began on October 26, 2003 severely damaged
some of SDG&E's infrastructure, causing a significant number of
customers to be without utility services. On October 27, 2003, Governor
Gray Davis declared a "state of emergency" for four counties, including
the County of San Diego and three counties within SoCalGas' service
territory.

The declaration of a state of emergency invokes Public Utilities Code
Section 454.9, which authorizes a public utility to establish a
catastrophic event memorandum account (CEMA) to record all costs
associated with (1) restoring utility services to customers; (2)
repairing, replacing or restoring damaged utility facilities and (3)
complying with governmental agency orders in connection with events
declared disasters by competent state or federal authorities.

The costs recorded in the CEMA are recoverable in rates separate from
ordinary costs currently recovered in rates. Public Utilities Code
Section 454.9 requires that the CPUC hold expedited hearings in
response to the utilities' request for recovery. SDG&E is recording
fire damage costs and the costs of restoring electric and natural gas
service in the CEMA account. SoCalGas is recording fire damage costs
and the costs of restoring natural gas service in the CEMA account,
although there has not been significant damage to the natural gas
system. Therefore, the company expects no significant effect on
earnings from the fires.

4. SEGMENT INFORMATION

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

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

- ---------------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
-----------------------------------------------
(Dollars in millions) 2003 2002 2003 2002
- ---------------------------------------------------------------------------
Operating Revenues:
Southern California Gas $ 794 $ 597 $ 2,622 $ 1,999
San Diego Gas & Electric 667 425 1,749 1,271
Sempra Energy Trading 304 178 832 576
Sempra Energy Resources 234 136 453 275
All other 74 56 206 244
Intersegment revenues (15) (7) (41) (17)
---------------------------------------------
Total $ 2,058 $ 1,385 $ 5,821 $ 4,348
- ---------------------------------------------------------------------------
Net Income (Loss):
Southern California Gas* $ 53 $ 56 $ 148 $ 167
San Diego Gas & Electric* 120 46 206 150
Sempra Energy Trading 22 10 39 73
Sempra Energy Resources 33 29 48 60
All other (17) 9 (26) (7)
-----------------------------------------------
Total $ 211 $ 150 $ 415 $ 443
- ---------------------------------------------------------------------------
* after preferred dividends

- ----------------------------------------------------------
Balance at
--------------------------
September 30, December 31,
2003 2002
- ----------------------------------------------------------
Assets:
Southern California Gas $ 3,823 $ 4,079
San Diego Gas & Electric 5,523 5,123
Sempra Energy Trading 5,212 5,614
Sempra Energy Resources 1,505 1,347
All other 2,725 2,580
Intersegment receivables (734) (986)
-------------------------
Total $ 18,054 $ 17,757
- ----------------------------------------------------------

5. FINANCIAL INSTRUMENTS

Note 10 of the notes to Consolidated Financial Statements in the Annual
Report discusses the company's financial instruments, including the
adoption of SFAS 133, "Accounting for Derivative Instruments and
Hedging Activities," as amended by SFAS 138, "Accounting for Certain
Derivative Instruments and Certain Hedging Activities" and SFAS 149,
"Amendment of Statement 133 on Derivative Instruments and Hedging
Activities". The effect is to recognize all derivatives as assets or
liabilities on the balance sheet, measure those instruments at fair
value, and recognize any changes in fair value in earnings for the
period that the change occurs unless the derivative qualifies as an
effective hedge that offsets other exposures.

The company utilizes derivative financial instruments to manage its
exposure to unfavorable changes in commodity prices, which are subject
to significant and often volatile fluctuations. Derivative financial
instruments include futures, forwards, swaps, options and long-term
delivery contracts. These contracts allow the company to predict with
greater certainty the effective prices to be received or paid by the
company and, in the case of the California Utilities, their customers.
In accordance with SFAS 133, the California Utilities have elected to
account for contracts that are settled by physical delivery at
historical cost, with gains and losses reflected in the income
statement at the contract settlement date.

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

Energy transportation and storage contracts entered into by the company
on or after October 25, 2002 are recorded at cost. Energy commodity
inventory is being recorded at the lower of cost or market. The
company's base metals and concentrates inventory continue to be
recorded at fair value in accordance with Accounting Research Bulletin
Number 43. On January 1, 2003, as a result of the rescission of EITF
98-10, SET and SES recorded a cumulative effect of a change in
accounting principle, which reduced after-tax earnings by $29 million,
related to the non-derivative contracts and certain physical inventory
that were recorded at fair value under EITF 98-10 but are not covered
by SFAS 133. This did not impact cash flow or liquidity.

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

September 30, December 31,
(Dollars in millions) 2003 2002
- --------------------------------------------------------------------------
TRADING ASSETS:
Unrealized gains on swaps and forwards $ 1,207 $ 1,226
OTC commodity options purchased 405 480
Due from trading counterparties 1,000 1,279
Due from commodity clearing organizations
and clearing brokers 109 49
Resale agreements 10 --
Commodities owned 1,867 1,968
------ ------
Total trading assets $ 4,598 $ 5,002
====== ======

TRADING LIABILITIES:
Unrealized losses on swaps and forwards $ 1,038 $ 816
OTC commodity options written 271 569
Due to trading counterparties 1,140 1,196
Repurchase obligations 1,363 1,511
Commodities not yet purchased 52 --
------ ------
Total trading liabilities $ 3,864 $ 4,092
====== ======

Fixed-price contracts and other derivatives on the Consolidated Balance
Sheets primarily reflect the California Utilities' derivative gains and
losses related to long-term delivery contracts for purchased power and
natural gas transportation. The California Utilities have established
regulatory assets and liabilities to the extent that these gains and
losses are recoverable or payable through future rates. Other
significant derivatives recorded on the balance sheet include a fixed-
to-floating interest rate swap agreement and a contingent purchase
price obligation arising from the company's acquisition of the proposed
Cameron LNG project. Payments under the swap agreement and changes in
interest rate (LIBOR) are reflected as adjustments to long-term debt.
The contingent payments under the proposed LNG project purchase
obligation are included in property, plant and equipment. The changes
in fixed-price contracts and other derivatives on the Consolidated
Balance Sheets for the nine months ended September 30, 2003 were
primarily due to the contingent purchase price obligation arising from
the company's acquisition of the proposed Cameron LNG project,
partially offset by physical deliveries under long-term purchased-power
and natural gas transportation contracts. The transactions associated
with fixed-price contracts and other derivatives had no material impact
to the Statements of Consolidated Income for the nine months ended
September 30, 2003 or 2002.

ITEM 2.

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

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

RESULTS OF OPERATIONS

California Utility Revenues and Cost of Sales

Natural gas revenues increased to $3.0 billion for the nine months
ended September 30, 2003 from $2.3 billion for the corresponding period
in 2002, and the cost of natural gas increased to $1.5 billion in 2003
from $945 million in 2002. Additionally, natural gas revenues increased
to $870 million for the three months ended September 30, 2003 from $658
million for the corresponding period in 2002, and the cost of natural
gas increased to $372 million in 2003 from $216 million in 2002. These
changes were primarily attributable to approved performance awards
recognized during the third quarter of 2003, as well as natural gas
price increases (which are passed on to customers) partially offset by
reduced volumes. See discussion of performance awards in Note 3 of the
notes to Consolidated Financial Statements.

Under the current regulatory framework, changes in core-market natural
gas prices for core customers (primarily residential and small
commercial and industrial customers) do not affect net income, since
core-customer rates generally recover the actual cost of natural gas on
a substantially concurrent basis and are fully balanced. However,
SoCalGas' GCIM allows SoCalGas to share in the savings or costs from
buying natural gas for customers below or above monthly benchmarks. The
mechanism permits full recovery of all costs within a tolerance band
above the benchmark price and refunds all savings within a tolerance
band below the benchmark price. The costs or savings outside the
tolerance band are shared between customers and shareholders. In
addition, SDG&E's gas procurement PBR mechanism provides an incentive
mechanism by measuring SDG&E's procurement of natural gas against a
benchmark price comprised of monthly natural gas indices, resulting in
shareholder rewards for costs achieved below the benchmark and
shareholder penalties when costs exceed the benchmark.

Electric revenues increased to $1.4 billion for the nine months ended
September 30, 2003 from $962 million for the same period in 2002, and
the cost of electric fuel and purchased power increased to $428 million
in 2003 from $221 million in 2002. Additionally, electric revenues
increased to $576 million for the three months ended September 30, 2003
from $358 million for the same period in 2002, and the cost of electric
fuel and purchased power increased to $128 million in 2003 from $81
million in 2002. These changes were mainly due to the effect of the
DWR's purchasing the net short position of SDG&E during 2002, increases
in electric commodity costs, the increase in authorized distribution
revenue and higher volumes in 2003, and, for the quarter, recognition
of $116 million related to the approved settlement of intermediate-term
purchase power contracts and higher earnings from PBR awards. Under the
current regulatory framework, changes in commodity costs do not affect
net income. The commodity costs associated with the DWR's purchases and
the corresponding sales to SDG&E's customers were not included in the
Statements of Consolidated Income as SDG&E was merely transmitting
electricity from the DWR to the customers without taking title to the
electricity. During 2003, costs associated with long-term contracts
allocated to SDG&E from the DWR were likewise not included in the
income statement, since the DWR retains legal and financial
responsibility for these contracts.

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

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

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

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

Other Operating Revenues

Other operating revenues, which consist primarily of revenues at
Global, increased to $1.5 billion for the nine months ended September
30, 2003 from $1.1 billion for the same period of 2002, and increased
to $612 million for the three-month period ended September 30, 2003
from $369 million for the corresponding period of 2002. These changes
were primarily due to higher revenues at SET as the result of increased
volumes and volatility in the energy commodity markets and increased
coal sales related to Section 29 income tax credits, and increased
revenues from SER. SER's higher revenues were primarily attributable to
higher sales of electricity to the DWR under the contract which
recommenced in April 2002, and sales by its Twin Oaks power plant
purchased in the fourth quarter of 2002.

Other Cost of Sales

Other cost of sales, which consists primarily of cost of sales at
Global, increased to $886 million for the nine months ended September
30, 2003 from $503 million for the corresponding period of 2002, and
increased to $371 million for the three months ended September 30, 2003
from $165 million for the same period in 2002. The increases were
primarily due to the higher sales at SER and the increased activity at
SET as noted above.

Other Operating Expenses

Other operating expenses increased to $1.6 billion for the nine months
ended September 30, 2003 from $1.3 billion for the same period in 2002.
Of the total balance, $1.1 billion and $975 million in 2003 and 2002,
respectively, represent other operating expenses at the California
Utilities. Other operating expenses increased to $668 million for the
three months ended September 30, 2003 from $424 million for the
corresponding period of 2002. Of the total balance, $423 million and
$334 million in 2003 and 2002, respectively, represent other operating
expenses at the California Utilities. The overall increase was due to
general increases at the California Utilities, primarily as a result of
a $64 million before-tax charge for litigation and for losses
associated with a sublease of portions of the SoCalGas headquarters
building. The non-recurring sublease losses pertain to pre-2003
transactions, but are charged against current operations because they
are not material to annual financial statements. In addition, general
operating costs increased at SER, SET and SEI, mainly due to a $77
million before-tax write-down of the carrying value of the assets of
Frontier Energy, a small North Carolina utility subsidiary, as a result
of reductions in actual and previously anticipated sales of natural gas
by the utility.

Other Income - Net

Other income, which primarily consists of equity earnings from
unconsolidated subsidiaries and interest on regulatory balancing
accounts, increased to $38 million for the nine months ended September
30, 2003 from $6 million for the nine months ended September 30, 2002.
The increase was primarily due to increased equity earnings from SEI
and other subsidiaries, offset partially by depressed results at SER's
joint ventures.

Other income increased to $34 million for the three months ended
September 30, 2003, from a net expense of $21 million for the
corresponding period of the prior year due primarily to increased
equity earnings from SER, SEI and other subsidiaries.

Income Taxes

Income tax expense decreased to $109 million for the nine months ended
September 30, 2003 from $143 million for the same period of 2002. The
effective income tax rates were 19.7 percent and 24.5 percent for the
nine-month periods ended September 30, 2003 and 2002, respectively. The
changes were primarily due to reduced pretax income and increased
income tax credits from synthetic fuel investments in 2003 (see
discussion of Section 29 credits in Note 3), offset partially by a $25
million favorable resolution of income-tax issues at SDG&E in the
second quarter of 2002.

Income tax expense decreased to $58 million for the third quarter of
2003 compared to $69 million for the third quarter of 2002, and the
effective income tax rate decreased to 21.6 percent from 31.5 percent.
These changes were due to increased income tax credits in 2003,
partially offset by higher pretax income.

In connection with its affordable-housing investments, the company has
unused tax credits dating back to 2000, which the company fully expects
to utilize before their various expiration dates of 2020 to 2023. At
September 30, 2003, the amount of these unused tax credits was $192
million. In addition, at September 30, 2003, the company has $73
million of alternative minimum tax credits with no expiration date.

Net Income

For the nine months ended September 30, net income decreased to $415
million, or $1.98 per diluted share of common stock, in 2003 from $443
million, or $2.15 per diluted share in 2002. Excluding the effects of
the cumulative effect of the changes in accounting principle in 2003
($0.14 per diluted share, discussed in Note 2 of the notes to
Consolidated Financial Statements) and the extraordinary item in 2002
associated with negative goodwill from SET's acquisitions of the metals
business ($0.01 per diluted share, discussed in the Annual Report),
income increased to $444 million in 2003 from $441 million in 2002.
The slight increase was due to the approved settlement of intermediate-
term purchase power contracts and the recognition of higher performance
awards, offset by the write-down of assets at Frontier Energy,
litigation and sublease losses as well as the $25 million income-tax
resolution in the second quarter of 2002.

Net income for the third quarter was $211 million, or $1.00 per diluted
share for 2003, compared to $150 million or $0.73 per diluted share in
2002. The increase was due primarily to the factors discussed above,
other than the $25 million income-tax resolution, as well as lower
income tax expense in 2003.

Net Income by Business Unit

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

SOUTHERN CALIFORNIA GAS COMPANY

SoCalGas recorded net income of $148 million and $167 million for the
nine-month periods ended September 30, 2003 and 2002, respectively, and
net income of $53 million and $56 million for the three-month periods
ended September 30, 2003 and 2002, respectively. The decreases were
primarily due to a $28 million after-tax charge for litigation and for
losses associated with a long-term sublease of portions of its
headquarters building, and the end of sharing of merger savings (which
positively impacted earnings by $13 million for the nine-month period
and $4 million for the three-month period in 2002). These factors were
partially offset by the after-tax recognition of $29 million in GCIM
awards in the third quarter of 2003. The non-recurring sublease losses
pertain to pre-2003 transactions, but are charged against current
operations because they are not material to annual financial
statements.

SAN DIEGO GAS & ELECTRIC

SDG&E recorded net income of $206 million and $150 million for the
nine-month periods ended September 30, 2003 and 2002, respectively, and
net income of $120 million and $46 million for the three-month periods
ended September 30, 2003 and 2002, respectively. The increases were
primarily due to income of $65 million after-tax related to the
approved settlement of intermediate-term purchase power contracts,
higher earnings from PBR awards, and higher transportation and
distribution revenue. These factors were partially offset by higher
operating expenses including litigation charges in the third quarter of
2003, and the end of sharing of the merger savings (which positively
impacted earnings by $6 million for the nine-month period and $2
million for the three-month period in 2002). Additionally, for the
nine-month period, the increases were offset by the $25 million benefit
from the favorable resolution of prior years' income-tax issues
recorded in the second quarter of 2002.

SEMPRA ENERGY TRADING

SET recorded net income of $39 million and $73 million for the nine-
month periods ended September 30, 2003 and 2002, respectively, and net
income of $22 million and $10 million for the three-month periods ended
September 30, 2003 and 2002, respectively. For purposes of comparison
with the corresponding 2002 periods, net income for the nine months and
three months ended September 30, 2003 would have been $70 million and
$9 million, respectively, if not for the repeal of EITF 98-10 as
described in Note 2 of the notes to Consolidated Financial Statements.
The repeal of EITF 98-10 adversely impacted SET's results by a
cumulative effect adjustment of $28 million and an additional $3
million related to operations for the nine months ended September 30,
2003, including a $13 million positive adjustment for the three months
ended September 30, 2003.

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

(Dollars in millions) 2003 2002
- -----------------------------------------------------------------
Balance at beginning of period $ 180 $ 405
Cumulative effect adjustment (48) --
Additions 833 355
Realized (552) (313)
------------------------------------
Balance at September 30 $ 413 $ 447
====================================

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

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

The following table summarizes the counterparty credit quality for SET.
These amounts are net of collateral in the for