SOUTHERN CALIFORNIA GAS CO - 10-Q Quarterly Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q
(Mark One)
[..X..] Quarterly report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934
September 30, 2004
For the quarterly period ended.......................................
Or
[.....] Transition report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934

For the transition period from ________________ to _________________

Commission Name of Registrant, State of IRS Employer
File Incorporation, Address and Identification
Number Telephone Number Number
- ---------- ---------------------------------- --------------
1-40 Pacific Enterprises 94-0743670
(A California Corporation)
101 Ash Street
San Diego, California 92101
(619) 696-2020

1-1402 Southern California Gas Company 95-1240705
(A California Corporation)
555 West Fifth Street
Los Angeles, California 90013
(213) 244-1200

No Change
- -----------------------------------------------------------------------
Former name, former address and former fiscal year, if changed since
last report

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

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

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:

Pacific Enterprises Wholly owned by Sempra Energy

Southern California Gas Company Wholly owned by Pacific Enterprises

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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," "could," "would" and "should" or similar expressions, or
discussions of strategy or of plans are intended to identify forward-
looking statements. Forward-looking statements are not guarantees of
performance. They involve risks, uncertainties and assumptions. Future
results may differ materially from those expressed in these forward-
looking statements.

Forward-looking statements are necessarily based upon various
assumptions involving judgments with respect to the future and other
risks, including, among others, local, regional and national economic,
competitive, political, legislative and regulatory conditions and
developments; actions by the California Public Utilities Commission,
the California Legislature, and the Federal Energy Regulatory
Commission and other regulatory bodies in the United States; capital
market conditions, inflation rates, interest rates and exchange rates;
energy and trading markets, including the timing and extent of changes
in commodity prices; the availability of natural gas; weather
conditions and conservation efforts; war and terrorist attacks;
business, regulatory, environmental and legal decisions and
requirements; 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 companies. 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 companies' business described in this
report and other reports filed by the companies from time to time with
the Securities and Exchange Commission.

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

PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions)

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PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions)

5

PACIFIC ENTERPRISES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

6

PACIFIC ENTERPRISES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

7

PACIFIC ENTERPRISES AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)

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SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions)

9

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions)

10

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

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SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)

12

SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)

13

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1. GENERAL

This Quarterly Report on Form 10-Q is that of Pacific Enterprises (PE)
and of Southern California Gas Company (SoCalGas)(collectively referred
to as the company or the companies). PE's common stock is wholly owned
by Sempra Energy, a California-based Fortune 500 holding company, and
PE owns all of the common stock of SoCalGas. The financial statements
herein are, in one case, the Consolidated Financial Statements of PE
and its subsidiary SoCalGas, and, in the other, the Consolidated
Financial Statements of SoCalGas and its subsidiaries, which comprise
less than one percent of SoCalGas' consolidated financial position and
results of operations.

Sempra Energy also indirectly owns all of the common stock of San Diego
Gas & Electric (SDG&E). SoCalGas and SDG&E are collectively referred to
herein as "the California Utilities."

The accompanying Consolidated Financial Statements have been prepared
in accordance with the interim-period-reporting requirements of Form
10-Q. Results of operations for interim periods are not necessarily
indicative of results for the entire year. In the opinion of
management, the accompanying statements reflect all adjustments
necessary for a fair presentation. These adjustments are only of a
normal recurring nature. Certain changes in classification have been
made to prior presentations to conform to the current financial
statement presentation. Specifically, certain December 31, 2003 income
tax liabilities have been reclassified from Deferred Income Taxes to
current Income Taxes Payable and to Deferred Credits and Other
Liabilities to conform to the current presentation of these items.

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

The companies' 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.

For the quarters and nine months ended September 30, 2004 and 2003,
comprehensive income was equal to earnings applicable to common shares.

SoCalGas accounts for the economic effects of regulation on utility
operations in accordance with Statement of Financial Accounting
Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of
Regulation.

NOTE 2. NEW ACCOUNTING STANDARDS

Stock-Based Compensation: On March 31, 2004, the Financial Accounting
Standards Board (FASB) issued a proposed Exposure Draft to amend SFAS
123, Accounting for Stock-Based Compensation. The proposed statement
would eliminate the choice of accounting for share-based compensation
transactions using Accounting Principles Board (APB) Opinion No. 25,

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Accounting for Stock Issued to Employees, whereby no expense is
recorded for most stock options, and instead would require that such
transactions be accounted for using a fair-value-based method, whereby
expense is recorded for stock options. It would also prohibit
application by restating prior periods and would require that expense
ultimately be recognized only for those options that actually vest. A
final statement is expected to be issued in the fourth quarter of 2004
and be effective July 1, 2005.

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

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

Note 5 of the notes to Consolidated Financial Statements in the Annual
Report discusses the company's expected contribution to its pension
plan and other postretirement benefit plans in 2004. For the nine
months ended September 30, 2004, $3 million and $38 million of
contributions have been made to its pension plan and other
postretirement benefit plans, respectively. $11 million of
contributions have been made to its other postretirement benefit plans
but no contribution was made to its pension plan for the quarter ended
September 30, 2004.

FASB Staff Position (FSP) 106-2, "Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003": In December 2003, the Medicare Prescription
Drug, Improvement and Modernization Act of 2003 (the "Act") was
enacted. The Act establishes a prescription drug benefit under
Medicare, known as "Medicare Part D," and a tax-exempt federal subsidy
to sponsors of retiree health care benefit plans that provide a benefit
that actuarially is at least equivalent to Medicare Part D.

In May 2004, the FASB issued FSP 106-2 which requires that the effects
of the federal subsidy be considered an actuarial gain and be
recognized in the same manner as other actuarial gains and losses. In
addition, FSP 106-2 requires certain disclosures for employers that
sponsor postretirement health care plans that provide prescription drug
benefits. During the third quarter of 2004, the company adopted FSP
106-2 retroactive to the beginning of the year. The company and its
actuarial advisors determined that benefits provided to certain
participants will actuarially be at least equivalent to Medicare Part
D, and, accordingly, the company will be entitled to an expected tax-
exempt subsidy that reduces the company's accumulated postretirement
benefit obligation under the plan at January 1, 2004 by $94 million and
net periodic benefit cost for 2004 by $12 million.

The net periodic postretirement benefit costs for the three and nine
months ended September 30, 2004 were reduced by $9 million, before
regulatory adjustments, to reflect the expected subsidy as a result of
the Act.

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The following tables provide the impact of the Act on components of net
periodic postretirement benefit costs. The three-month period includes
the entire nine-month subsidy since none of the subsidy was recorded
until the third quarter.

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

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

Balance as of January 1, 2004 $ 11
Accretion expense (interest) --
------
Balance as of September 30, 2004 $ 11*
======
* The current portion of the obligation is included in Other Current
Liabilities on the Consolidated Balance Sheets.

In June 2004, the FASB issued a proposed interpretation, Accounting for
Conditional Asset Retirement Obligations, an interpretation of FASB
Statement No. 143. The interpretation would clarify that a legal
obligation to perform an asset retirement activity that is conditional
on a future event is within the scope of SFAS 143. Accordingly, the
interpretation would require an entity to recognize a liability for a
conditional asset retirement obligation if the liability's fair value
can be reasonably estimated. The proposed interpretation would be
effective for the company on December 31, 2005.

SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": Effective July 1, 2003, SFAS 149 amended and
clarified accounting for derivative instruments and for hedging
activities under SFAS 133. Under SFAS 149, natural gas forward
contracts that are subject to unplanned netting generally do not
qualify for the normal purchases and normal sales exception, whereby
derivatives are not required to be marked to market when the contract
is usually settled by the physical delivery of natural gas. ("Netting"
refers to contract settlement by paying or receiving the monetary
difference between the contract price and the market price at the date
on which physical delivery would have occurred.) The company has
determined that all natural gas contracts are subject to unplanned
netting and as such, these contracts are marked to market.
Implementation of SFAS 149 did not have a material impact on reported
net income. Additional information on derivative instruments is
provided in Note 3.

FASB Interpretation No. (FIN) 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees": The company has a residual
value guarantee under a fleet lease arrangement. As of September 30,
2004, the company had no liabilities recorded for the fleet lease
guarantee due to the immaterial amount of the estimated fair value of
such guarantee.

NOTE 3. FINANCIAL INSTRUMENTS

As described in Note 7 of the notes to Consolidated Financial
Statements in the Annual Report, the company follows the guidance of
SFAS 133 as amended by SFAS 138 and 149 (collectively SFAS 133) to
account for its derivative instruments and hedging activities.
Derivative instruments and related hedged items are recognized as
either assets or liabilities on the balance sheet, measured at fair
value.

SFAS 133 provides for hedge accounting treatment when certain criteria
are met. For derivative instruments designated as fair value hedges,

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the gain or loss is recognized in earnings in the period of change
together with the offsetting gain or loss on the hedged item
attributable to the risk being hedged. For derivative instruments
designated as cash flow hedges, the effective portion of the derivative
gain or loss is included in Other Comprehensive Income, but not
reflected in the Statements of Consolidated Income until the
corresponding hedged transaction is settled. Any ineffective portion is
reported in earnings immediately.

The company utilizes natural gas derivatives to manage commodity price
risk associated with servicing its load requirements. These contracts
allow the company to predict with greater certainty the effective
prices to be received or paid by the company and the prices to be
charged to its customers. The company also periodically enters into
interest-rate swap agreements to moderate exposure to interest-rate
changes and to lower the overall cost of borrowing. The use of
derivative financial instruments is subject to certain limitations
imposed by company policy and regulatory requirements.

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

Fixed-price Contracts and Other Derivatives

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

The changes in Fixed-price Contracts and Other Derivatives on the
Consolidated Balance Sheets for the nine months ended September 30,
2004 were primarily due to physical deliveries under long-term 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, 2004 and 2003.

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NOTE 4. REGULATORY MATTERS

NATURAL GAS MARKET OIR

The CPUC's Natural Gas Market Order Instituting Rulemaking (OIR) was
instituted on January 22, 2004, and will be addressed in two phases. A
decision on Phase I was issued on September 2, 2004 and the schedule
for Phase II calls for a decision by the end of 2004. Further
discussion of Phase I and Phase II is included in the Annual Report.
The focus of the Gas OIR is the period from 2006 to 2016. Since Natural
Gas Industry Restructuring (GIR), as discussed in the Annual Report,
would end in August 2006 and there is overlap between GIR and the OIR
issues, a number of parties (including SoCalGas) have requested the
CPUC not to implement GIR.

The California Utilities have made comprehensive filings in the OIR
outlining a proposed market structure that is intended to create access
to new natural gas supply sources (such as liquefied natural gas (LNG))
for California. In their Phase I and Phase II filings, SoCalGas and
SDG&E proposed a framework to provide firm tradable access rights for
intrastate natural gas transportation; provide SoCalGas with continued
balancing account protection for intrastate transmission and
distribution revenues, thereby eliminating throughput risk; and
integrate the transmission systems of SoCalGas and SDG&E so as to have
common rates and rules. The California Utilities also proposed that the
capital expenditures necessary to access new sources of supply be
included in ratebase and that the total amount of the expenditures
would be $200 million to $300 million.

The California Utilities also proposed a methodology and framework to
be used by the CPUC for granting pre-approval of new interstate
transportation agreements. The Phase I decision approves the California
Utilities' transportation capacity pre-approval procedures with some
modifications. SoCalGas' existing pipeline capacity contract with
Transwestern Pipeline Company expires in November 2005 and its primary
contracts with El Paso Natural Gas Company expire in August 2006.
Discussions are underway pursuant to the framework approved by the CPUC
to acquire replacement capacity. The Phase I decision also directs the
California Utilities to file, by December 2, 2004, an application to
implement proposals for transmission system integration, firm access
rights, and off-system delivery services. The CPUC has determined that
project developers, not the utilities, will be presumed to pay for the
costs for access-related infrastructure, subject to future applications
to be filed when more is known about the particular projects. Phase II
of the Gas Market OIR will review the CPUC's ratemaking policies on
throughput risk to better align these with its objectives of promoting
energy conservation and adequate infrastructure. Phase II will also
investigate the need for emergency natural gas storage reserves and the
role of the utility in backstopping the noncore market.

COST OF SERVICE FILINGS

In 2002, the California Utilities filed cost of service applications
with the CPUC, seeking rate increases reflecting forecasts of 2004
capital and operating costs, as further discussed in the Annual Report.
SoCalGas requested revenue increases of $37 million. As previously
reported, in December 2003 SoCalGas filed with the CPUC a proposed

20

settlement of its cost of service proceeding. The settlement, if
approved by the CPUC, would reduce the company's annual rate revenues
by an aggregate net amount of approximately $33 million from the rates
in effect during 2003. The CPUC's Office of Ratepayer Advocates (ORA)
and all other major parties to the cost of service proceedings have
recommended that the CPUC approve the settlement.

On September 28, 2004, the CPUC's Administrative Law Judge (ALJ) and
the CPUC Commissioner assigned to the cost of service proceedings
issued differing proposed decisions for consideration by the CPUC. Both
of these proposed decisions recommend that the CPUC reject the proposed
settlement. The ALJ's proposed decision would, if adopted by the CPUC,
increase annual rate revenues by $44 million from that contemplated by
the settlement but would also adopt a one-way balancing account
requiring that any reductions in operating labor costs from those
estimated in establishing rates be refunded to customers. CPUC
Commissioner Wood's alternate proposed decision, which does not include
a one-way labor balancing account, would, if adopted by the CPUC,
decrease the annual rate reduction by $8 million from that contemplated
by the proposed settlement.

If various minor factual errors are corrected, they would increase the
annual rate revenues that would be provided by the ALJ's proposed
decision to $46 million above that contemplated by the settlement and
would increase the annual rate revenues that would be provided by
Commissioner Wood's alternative proposed decision to $10 million above
that contemplated by the settlement. Both proposed decisions would
approve balancing accounts for pension costs similar to those
contemplated by the settlement and various other cost balancing
accounts not contemplated by the settlement. All the proposals
contemplate that the rates resulting from the cost of service
proceedings would remain effective through 2007 subject to annual
attrition adjustments.

The company previously reported that it expects that another CPUC
commissioner will issue an additional proposed decision that, if
adopted by the CPUC, would essentially approve the proposed
settlements. Subsequently, on October 28, 2004, the CPUC at its
regularly scheduled meeting deferred acting on the cost of service
proceedings at the request of Commissioner Brown, who stated that he
would issue an additional proposed decision.

The CPUC may adopt any one of the proposed decisions or reject all of
them and adopt a different outcome. The company expects that a CPUC
decision will be issued by year end.

The CPUC previously ordered that any changes in rates resulting from
the cost of service proceedings would be effective retroactively to
January 1, 2004. Consequently, during 2004 the company has, in general,
recorded revenue and resulting net income in a manner consistent with
the reduced rates contemplated by the proposed settlement, except for
the favorable effect of the recovery of pension costs contemplated by
the proposed settlement and provided by the proposed decisions. To the
extent that the revenues provided by the CPUC's decision in the cost of
service proceedings differ from those previously recorded, a
reconciling adjustment to revenues and resulting net income would be

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recorded in the latest quarter for which financial statements had not
been published.

Other ratemaking issues are included in Phase II of the cost of service
proceeding. In addition to recommending changes in the performance-
based regulation (PBR) formulas, the ORA also proposed the possibility
of performance penalties for service quality, safety and electric
service reliability, without the possibility of performance awards.
Hearings took place in June 2004. On July 21, 2004, all of the active
parties in Phase II who dealt with post test year ratemaking and
performance incentives filed for adoption by the CPUC of an all-party
settlement agreement for most of the Phase II issues, including annual
inflation adjustments and revenue sharing. The agreement does not cover
performance incentives. For the interim years of 2005-2007, the
Consumer Price Index would be used to adjust the escalatable authorized
base rate revenues within identified floors and ceilings. It is not
likely that the CPUC will address this matter in its decision related
to Phase II of this proceeding before year-end 2004. Consequently, to
ensure that the results of Phase II would be applicable for a full year
in 2005, SoCalGas and SDG&E filed with the CPUC on September 29, 2004,
a petition to modify a prior decision that provided for the differences
between 2004's rates and the amounts determined in the cost of service
decision to be collected or refunded in future rates, to also apply to
similar differences occurring in 2005 prior to implementation of the
cost of service decision.

SoCalGas had filed for continuation of existing PBR mechanisms for
service quality and safety that would otherwise expire at the end of
2003. In January 2004, the CPUC issued a decision that extended 2003
service and safety targets through 2004, but did not determine the
applicability of rewards or penalties. As part of the proposed Phase II
Settlement Agreement, Revenue Sharing, under which IOUs return to
customers a percentage of earnings above specified levels, would be
suspended for 2004 and resume for 2005 through 2007. The proposed
revenue sharing mechanism also provides the utility the option to file
for suspension of the earnings sharing mechanism if earnings for two
consecutive years fall 175 basis points or more below its authorized
rate of return; however, if earnings are 300 or more basis points above
the utility's authorized rate of return, the revenue sharing mechanism
would be automatically suspended and trigger a formal regulatory review
by the CPUC to determine whether modification of the ratemaking
mechanism is required.

PERFORMANCE-BASED REGULATION

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

The only incentive reward approved during the nine months ended
September 30, 2004 consisted of $6.3 million related to SoCalGas' Year
9 GCIM, which was approved on February 26, 2004. This reward was
awarded by the CPUC subject to refund based on the outcome of the

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Border Price Investigation, as discussed below. The cumulative amount
of rewards subject to refund based on the outcome of the Border Price
Investigation is $56.9 million, substantially all of which has been
included in net income.

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

Program
-----------------------------------
DSM/Energy Efficiency* $ 10.9
GCIM Year 10 2.4
2003 safety .5
-----------------------------------
Total $ 13.8
-----------------------------------
* Dollar amounts shown do not include interest, franchise fees or
uncollectible amounts.

COST OF CAPITAL

Effective January 1, 2003, SoCalGas' authorized rate of return on
equity (ROE) is 10.82 percent and its return on ratebase (ROR) is 8.68
percent. These rates are subject to automatic adjustment if the 12-
month trailing average of 30-year Treasury bond rates and the Global
Insight forecast of the 30-year Treasury bond rate 12 months ahead vary
by greater than 150 basis points from a benchmark, which is currently
5.38 percent. The 12-month trailing average was 5.10 percent and the
Global Insight forecast was 5.84 percent at September 30, 2004.

BIENNIAL COST ALLOCATION PROCEEDING (BCAP)

The BCAP determines the allocation of authorized costs between customer
classes for natural gas transportation service provided by the company
and adjusts rates to reflect variances in sales volumes as compared to
the forecasts previously used in establishing transportation rates.
SoCalGas filed with the CPUC its 2005 BCAP application in September
2003, requesting updated transportation rates effective January 1,
2005. In November 2003, an Assigned Commissioner Ruling delayed the
BCAP application until a decision is issued in the GIR implementation
proceeding. As a result of the April 1, 2004 decision on GIR
implementation as described in Natural Gas Industry Restructuring in
the Annual Report, on May 27, 2004 the ALJ in the 2005 BCAP issued a
decision dismissing the BCAP application. The company is required to
file a new BCAP application after the stay of the GIR implementation
decision is lifted. As a result of the deferrals and the significant
decline forecasted in noncore gas throughput on SoCalGas' system, in
December 2002 the CPUC issued a decision approving 100 percent
balancing account protection for SoCalGas' risk on local transmission
and distribution revenues from January 1, 2003 until the CPUC issues
its next BCAP decision. SoCalGas is seeking to continue this balancing
account protection in the Natural Gas OIR proceeding.

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BORDER PRICE INVESTIGATION

In November 2002, the CPUC instituted an investigation into the
Southern California natural gas market and the price of natural gas
delivered to the California - Arizona border between March 2000 and May
2001. The California Utilities are the parties to the first phase of
the investigation. If the investigation were to determine that the
conduct of either of the California Utilities contributed to the
natural gas price spikes that occurred during the investigation period,
the CPUC may modify the party's natural gas procurement incentive
mechanism, reduce the amount of any shareholder award for the period
involved, and/or order the party to issue a refund to ratepayers. At
September 30, 2004, the cumulative amount of shareholder awards,
substantially all of which has been included in net income, was $56.9
million. The ORA has filed testimony supporting the GCIM and the
actions of SoCalGas during this period. The first phase of this
investigation was reopened for one day on October 25, 2004, for
additional testimony and supplemental opening and reply briefs. While
the ALJ stated that a proposed decision is not imminent, the company
expects that a proposed decision will be issued before year end for
consideration by the CPUC. Although the proposed decision may be
adverse to it, the company believes it is unlikely that the full CPUC
would adopt any such adverse decision and would instead conclude that
the California Utilities were not responsible for any natural gas price
spikes. A final CPUC decision in the first phase of the investigation
is not expected until 2005.

CPUC INVESTIGATION OF ENERGY-UTILITY HOLDING COMPANIES

The CPUC has initiated an investigation into the relationship between
California's IOUs and their parent holding companies. The CPUC broadly
determined that it could, in appropriate circumstances, require the
holding company to provide cash to a utility subsidiary to cover its
operating expenses and working capital to the extent they are not
adequately funded through retail rates. This would be in addition to
the requirement of holding companies to provide for their utility
subsidiaries' capital requirements, as the IOUs previously acknowledged
in connection with the holding companies' formations. 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.

In an opinion issued May 21, 2004, the California Court of Appeal
upheld the CPUC's assertion of limited enforcement jurisdiction, but
concluded that the CPUC's interpretation of the "first priority"
condition (that the holding companies could be required to infuse cash
into the utilities as necessary to meet the utilities' obligation to
serve) was not ripe for review. In September 2004, the California
Supreme Court declined to review the California Court of Appeal's
decision.

NOTE 5. LITIGATION

Except for the matters referred to below, neither the company nor its
subsidiaries are party to, nor is their property the subject of, any
material pending legal proceedings other than routine litigation
incidental to their businesses. Management believes that none of these

24

matters will have further material adverse effect on the company's
financial condition or results of operations.

Energy Crisis Litigation

In 2000 and 2001, California experienced a severe energy crisis
characterized by dramatic increases in the prices of natural gas. Many,
often duplicative, lawsuits have been filed against numerous energy
companies seeking overlapping damages aggregating in the tens of
billions of dollars for allegedly unlawful activities asserted to have
caused or contributed to the energy crisis. In addition, the energy
crisis has generated numerous governmental investigations and
regulatory proceedings. The company is cooperating in various
investigations, including an investigation being conducted by the
California Attorney General into possible anti-competitive behavior.
The material regulatory proceedings arising out of the energy crisis
that involve the company are briefly summarized, along with other
proceedings, in Note 4 and this Note 5. The lawsuits arising out of the
energy crisis to which the company is a defendant are briefly
summarized below.

Class-action and individual antitrust and unfair competition lawsuits
filed in 2000 and thereafter, and currently consolidated in San Diego
Superior Court seek damages, alleging that Sempra Energy, SoCalGas and
SDG&E, along with El Paso Natural Gas Company (El Paso) and several of
its affiliates, unlawfully sought to control natural gas and
electricity markets. In December 2003, the Court approved a settlement
whereby the applicable El Paso entities (including cases involving
unrelated claims not applicable to Sempra Energy, SoCalGas or SDG&E)
will pay approximately $1.7 billion to resolve these claims. The
proceeding against Sempra Energy and the California Utilities has not
been settled and continues to be litigated. During the third quarter of
2004, the court denied motions by Sempra Energy and the California
Utilities for summary judgment in their favor. Sempra Energy and the
California Utilities have requested the Court of Appeal to review these
denials; however, such an interim review pending a final decision on
the merits of the case is entirely at the discretion of the appellate
court. In October 2004, certain of the plaintiffs issued a news release
asserting that they could recover as much as $24 billion from Sempra
Energy and the California Utilities if their allegations were upheld at
trial. The trial of the case was previously set for September 2004 but
has been postponed and the newly assigned judge has yet to schedule a
new trial date. (The original judge is retiring at year end.)

Similar lawsuits have been filed by the Attorneys General of Arizona
and Nevada, alleging that El Paso and certain Sempra Energy
subsidiaries unlawfully sought to control the natural gas market in
their respective states. The claims against the Sempra Energy
defendants in the Arizona lawsuit were settled in September 2004 for
$150,000 and have been dismissed with prejudice.

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 recovery
of damages alleged to aggregate in excess of $150 million (before
trebling) from an alleged conspiracy to drive up or control natural gas

25

prices, eliminate competition and increase market volatility, breach of
contract and wire fraud. On January 27, 2004, the U.S. District Court
dismissed the Sierra Pacific Resources case against all of the
defendants, determining that this is a matter for the FERC to resolve.
However, the court granted plaintiffs' request to amend their
complaint, which they have done and Sempra Energy has filed another
motion to dismiss, which is scheduled to be heard on November 29, 2004.

In July 2004, the City and County of San Francisco, the County of Santa
Clara and the County of San Diego brought actions, alleging that energy
prices were unlawfully manipulated by defendants' reporting
artificially inflated natural gas prices to trade publications and by
entering into wash trades and by engaging in "churning" transactions
with Reliant Energy, in San Diego Superior Court against various
entities, including Sempra Energy, SET, SoCalGas and SDG&E.

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" and "Risk Factors" contained in the Annual Report.

RESULTS OF OPERATIONS

Revenues and Cost of Sales

Natural gas revenues increased to $2.8 billion for the nine months
ended September 30, 2004 from $2.6 billion for the corresponding period
in 2003, and the cost of natural gas increased to $1.5 billion in 2004
from $1.4 billion in 2003. Additionally, natural gas revenues were $826
million for the quarter ended September 30, 2004 compared to $794
million for the corresponding period in 2003, and the cost of natural
gas was $391 million in 2004 compared to $333 million in 2003. These
increases were primarily attributable to natural gas cost increases,
which are passed on to customers, offset by $48 million of GCIM awards
recognized during the third quarter of 2003. Performance awards are
discussed in Note 4 of the notes to Consolidated Financial Statements.

In 2002, the California Utilities filed Cost of Service applications
with the CPUC, seeking rate increases reflecting forecasts of 2004
capital and operating costs, as further discussed in the Annual Report
and in Note 4 of the notes to Consolidated Financial Statements. In
accordance with generally accepted accounting principles, SoCalGas is
generally recognizing 2004 revenue in a manner consistent with the
reduced rates contemplated by the proposed settlements, except for the
favorable effect of the recovery of pension costs contemplated by the
proposed settlements and provided by both proposed decisions. To the
extent that the revenues provided by the CPUC's decision in the cost of
service proceedings differ from those previously recorded, a
reconciling adjustment to revenues and resulting net income would be
recorded in the latest quarter for which financial statements had not

26

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

The table below summarizes natural gas volumes and revenues by customer
class for the nine months ended September 30, 2004 and 2003.

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

Other Operating Expenses

Other operating expenses at SoCalGas decreased to $660 million for the
nine-month period ended September 30, 2004 from $689 million for the
same period in 2003 and decreased to $222 million for the quarter ended
September 30, 2004 from $268 million for the same period in 2003
primarily as a result of a $55 million before-tax charge in the third
quarter of 2003 for litigation and for losses associated with a
sublease of portions of the SoCalGas headquarters building, offset by
an increase in refundable costs.

Net Income

SoCalGas recorded net income of $175 million and $149 million for the
nine-month periods ended September 30, 2004 and 2003, respectively, and
net income of $68 million and $53 million for the quarters ended
September 30, 2004 and 2003, respectively. The increases were primarily
due to the $32 million after-tax charge for litigation and for losses
associated with a long-term sublease of portions of its headquarters
building in 2003, higher margins in 2004 and the gain on the sale of
partnership property, partially offset by higher GCIM awards in 2003
and higher depreciation expense in 2004.

27

CAPITAL RESOURCES AND LIQUIDITY

SoCalGas' operations are the major source of liquidity for PE. In
addition, working capital requirements can be met through the issuance
of short-term and long-term debt. Cash requirements primarily consist of
capital expenditures for utility plant.

At September 30, 2004, the company had $26 million in cash and $800
million in available unused, committed lines of credit (of which PE had
$500 million for the sole purpose of providing loans to Sempra Energy
Global Enterprises, another subsidiary of Sempra Energy, and SoCalGas
had $300 million). See "Cash Flows from Financing Activities" for
discussion on changes in PE's credit facility in 2004.

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

CASH FLOWS FROM OPERATING ACTIVITIES

Net cash provided by PE's operating activities totaled $563 million and
$423 million for the nine months ended September 30, 2004 and 2003,
respectively. PE's operating activities included $521 million and $431
million, respectively, from SoCalGas. The increases were primarily
attributable to a lower decrease in overcollected regulatory balancing
accounts and higher decrease in accounts receivable in 2004 and 2003
refunds of customer deposits.

For the nine months ended September 30, 2004, the company made pension
plan and other postretirement benefit plan contributions of $3 million
and $38 million, respectively.

CASH FLOWS FROM INVESTING ACTIVITIES

Net cash provided by (used in) PE's investing activities totaled $(241)
million and $79 million for the nine months ended September 30, 2004 and
2003, respectively. Net cash used in SoCalGas' investing activities
totaled $201 million and $131 million for the nine months ended
September 30, 2004 and 2003, respectively. The changes were primarily
due to increased advances to and lower repayments by Sempra Energy in
2004 for PE and SoCalGas, respectively.

Significant capital expenditures in 2004 are expected to be for
improvements to the distribution and transmission systems. These
expenditures are expected to be financed by cash flows from operations
and debt issuances.

In September 2004, the CPUC approved a proposed framework for the
contracting of interstate pipeline capacity for core customers.
Discussions are underway for the California Utilities to acquire

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pipeline capacity to replace capacity contracts expiring over the next
two years. The CPUC also approved requests to establish receipt points
to accept new supplies, including imported LNG, to the California
Utilities' service area. Approval for a point of receipt to import
natural gas from Mexico to Southern California via pipelines at Otay
Mesa was also obtained. As a result, the California Utilities expect to
install capital facilities starting in 2005, in order to receive natural
gas supplies from new delivery locations. The CPUC has determined that
project developers, not the utilities, will be presumed to pay for the
costs for access-related infrastructure, subject to future applications
to be filed when more is known about the particular projects. Note 4 of
the notes to Consolidated Financial Statements herein provides further
details.

CASH FLOWS FROM FINANCING ACTIVITIES

Net cash used in PE's financing activities totaled $328 million and $508
million for the nine months ended September 30, 2004 and 2003,
respectively. Net cash used in SoCalGas' financing activities totaled
$326 million and $306 million for the nine months ended September 30,
2004 and 2003, respectively. The changes were attributable to lower debt
and dividend payments by PE and lower debt payments partially offset by
higher dividend payments by SoCalGas in 2004.

In September 2004, PE extended the termination date of its revolving
credit agreement to September 30, 2005, and increased the revolving
credit commitment from $250 million to $500 million. Borrowings under
the credit agreement, none of which are outstanding, are available to
provide loans to Global and would bear interest at rates varying with
market rates, PE's credit ratings and amounts borrowed. They would be
guaranteed by Sempra Energy and would be subject to mandatory repayment
if Sempra Energy's or SoCalGas' ratio of debt to total capitalization
(as defined in the agreement) were to exceed 65%, or if there were to
be a change in law materially and adversely affecting SoCalGas' ability
to pay dividends or make other distributions to PE.

FACTORS INFLUENCING FUTURE PERFORMANCE

Performance of the companies will depend primarily on the ratemaking
and regulatory process, electric and natural gas industry
restructuring, and the changing energy marketplace. These factors are
discussed in the Annual Report and in Note 4 of the notes to
Consolidated Financial Statements herein.

CRITICAL ACCOUNTING POLICIES AND KEY NON-CASH PERFORMANCE INDICATORS

There have been no significant changes to the accounting policies
viewed by management as critical or key non-cash performance indicators
for the company, as set forth in the Annual Report.

NEW ACCOUNTING STANDARDS

Relevant pronouncements that have recently become effective and have
had a significant effect on the company are SFAS Nos. 132 (revised
2003), 143 and 149, FASB Staff Position 106-2, and FIN 45, as discussed
in Note 2 of the notes to Consolidated Financial Statements.

29

Pronouncements that have or are likely to have a material effect on
future earnings are described below.

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

In June 2004, the FASB issued a proposed interpretation of SFAS 143,
Accounting for Conditional Asset Retirement Obligations, an
interpretation of FASB Statement No. 143. The interpretation would
clarify that a legal obligation to perform an asset retirement activity
that is conditional on a future event is within the scope of SFAS 143.
Accordingly, the interpretation would require an entity to recognize a
liability for a conditional asset retirement obligation if the
liability's fair value can be reasonably estimated. The proposed
interpretation would be effective for the company on December 31, 2005.

SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": SFAS 149 amends and clarifies accounting for
derivative instruments and for hedging activities under SFAS 133. Under
SFAS 149, natural gas forward contracts that are subject to unplanned
netting do not qualify for the normal purchases and normal sales
exception, whereby derivatives are not required to be marked to market
when the contract is usually settled by the physical delivery of
natural gas. The company has determined that all natural gas contracts
are subject to unplanned netting and as such, these contracts are
marked to market. Implementation of SFAS 149 on July 1, 2003 did not
have a material impact on reported net income.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

As of September 30, 2004, the total Value at Risk of SoCalGas'
positions was not material.

ITEM 4. CONTROLS AND PROCEDURES

The companies have designed and maintain disclosure controls and
procedures to ensure that information required to be disclosed in the
companies' 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 companies'
management, including their Chief Executive Officers and Chief
Financial Officers, 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

30

necessarily applies judgment in evaluating the cost-benefit
relationship of other possible controls and procedures.

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

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

PART II - OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Except as described in Notes 4 and 5 of the notes to Consolidated
Financial Statements herein, neither the companies nor their
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

Compensation

10.1 Sempra Energy Employee Stock Incentive Plan
(September 30, 2004 Sempra Energy Form 10-Q
Exhibit 10.1).

10.2 Sempra Energy Amended and Restated Executive Life
Insurance Plan (September 30, 2004 Sempra Energy
Form 10-Q Exhibit 10.2).

10.3 Sempra Energy Excess Cash Balance Plan
(September 30, 2004 Sempra Energy Form 10-Q
Exhibit 10.3).

10.4 Form of Sempra Energy 1998 Long Term Incentive Plan
Performance-Based Restricted Stock Award
(September 30, 2004 Sempra Energy Form 10-Q
Exhibit 10.4).

10.5 Form of Sempra Energy 1998 Long Term Incentive Plan
Nonqualified Stock Option Agreement
(September 30, 2004 Sempra Energy Form 10-Q
Exhibit 10.5).

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10.6 Form of Sempra Energy 1998 Non-Employee Directors' Stock
Plan Nonqualified Stock Option Agreement
(September 30, 2004 Sempra Energy Form 10-Q
Exhibit 10.6).

10.7 Sempra Energy Supplemental Executive Retirement Plan
(September 30, 2004 Sempra Energy Form 10-Q
Exhibit 10.7).

10.8 Neal Schmale Restricted Stock Award Agreement
(September 30, 2004 Sempra Energy Form 10-Q
Exhibit 10.8).

10.9 Severance Pay Agreement between Sempra Energy and
Donald E. Felsinger (September 30, 2004 Sempra Energy
Form 10-Q Exhibit 10.9).

10.10 Severance Pay Agreement between Sempra Energy and
Neal Schmale (September 30, 2004 Sempra Energy
Form 10-Q Exhibit 10.10).

10.11 Sempra Energy Executive Personal Financial Planning Program
Policy Document (September 30, 2004 Sempra Energy
Form 10-Q Exhibit 10.11).

Exhibit 12 - Computation of ratios

12.1 Computation of Ratio of Earnings to Fixed Charges of PE.

12.2 Computation of Ratio of Earnings to Fixed Charges of
SoCalGas.

Exhibit 31 -- Section 302 Certifications

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

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

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

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

Exhibit 32 -- Section 906 Certifications

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

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

32.3 Statement of SoCalGas' Chief Executive Officer pursuant
to 18 U.S.C. Sec. 1350.

32

32.4 Statement of SoCalGas' Chief Financial Officer pursuant
to 18 U.S.C. Sec. 1350.

(b) Reports on Form 8-K

The following reports on Form 8-K were filed after June 30, 2004:

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

Current Report on Form 8-K filed September 30, 2004, announcing proposed
decisions issued by the CPUC's Administrative Law Judge and the Assigned
CPUC Commissioner on September 28, 2004, in the California Utilities'
Cost of Service Proceedings.

Current Report on Form 8-K filed October 27, 2004, discussing the
current status of the California Utilities' Cost of Service Proceedings
and the Border Price Investigation.

Current Report on Form 8-K filed November 4, 2004, filing as an exhibit
Sempra Energy's press release of November 4, 2004, giving the financial
results for the quarter ended September 30, 2004.

33

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrants have duly caused this report to be signed on their behalf by
the undersigned thereunto duly authorized.

PACIFIC ENTERPRISES
-------------------
(Registrant)

Date: November 4, 2004 By: /s/ F. H. Ault
----------------------------
F. H. Ault
Sr. Vice President and Controller

SOUTHERN CALIFORNIA GAS COMPANY
-------------------------------
(Registrant)

Date: November 4, 2004 By: /s/ S. D. Davis
---------------------------
S. D. Davis
Sr. Vice President-External Relations
and Chief Financial Officer