SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] Annual report pursuant to Section 13 or 15(d) of the Securities Exchange
Act of 1934 Forfor the fiscal year ended December 31, 20012004
OR
[ ] Transition report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 For the transition period from to
.------- -------
Exact Name of
Commission Registrant IRS Employer
File as specified State of Identification
Number in its charter Incorporation Number
- ---------- -------------- -------------- ------------------------
1-40 PACIFIC ENTERPRISES California 94-0743670
1-1402 SOUTHERN CALIFORNIA GAS COMPANY California 95-1240705
555 WEST FIFTH STREET, LOS ANGELES, CALIFORNIA 90013
- ---------------------------------------------- ----------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (213)244-1200
--------------
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of each exchange
Title of each class on which registered
- ------------------- ---------------------
Pacific Enterprises Preferred Stock: American and Pacific
$4.75 dividend; $4.50 dividend;
$4.40 dividend; $4.36 dividend
Southern California Gas Co. Preferred Stock Pacific
Southern California Gas Co. First Mortgage Bonds: New York
Series Y, due 2021; Series Z, due 2002;
Series BB, due 2023; Series DD, due 2023;
Series EE, due 2025; Series FF, due 2003
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
Pacific Enterprises None
Southern California Gas Company None
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 and (2) has been subject to such filing
requirements for the past 90 days. Yes [ X ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. [ X ]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [ X ]
Exhibit Index on page 76.94. Glossary on page 79.99.
Aggregate market value of the voting stock held by non-affiliates of the
registrant as of February 28, 2002:January 31, 2005:
Pacific Enterprises $51.1$68.8 Million
Southern California Gas Company $15.8$20.1 Million
Common Stock outstanding without par value as of February 28, 2002:January 31, 2005:
Pacific Enterprises Wholly owned by Sempra Energy
Southern California Gas Company Wholly owned by Pacific Enterprises
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Information Statement prepared for the May 20022005 annual meeting
of shareholders are incorporated by reference into Part III.2
TABLE OF CONTENTS
PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . 34
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . .10. 12
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . .10. 12
Item 4. Submission of Matters to a Vote of Security Holders. .10. 12
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . .11. 12
Item 6. Selected Financial Data. . . . . . . . . . . . . . . .11. 13
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . .12. 13
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk . . . . . . . . . . . . . . . . .24. 26
Item 8. Financial Statements and Supplementary Data. . . . . .24. 27
Item 9. Changes Inin and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . .67. 82
Item 9A. Controls and Procedures . . . . . . . . . . . . . . . 82
Item 9B. Other Information . . . . . . . . . . . . . . . . . . 83
PART III
Item 10. Directors and Executive Officers of the Registrant . .68. 85
Item 11. Executive Compensation . . . . . . . . . . . . . . . .69. 86
Item 12. Security Ownership of Certain Beneficial Owners
and Management.Management and Related Stockholder Matters. . . . . . . . . . . . . . . . . . .6986
Item 13. Certain Relationships and Related Transactions . . . .69. 86
Item 14 Principal Accountant Fees and Services . . . . . . . . 86
PART IV
Item 14.15. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . .69. 87
Consents of Independent Auditors' ConsentsRegistered Public Accounting Firm and
Report on ScheduleSchedule. . . . . .71. . . . . . . . . . . . 89
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . .74. 92
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . .76. 94
Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . .79. 99
3
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This Annual 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-lookingforward-
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 internationalnational economic,
competitive, political, legislative and regulatory conditions and
developments; actions by the CPUC,California Public Utilities Commission,
the California State Legislature, and the FERC;Federal Energy Regulatory
Commission and other regulatory bodies in the financial condition of
other investor-owned utilities;United States; capital
marketmarkets 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;decisions and
requirements; the pacestatus 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.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 company'scompanies' business described in this annual
report and other reports filed by the companycompanies from time to time with
the Securities and Exchange Commission.4
PART I
ITEM 1. BUSINESS
Description of Business
Pacific Enterprises (PE or the company) is an energy services company
whose only directsignificant subsidiary is Southern California Gas Company
(SoCalGas), the nation's largest natural gas distribution utility. 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 second case, 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." A description of PE and SoCalGas is
given in "Management's Discussion and Analysis of Financial Condition
and Results of Operations" herein.
SoCalGas is PE's only subsidiary andAs PE itself has no operations.operations, PE's financial position and operations
consist of those of SoCalGas and some additional items attributable to
PE's position as a holding company (e.g. cash, intercompany accounts,
debt and equity.)
GOVERNMENT REGULATION
Local Regulation
SoCalGas has gas franchisesequity).
Company Website
The company's website address is http://www.socalgas.com/ and Sempra
Energy's website address is http://www.sempra.com/investor.htm. The
company makes available free of charge via a hyperlink on its website
its annual report on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K, and any amendments to those reports as soon as
reasonably practicable after such material is electronically filed with
or furnished to the Securities and Exchange Commission.
RISK FACTORS
The following risk factors and all other information contained in this
report should be considered carefully when evaluating the company.
These risk factors could affect the actual results of the company and
cause such results to differ materially from those expressed in any
forward-looking statements of, or made by or on behalf of, the company.
Other risks and uncertainties, in addition to those that are described
below, may also impair its business operations. If any of the following
risks occurs, the company's business, cash flows, results of operations
and financial condition could be seriously harmed. These risk factors
should be read in conjunction with the 239 legal jurisdictions in its
service territory. These franchises allow SoCalGas to locate
facilities forother detailed information
concerning the transmission and distribution of natural gascompany set forth in the streetsnotes to Consolidated Financial
Statements and other public places. Some franchises have fixed terms,
such as that forin "Management's Discussion and Analysis of Financial
Condition and Results of Operations" herein.
SoCalGas is subject to extensive regulation by state, federal and local
legislation and regulatory authorities, which may adversely affect the
cityoperations, performance and growth of Los Angeles, which expires in 2012. Most
of the franchises do not have fixed terms and continue indefinitely.
The range of expiration dates for the franchises with definite terms
is 2003 to 2048.
California Utility Regulation
The State of California Legislature, from time to time, passes laws
that regulate SoCalGas' operations. For example, in 1999, the
legislature enacted a law addressing natural gas industry
restructuring.its business.
5
The California Public Utilities Commission (CPUC), which consists of
five commissioners appointed by the Governor of California for
staggered six-year terms, regulates SoCalGas' rates and conditions of
service, sales of securities, rates of return, rates of depreciation,
uniform systems of accounts, examination of records and long-term
resource procurement. The CPUC conducts various reviews of utility
performance (including reasonableness and prudency reviews) and
affiliate relationships and conducts audits and investigations into
various matters which may, from time to time, result in disallowances
and penalties adversely affecting earnings and cash flows. Various
proceedings involving the CPUC and relating to SoCalGas' rates, costs,
incentive mechanisms, performance-based regulation and compliance with
affiliate and holding company rules are discussed in the notes to
Consolidated Financial Statements and in "Management's Discussion and
Analysis of Financial Condition and Results of Operations" herein.
Periodically, SoCalGas' rates are approved by the CPUC based on
forecasts of capital and operating costs. If SoCalGas' actual capital
and operating costs were to exceed the amount included in its base
rates approved by the CPUC, it would adversely affect earnings and cash
flows.
To promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, the CPUC adopted
Performance-Based Regulation (PBR) for the California Utilities. Under
PBR, regulators require 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. The
three areas that are eligible for PBR rewards are: operational
incentives based on measurements of safety, reliability and customer
satisfaction; energy efficiency rewards based on the effectiveness of
the programs; and natural gas procurement rewards. Although SoCalGas
has received significant PBR rewards in the past, there can be no
assurance that SoCalGas will receive rewards at similar levels in the
future, or at all. Additionally, if SoCalGas fails to achieve certain
minimum performance levels established under the PBR mechanisms, it may
be assessed financial disallowances or penalties which could adversely
affect their earnings and cash flows.
SoCalGas may be impacted by new regulations, decisions, orders or
interpretations of the CPUC or other regulatory bodies. New
legislation, regulations, decisions, orders or interpretations could
change how SoCalGas operates, could affect its ability to recover their
various costs through rates or adjustment mechanisms, or could require
SoCalGas to incur additional expenses.
The California Utilities' future results of operations and financial
condition may be materially adversely affected by the outcome of
pending litigation against them.
The California energy crisis of 2000 and 2001 has generated numerous
lawsuits, governmental investigations and regulatory proceedings
involving many energy companies, including Sempra Energy and the
California Utilities. They are the remaining defendants in class action
and individual antitrust and unfair competition lawsuits scheduled for
a jury trial to begin in September 2005 in which the plaintiffs have
asserted that they are entitled to recover $24 billion in damages.
6
Additional lawsuits have been filed by the Attorney General of Nevada
and by others. They are also responding to an ongoing investigation
being conducted by the California Attorney General and an ongoing CPUC
proceeding related to the increase in natural gas prices at the
California-Arizona border in 2000-2001. The California Utilities have
expended and continue to expend substantial amounts defending these
lawsuits and in connection with related investigations and regulatory
proceedings. If these matters are ultimately resolved unfavorably to
the California Utilities, their results of operations and financial
condition and those of Sempra Energy may be materially adversely
affected.
These proceedings are discussed in the notes to Consolidated Financial
Statements and in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" herein.
SoCalGas' cash flows, ability to pay dividends and ability to meet its
debt obligations largely depend on the performance of its utility
operations.
SoCalGas' utility operations are its major source of liquidity.
SoCalGas' cash flows, ability to meet its obligations to creditors and
its ability to pay dividends on its common stock are largely dependent
upon the sufficiency of utility earnings and cash flows in excess of
utility needs.
Natural disasters, catastrophic accidents or acts of terrorism could
materially adversely affect SoCalGas' business, earnings and cash
flows.
Like other major industrial facilities, SoCalGas' natural gas pipelines
and storage facilities may be damaged by natural disasters,
catastrophic accidents or acts of terrorism. Any such incidents could
result in severe business disruptions, significant decreases in
revenues or significant additional costs to the company, which could
have a material adverse effect on SoCalGas' earnings and cash flows.
Given the nature and location of these facilities, any such incidents
also could cause fires, leaks, explosions, spills or other significant
damage to natural resources or property belonging to third parties, or
personal injuries, which could lead to significant claims against the
company and its subsidiaries. Insurance coverage may become unavailable
for certain of these risks and the insurance proceeds received for any
loss of or damage to any of its facilities, or for any loss of or
damage to natural resources or property or personal injuries caused by
its operations, may be insufficient to cover the company's losses or
liabilities without materially adversely affecting the company's
financial condition, earnings and cash flows.
GOVERNMENT REGULATION
California Utility Regulation
The CPUC, which consists of five commissioners appointed by the
Governor of California for staggered six-year terms, regulates
SoCalGas' rates and conditions of service, sales of securities, rate of
return, rates of depreciation, uniform systems of accounts, examination
7
of records, and long-term resource procurement. The CPUC also conducts
various reviews of utility performance and conducts investigations into
various matters, such as deregulation, competition and the environment,
to determine its future policies. The CPUC also regulates the
relationship of utilities with their holding companies and is currently
conducting an investigation into this relationship. This investigation
is discussed further in Note 9 of the notes to Consolidated Financial
Statements herein.
United States Utility Regulation
The Federal Energy Regulatory Commission (FERC) regulates the
interstate sale and transportation of natural gas, the uniform systems
of accounts and rates of depreciation. Both the FERC and the CPUC are
currently investigating prices charged to the California investor-owned
utilities (IOUs) by various suppliers of natural gas and electricity.
Further discussion is provided in Note 9 of the notes to Consolidated
Financial Statements herein.
Local Regulation
SoCalGas has natural gas franchises with the 240 legal jurisdictions in
its service territory. These franchises allow SoCalGas to locate,
operate and maintain facilities for the transmission and distribution
of natural gas in streets and other public places. Some franchises have
fixed terms, such as that for the city of Los Angeles, which expires in
2012. The range of expiration dates for the franchises with definite
terms is 2005 to 2048. Most of the franchises do not have fixed terms
and continue indefinitely.
Licenses and Permits
SoCalGas obtains a number ofnumerous permits, authorizations and licenses in
connection with the transmission and distribution of natural gas. They
require periodic renewal, which results in continuing regulation by the
granting agency.
Other regulatory matters are described in Note 12 of the notes to
Consolidated Financial Statements, herein.
SOURCES OF REVENUE
Information on this topic is provided in Note 29 of the notes to
Consolidated Financial Statements herein.
NATURAL GAS UTILITY OPERATIONS
Utility ServicesResource Planning and Natural Gas Procurement and Transportation
SoCalGas purchases, sells, distributes, stores and transports natural
gas. It owns and operates a natural gasis engaged in the purchase, sale, distribution, transmission and
storage system that supplies natural gas to 5.1 million end-use
customers throughout a 23,000-square-mile service territory from
central California to the Mexican border. SoCalGas also transports gas
to about 1,300 utility electric generation (UEG), wholesale, large
commercial, industrial and off-system (outside the company's normal
service territory) customers.
SoCalGas offers two basic utility services: sale of natural gas and
transportation of natural gas. Natural gas service is also
provided on a wholesale basis to the distribution systemsThe company's resource planning, power
procurement, contractual commitments and related regulatory matters are
discussed below and in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and in Notes 9 and 10 of
the City
of Long Beach, Southwest Gas Corporation and San Diego Gas & Electric
Company (SDG&E), an affiliated company.
Supplies of Natural Gas
SoCalGas buys natural gas under several short-term and long-term
contracts. Short-term purchases are from various Southwest U.S. and
Canadian gas suppliers, and are primarily based on monthly spot-market
prices. SoCalGas transports gas under long-term firm pipeline capacity
agreements that provide for annual reservation charges, which are
recovered in rates. SoCalGas has commitments for firm pipeline
capacity under contracts with pipeline companies that expire at
various dates through 2006.
Most of the natural gas purchased and delivered by SoCalGas is
produced outside of California. These supplies are deliverednotes to SoCalGas' intrastate transmission system by interstate pipeline
companies, primarily El Paso Natural Gas Company and Transwestern
Natural Gas Company. These interstate companies provide transportation
services for supplies purchased from other sources by SoCalGas or its
transportation customers. The rates that interstate pipeline companies
may charge for natural gas and transportation services are regulated
by the FERC.
The following table shows the sources of natural gas deliveries from
1997 through 2001:
Years Ended December 31
-------------------------------------------------
2001 2000 1999 1998 1997
- -----------------------------------------------------------------------------------------
Purchases in billions of cubic feet
Gas Purchases - Commodity Portion 367 360 391 374 329
Customer-owned and exchange receipts 837 755 637 637 614
Storage Withdrawal
(Injection) - net (27) 39 (6) (28) (3)
Company use and
unaccounted For (24) (21) (16) (21) (10)
------- ------- ------- ------- -------
Net Deliveries 1,153 1,133 1,006 962 930
======= ======= ======= ======= =======
Purchases in millions of dollars
Commodity costs $1,997 $1,243 $ 916 $ 774 $ 849
Fixed charges* 128 128 147 174 250
------- ------- ------- ------- -------
Total Purchases $2,125 $1,371 $1,063 $ 948 $1,099
======= ======= ======= ======= =======
Average Commodity Cost of Purchases
(dollars per thousand cubic feet)** $5.44 $3.45 $ 2.34 $2.07 $2.58
======= ======= ======= ======= =======
* Fixed charges primarily include pipeline demand charges, take or pay settlement
costs and other direct-billed amounts allocated over the quantities delivered by the
interstate pipelines serving SoCalGas.
** The average commodity cost of natural gas purchased excludes fixed charges.
Market-sensitive natural gas supplies (supplies purchased on the spot
market as well as under longer-term contracts, ranging from one month
to two years, based on spot prices) account for 100 percent of total
natural gas volumes purchased by SoCalGas. The average price of
natural gas at the California/Arizona (CA/AZ) border was $7.27/mmbtu
in 2001, compared with $6.25/mmbtu in 2000, and $2.33/mmbtu in 1999.
Supply/demand imbalances and a number of other factors associated with
California's energy crisis in late 2000 and early 2001 resulted in
higher natural gas prices during that period. Prices for natural gas
have subsequently decreased in the later part of 2001. As of December
31, 2001, the average spot cash price at the California/Arizona border
was $2.63/mmbtu.
During 2001, SoCalGas delivered 1,153 bcf of natural gas through
its system. Approximately 69 percent of these deliveries were
customer-owned natural gas for which SoCalGas provided transportation
services. The remaining natural gas deliveries were purchased by
SoCalGas and resold to customers. The company estimates that
sufficient natural gas supplies will be available to meet the
requirements of its customers for the next several years.Consolidated Financial Statements herein.
Customers
For regulatory purposes, customers are separated into core and noncore
customers. Core customers are primarily residential and small
commercial and industrial customers, without alternative fuel
8
capability. Noncore customers consist primarily of utility electric generation, (UEG),
wholesale, large commercial, industrial and off-
system (outside the company's normal service territory)enhanced oil recovery
customers. Of
the 5.1 million meters in SoCalGas service territory, only 1,300 serve
the noncore market.
Most core customers purchase natural gas directly from SoCalGas. Core
customers are permitted to aggregate their natural gas requirement and
up to a limit of 10 percent of SoCalGas' core market,
to purchase natural gas directly from brokers or producers. Beginning
in 2002, the CPUC authorized the removal of the 10 percent limit. SoCalGas continues to be
obligated to purchase reliable supplies of natural gas to serve the
requirements of itsthe core customers.
Natural Gas Procurement and Transportation
Most of the natural gas purchased and delivered by SoCalGas is produced
outside of California, primarily in the southwestern U.S. and SDG&E recently filed an application withCanada.
SoCalGas purchases natural gas under short-term and long-term
contracts. Short-term purchases are primarily based on monthly spot-
market prices.
To ensure the CPUCdelivery of the natural gas supplies to combine the two companies' core procurement portfolios. On March 6, 2002,distribution
system and to meet the seasonal and annual needs of customers, SoCalGas
is committed to firm pipeline capacity contracts that require the
payment of fixed reservation charges to reserve firm transportation
entitlements. SoCalGas sells excess capacity, if any, on a proposed decision was issued which, if approved, will allowshort-term
basis. Interstate pipeline companies, primarily El Paso Natural Gas
Company and Transwestern Pipeline Company, provide transportation
services into SoCalGas' intrastate transmission system for supplies
purchased by SoCalGas and SDG&E to combine their core procurement portfolios. A final CPUC
decision is expected in mid-2002.
Beginning in 2002, utility procurement services offered to
noncoreor its transportation customers will be phased out. Noncore customersfrom outside of
California. All of these contracts will have the
option to either become core customers, and continue to receive
utility procurement services, or remain noncore customers and purchase
their natural gas from other sources, such as brokers or producers.
Noncore customers will also have to make arrangements to deliver their
purchases to SoCalGas' receipt points for delivery through the
company's transmission and distribution system.
In 2001, approximately 87 percent of the CPUC-authorized natural
gas margin was allocated to the core customers, with 13 percent
allocated to the noncore customers.
Although revenues from transportation throughput is less thanexpired by 2007. The rates
that interstate pipeline companies may charge for natural gas sales, SoCalGas generally earnsand
transportation services are regulated by the same margin whether
SoCalGas buysFERC.
According to "Btu's Daily Gas Wire", the gas and sells it to the customer or transportsannual average spot price of
natural gas already owned byat the customer.California/Arizona border was $5.53 per million
British thermal unit (mmbtu) in 2004 ($6.35 in December 2004), compared
with $5.10 per mmbtu in 2003 and $3.14 per mmbtu in 2002. Prices for
natural gas increased toward the end of 2002, 2003 and in 2004.
SoCalGas's weighted average cost (including transportation charges) per
mmbtu of natural gas was $5.92 in 2004, $5.05 in 2003 and $3.03 in 2002.
With improved delivery capacity to California, SoCalGas alsoexpects
adequate resources to be available at prices that generally will follow
national natural gas pricing trends and volatility.
Natural Gas Storage
SoCalGas provides natural gas storage services for use by the core,
noncore and off-system customers. Core customers are allocated a
portion of SoCalGas' storage capacity. Remaining customers, including
SDG&E, can bid and negotiate the desired amount of storage on a bid and negotiated
contract basis. The storage service program provides opportunities for
customers to store natural gas, on an "as available" basis, usually during the summer to reduce
winter purchases when natural gas costs are generally higher. AsThis
allows customers to select the level of December 31, 2001, SoCalGas was storing approximately 35 bcf of
customer-owned gas.service they desire to assist
them in managing their fuel procurement and transportation needs.
9
Demand for Natural Gas
Natural gas is a principal energy source for residential, commercial,
industrial and UEG customers. Natural gas competes with electricity
forSoCalGas faces competition in the residential and commercial cooking, water heating, space heating
and clothes drying, and with other fuels for large industrial,
commercial and UEG uses. Growth incustomer
markets based on the natural-gas markets is largely
dependent upon the health and expansion of the southern California
economy. SoCalGas added approximately 58,000 new customer meters in
2001 and 69,000 in 2000, representing growth rates of approximately
1.2 percent and 1.4 percent, respectively. SoCalGas expects its growth
rate for 2002 will approximate that of 2001.
During 2001, 99 percent of residential energy customers in
SoCalGas' service area used natural gas for water heating, 96 percent
for space heating, 76 percent for cooking and 55 percent for clothes
drying.
Demandcustomers' preferences for natural gas by noncore customers is very sensitive to
the price of competing fuels. Although the number of noncore customers
in 2001 was only 1,300, it accounted for approximately 9 percent of
the authorized natural gas revenues and 69 percent of total natural
gas volumes. External factors such as weather, the price of
electricity, electric deregulation, the use of hydroelectric power,
competing pipelines and general economic conditions can result in
significant shifts in demand and market price.compared
with other energy products. The demand for natural gas by large UEG customerselectric
generators is influenced by a number of factors. In the short-term,
natural gas use by electric generators is impacted by the availability
of alternative sources of generation. The availability of
hydroelectricity is highly dependent on precipitation in the western
United States. In addition, natural gas use is impacted by the
performance of other generation sources in the western United States,
including nuclear and coal, and other natural gas facilities outside
the service area. Natural gas use is also impacted by changes in end-
use electricity demand. For example, natural gas use generally
increases during summer heat waves. Over the long-term, natural gas use
will be greatly affectedinfluenced by additional factors such as the price and
availabilitylocation
of new power plant construction. More generation capacity currently is
being constructed outside Southern California than within the utility
service area. This new generation will likely displace the output of
older, less efficient local generation, reducing the use of natural gas
for electric power generated in other areas.generation.
Effective March 31, 1998, electric industry restructuring gave
California consumersprovided out-
of-state producers the option of selecting their electricto purchase energy provider from a variety of local and out-of-state producers.for California utility
customers. As a result, natural gas demand for electric generation
within southernSouthern California competes with electric power generated
throughout the western United States. Although electric industry
restructuring has no direct impact on SoCalGas' natural gas operations,
future volumes of natural gas transported for electric generating plant
customers may be significantly affected to the extent that regulatory
changes divert electricityelectric generation from SoCalGas' service area.
Other
Additional information concerning customerGrowth in the natural gas markets is largely dependent upon the health
and expansion of the Southern California economy and prices of other
energy products. External factors such as weather, the price of
electricity, electric deregulation, the use of hydroelectric power,
competing pipelines and general economic conditions can result in
significant shifts in demand and market price. SoCalGas added 75,000
new customer meters in 2004 and 72,000 in 2003, representing growth
rates of 1.4 percent and 1.3 percent, respectively. SoCalGas expects
that its growth rate for 2005 will approximate that for 2004.
In the interruptible industrial market, customers are capable of
burning a fuel other aspectsthan natural gas. Fuel oil is the most significant
competing energy alternative. The company's ability to maintain its
industrial market share is largely dependent on price. The relationship
between natural gas supply and demand has the greatest impact on the
price of the company's product. With the reduction of natural gas
operationsproduction from domestic sources, the cost of natural gas from non-
domestic sources may play a greater role in the company's competitive
position in the future. The price of oil depends upon a number of
factors, including the relationship between world-wide supply and
demand, and the policies of foreign and domestic governments.
The natural gas distribution business is provided under "Management's Discussion and
Analysis of Financial Condition and Results of Operations" andseasonal in Notes 11 and 12 ofnature as
variations in weather conditions generally result in greater revenues
during the notes to Consolidated Financial Statements
herein.winter months when temperatures are colder. As is prevalent
10
in the industry, the company injects natural gas into storage during
the summer months (usually April through October) for withdrawal
storage during the winter months (usually November through March) when
customer demand is higher.
RATES AND REGULATION
Natural Gas Industry Restructuring
The natural gas industry in California experienced an initial phase of
restructuring during the 1980s. In December 2001 the CPUC issued a
decision adopting provisions affecting the structure of the natural
gas industry in California, some of which could introduce additional
volatility into the earnings ofInformation concerning rates and regulations applicable to SoCalGas and other market
participants. Additional information on natural gas industry
restructuring is
provided in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and in Note 12 of the
notes to Consolidated Financial Statements herein.
Balancing Accounts
In general, earnings fluctuations from changes in the costs of natural
gasNotes 1 and consumption levels for the majority of natural gas are
eliminated through balancing accounts authorized by the CPUC.
Additional information on balancing accounts is provided in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" and in Note 2 of the notes to Consolidated
Financial Statements herein.
Biennial Cost Allocation Proceeding (BCAP)
Rates to recover the changes in the cost of natural gas transportation
services are determined in the BCAP. The BCAP adjusts rates to reflect
variances in customer demand from estimates previously used in
establishing customer natural gas transportation rates. The mechanism
substantially eliminates the effect on income of variances in market
demand and natural gas transportation costs and is subject to the
limitations of the Gas Cost Incentive Mechanism (GCIM) described
below. Additional information on the BCAP is provided in "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and in Note 12 of the notes to Consolidated Financial
Statements herein.
Gas Cost Incentive Mechanism (GCIM)
The GCIM is a process SoCalGas uses to evaluate its natural gas
purchases, substantially replacing the previous process of
reasonableness reviews. Additional information on the GCIM is provided
in "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and in Note 12 of the notes to Consolidated
Financial Statements herein.
Cost of Capital
The authorized cost of capital is determined by an automatic
adjustment mechanism based on changes in certain capital market
indices. Additional information on the company's cost of capital is
provided in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and in Note 129 of the notes
to Consolidated Financial Statements herein.
ENVIRONMENTAL MATTERS
Discussions about environmental issues affecting SoCalGasthe company are
included in "Management's Discussion and AnalysisNote 10 of the notes to Consolidated Financial Condition and
Results of Operations"Statements
herein. The following additional information should be read in
conjunction with those discussions.
Hazardous Substances
In 1994, the CPUC approved the Hazardous Waste Collaborative Memorandum
account, a mechanism that allows SoCalGasallowing California's IOUs to recover in
rates thetheir hazardous waste
cleanup costs, associated with the cleanupincluding those related to Superfund sites or similar
sites requiring cleanup. Recovery of sites contaminated with
hazardous waste. In general, SoCalGas is allowed to recover 90 percent of itshazardous waste
cleanup costs and related third-party litigation costs, and 70 percent
of the related insurance-litigation expenses is permitted. In addition,
the company has the opportunity to retain a percentage of any relatedinsurance
recoveries to offset the 10 percent of costs of litigation.not recovered in rates.
During the early 1900s, SoCalGas and its predecessors manufactured gas
from coal or oil. The manufacturing sitesmanufactured-gas plants (MGPs) often have become
contaminated with the hazardous residual by-products of the process.
SoCalGas has identified 42 former manufactured-gas plantsuch sites at which it (together with other
users as to 21 of these sites) may have cleanup obligations. At a
minimum, preliminary investigations have been completed on 41 of the
sites. As of December 31, 2001, 182004, 27 of these sites have been remediated,
of which 1422 have received certification from the California
Environmental Protection Agency. Preliminary
investigations, at a minimum, have been completed on 41 of the sites.
At December 31, 2001,2004, SoCalGas'
estimated remaining investigation and remediation liability for all of these sitesthe
MGPs is $54.5$40.5 million.
SoCalGas lawfully disposeddisposes of wastes at permitted facilities owned and
operated by other entities. Operations at these facilities may result
in actual or threatened risks to the environment or public health.
Under California law, businesses that arrange for legal disposal of
wastes at a permitted facility from which wastes are later released, or
threaten to be released, can be held financially responsible for
corrective actions at the facility.
SoCalGas has been named as a potentially responsible party (PRP) for
twoone landfill sitessite and fiveone industrial waste disposal sites,site, from which
releases have occurred as described below.occurred.
Remedial actions and negotiations with other PRPs and the United States
Environmental Protection Agency have been in progress since 1986 and 1993 for
11
the twoCasmalia landfill sites.site. The company's share of costs to remediate
these sitesthis site is estimated to be $10.4 million ($0.7
million for the first site and $9.7 million for the second site). Of
this, $5.0$1.3, of which $0.9 million has been
spent since 1987 ($140,000 in 2001) and
the company recently signed a Consent Decree to settle and liquidate
all remaining liabilities at the second site for $5.7 million.
In the early 1990s, the company was notified of hazards at two
industrial waste treatment facilities in the California communities of
Fresno and Carson, where the company had disposed of wastes. During
2000, the company settled with the other PRPs at these sites for $0.4
million and has no additional liability.spent.
In December 1999, SoCalGas was notified that it is a PRP at a waste
treatment facility in Bakersfield, California. SoCalGas is working with
other PRPs in order to remove from the site certain liquid wastes that
threaten to be released. SoCalGas has reserved
$0.8 million in contingent environmental liability for itsSoCalGas' share of total site cleanup. Amounts expended to date are $0.1 million, including
$11,000 in 2001.
In March 2000, SoCalGas was notified it is a PRP at a former
mercury recycling facility in Brisbane, California. Total potential
liabilitycleanup costs is
estimated at $5,900. Settlement and payment to the State$0.7 million, of California is expected by mid-2002. Also in March 2000, SoCalGas
was sued in Federal District Court as a PRP in a waste oil disposal
site in Los Angeles. Plaintiffs alleged that SoCalGas had transported
various petroleum wastes to the site in the 1950s for recycling.
SoCalGas settled with plaintiffs in December 2000 forwhich $0.2 million.million has been spent.
At December 31, 2001, SoCalGas'2004, the company's estimated remaining investigation
and remediation liability related to hazardous waste sites, including
the manufactured gas sites,MGPs, was $54.5$41.9 million, of which 90 percent is authorized to be
recovered through the Hazardous Waste Collaborative mechanism. SoCalGasThe
company believes that any costs not ultimately recovered through rates,
insurance or other means will not have a material adverse effect on SoCalGas'the
company's consolidated results of operations or financial position.
Estimated liabilities for environmental remediation are recorded when
amounts are probable and estimable. Amounts authorized to be recovered
in rates under the Hazardous Waste Collaborative mechanism are recorded
as a regulatory asset.
Air and Water Quality
California's air quality standards are more restrictive than federal
standards. The transmission and distribution of natural gas require the
operation of compressor stations, which are subject to increasingly
stringent air-quality standards. Costs to comply with these standards
are recovered in rates.
OTHER MATTERS
Research, Development and Demonstration (RD&D)
The SoCalGas RD&D portfolio is focused in five major areas: operations,
utilization systems, power generation, public interest and
transportation. Each of these activities provides benefits to customers
and society by providing more cost-effective, efficient natural gas
equipment with lower emissions, increased safety and reduced environmental mitigation and other operating
costs. The CPUC has authorized SoCalGas to recover its operating costs
associated with RD&D. AnSoCalGas' annual average of $7.5RD&D costs have averaged $8.2
million has been spent over the lastpast three years.
Employees of Registrant
As of December 31, 2001,2004, SoCalGas had 6,0636,448 employees, compared to
5,8536,570 at December 31, 2000.
Wages2003.
Labor Relations
Field, technical and most clerical employees at SoCalGas are
represented by the Utility Workers' Union of America (UWUA) or the
International Chemical Workers' Council.Union Council (ICWUC). The collective
bargaining agreement onfor field, technical and most clerical employees
at SoCalGas covering wages, hours, and working conditions, remainsmedical and
12
various benefit plans was in effect through MarchDecember 31, 2002. Negotiations for2004. SoCalGas
has signed with UWUA and ICWUC, a new collective bargaining agreement
are currentlythat will be in progress.effect from January 1, 2005 through September 30, 2008.
ITEM 2. PROPERTIES
Natural Gas Properties
At December 31, 2001, SoCalGas owned approximately 2,8452004, SoCalGas' natural gas facilities included 2,830
miles of transmission and storage pipeline, 45,62047,307 miles of
distribution pipeline and 44,86845,954 miles of service piping. ItThey also
owned 10included 11 transmission compressor stations and 64 underground storage
reservoirs, with a combined working capacity of 121.1122 billion cubic feet.
Other Properties
SoCalGas has a 15-percent limited partnership interest inleases approximately half of a 52-story office building in
downtown Los Angeles. SoCalGas leases approximately
half of the buildingAngeles through the year 2011. The lease has six separate five-year
renewal options.
The company owns or leases other offices, operating and maintenance
centers, shops, service facilities and equipment necessary in the
conduct of its business.
ITEM 3. LEGAL PROCEEDINGS
Except for the matters described in Note 1110 of the notes to
Consolidated Financial Statements or referred to elsewhere in this
Annual Report, neither the companycompanies nor itstheir subsidiaries are party
to, nor is their property the subject of, any material pending legal
proceedings other than routine litigation incidental to their
businesses.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.None
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
As a result of the formation of Sempra Energy as described in Note 1
of notes to Consolidated Financial Statements, allAll of the issued and outstanding common stock of PE is owned by Sempra
Energy. The information required by Item 5 concerning dividends
declared is included in the "Statements of Consolidated Changes in
Shareholders' Equity" set forth in Item 8 of this Annual Report herein.
13
ITEM 6. SELECTED FINANCIAL DATA
(Dollars in millions) At December 31, or for the years then ended
------------------------------------------------
Pacific Enterprises:- ------------------------------------------------------------------------------------
2004 2003 2002 2001 2000
1999 1998 1997
-------- ------- ------- ------- ------------- ------ ------ ------ ------
Pacific Enterprises:
Income Statement Data:
Operating revenues $3,716 $2,854 $2,569 $2,472 $2,738$ 3,997 $ 3,544 $ 2,858 $ 3,716 $ 2,854
Operating income $ 235 $ 237 $ 246 $ 269 $ 263 $ 271 $ 218 $ 259
Dividends on preferred stock $ 4 $ 4 $ 4 $ 4 $ 4
Earnings applicable to
common shares $ 232 $ 217 $ 209 $ 202 $ 207 $ 180 $ 143 $ 180
Balance Sheet Data:
Total assets $4,191 $4,756 $4,110 $4,571 $4,977$ 5,953 $ 5,833 $ 5,883 $ 5,414 $ 5,957
Long-term debt $ 864 $ 762 $ 657 $ 579 $ 821
$ 939 $ 985 $1,118
Short-term debt (a)* $ 30 $ 175 $ 175 $ 150 $ 120
$ 30 $ 249 $ 502
Shareholders' equity $1,574 $1,526 $1,426 $1,547 $1,469
(a) Includes long-term debt due within one year.
Since Pacific Enterprises is a wholly owned subsidiary of Sempra
Energy, per share data has been omitted.
At December 31, or for the years then ended
------------------------------------------------$ 1,814 $ 1,697 $ 1,684 $ 1,574 $ 1,526
SoCalGas: 2001 2000 1999 1998 1997
-------- ------- ------- ------- -------
Income Statement Data:
Operating revenues $3,716 $2,854 $2,569 $2,427 $2,641$ 3,997 $ 3,544 $ 2,858 $ 3,716 $ 2,854
Operating income $ 238 $ 223 $ 242 $ 273 $ 266
$ 268 $ 238 $ 318
Dividends on preferred Stockstock $ 1 $ 1 $ 1 $ 1 $ 71
Earnings applicable to
Commoncommon shares $ 232 $ 209 $ 212 $ 207 $ 206 $ 200 $ 158 $ 231
Balance Sheet Data:
Total assets $3,762 $4,128 $3,452 $3,834 $4,205$ 5,502 $ 5,349 $ 5,403 $ 4,986 $ 5,329
Long-term debt $ 864 $ 762 $ 657 $ 579 $ 821
$ 939 $ 967 $ 968
Short-term debt (a)* $ 30 $ 175 $ 175 $ 150 $ 120
$ 30 $ 75 $ 498
Shareholders' equity $1,327 $1,309 $1,310 $1,382 $1,467
(a) Includes$ 1,407 $ 1,376 $ 1,340 $ 1,327 $ 1,309
- ------------------------------------------------------------------------------------
*Includes long-term debt due within one year.
Since Pacific Enterprises is a wholly owned subsidiary of Sempra Energy
and SoCalGas is a wholly owned subsidiary of Pacific Enterprises, per
share data has been omitted.is not provided.
This data should be read in conjunction with the Consolidated Financial
Statements and the notes to Consolidated Financial Statements contained
herein.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
-- Pacific Enterprises and Southern
California Gas Company
IntroductionINTRODUCTION
This section of the 2004 Annual Report includes management's discussion
and analysis of operating results from 19992002 through 2001,2004, and provides
information about the capital resources, liquidity and financial
performance of Pacific Enterprises (PE) and Southern California Gas
Company (SoCalGas). SoCalGas, PE or the two together are referred to as
the
company"the company" herein, the distinction being indicated by the context.
ItThis section also focuses on the major factors expected to influence
future operating results and discusses investment and financing14
activities and plans. It should be read in conjunction with the
Consolidated Financial Statements included in this Annual Report.
PE is athe holding company whose only direct subsidiary isfor SoCalGas, the nation's largest natural
gas distribution utility. SoCalGas owns and operates a natural gas
distribution, transmission and storage system supplying natural gas
throughout a 23,000-square mileapproximately 20,000 square miles of service territory. Its
service territory comprising mostextends from San Luis Obispo on the north to the
Mexican border in the south, excluding San Diego County, the City of
southern CaliforniaLong Beach and partthe desert area of central
California.San Bernardino County. SoCalGas
provides natural gas service to residential, commercial, industrial,
utility electric generation and wholesale customers, through 55.5
million meters in a service area with a population of 1819.5 million.
Business Combination
Sempra Energy was formed as a holding company for PESoCalGas and Enova
Corporation (Enova), the parent corporation ofits sister utility, San Diego Gas & Electric Company (SDG&E), in connection with a business combination
that was completed on June 26, 1998 (the business combination). In
connection with the business combination, the holders of common stock
of PE and Enova became the holders of Sempra Energy's common stock.
As a resultare
collectively referred to herein as "the California Utilities."
RESULTS OF OPERATIONS
The following table shows net income for each of the business combination,last five years.
(Dollars in millions)
- -----------------------------------------
PE dividended its
nonutility subsidiaries to Sempra Energy during 1998 and early 1999.
See Note 1 of the notes to the Consolidated Financial Statements for
additional information.
Capital Resources And Liquidity
SoCalGas' operations have historically been a major source of
liquidity. 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 December 31,SoCalGas
---------- ----------
2004 $ 236 $ 233
2003 $ 221 $ 210
2002 $ 213 $ 213
2001 the company had $13 million in cash and
$620 million in unused, committed lines of credit (of which SoCalGas
had $120 million in unused lines of credit). Construction, investment
and financing programs are continuously reviewed and revised in
response to changes in competition, customer growth, inflation,
customer rates, the cost of capital, and environmental and regulatory
requirements. Management believes that cash flows from operations and
from debt issuances are adequate to meet capital expenditure
requirements and other commitments.
Cash Flows From Operating Activities
The decrease in cash flows from operating activities in 2001 compared
to$ 206 $ 208
2000 was the result of SoCalGas' balancing account activity. This
included returns of prior overcollections and the temporary effects of
higher-than-expected costs of natural gas and public purpose programs
and lower-than expected sales volumes. The increase in cash flows from
operating activities in 2000 was primarily due to higher accounts
payable and overcollected regulatory balancing accounts, partially
offset by increased accounts receivable. The increases in accounts
payable and accounts receivable were primarily due to higher prices
for natural gas. The regulatory balancing account overcollections
resulted from higher sales volume and the actual cost of gas being
slightly lower than amounts being collected in rates on a current
basis.
Cash Flows From Investing Activities
Cash flow used in investing activities decreased in 2001 due to loan
repayments being made by Sempra Energy to the company in 2001 compared
to loans being made to Sempra Energy in 2000, partially offset by an
increase in capital expenditures for utility plant. Capital
expenditures were $294 million in 2001, compared to $198 million and
$146 million in 2000 and in 1999, respectively. Increases in capital
expenditures in 2001 and 2000 were primarily due to improvements to
the gas distribution system and expansion of pipeline capacity to meet
increased demand by electric generators and by commercial and
industrial customers.
Over the next five years, the company expects to make capital
expenditures of approximately $2.0 billion. Capital expenditures in
2002 are expected to be comparable to those of 2001. They will be
financed primarily by operations and debt issuances.
Construction, investment and financing programs are continuously
reviewed and revised by the company in response to changes in economic
conditions, competition, customer growth, inflation, customer rates, the cost
of capital, and environmental and regulatory requirements.
Cash Flows From Financing Activities
Net cash used in financing activities increased in 2001 compared to
2000 primarily due to the increase in long-term debt repayments and
higher dividends paid by PE in 2001.
Net cash used in financing activities decreased in 2000 compared
to 1999 primarily due to lower long-term debt repayments. For
SoCalGas, the decrease was also attributable to lower dividends paid
in 2000.
Long-Term and Short-Term Debt
In 2001, cash was used for the repayment of $150 million of first-
mortgage bonds and $120 million of unsecured notes. PE had an
offsetting increase of $50 million in short-term debt.
Cash was used for the repayment of $30 million of unsecured notes
in 2000. In 1999, cash was used for the repayment of $75 million of
unsecured notes. PE also repaid $43 million of short-term debt.
Dividends
Dividends paid to Sempra Energy amounted to $190 million in 2001 and
$100 million in each of 2000 and 1999. Dividends paid by SoCalGas to
PE amounted to $190 million, $200 million and $278 million in 2001,
2000 and 1999, respectively.
The payment of future dividends and the amount thereof are within
the discretion of the companies' boards of directors. The CPUC's
regulation of SoCalGas' capital structure limits to $280 million the
portion of its December 31, 2001 retained earnings that is available
for dividends to PE.
Capitalization
Total capitalization at December 31, 2001, was $2.3 billion of which
$2.1 billion applied to SoCalGas. The debt-to-capitalization ratios
were 32 percent and 35 percent at December 31, 2001 for PE and
SoCalGas, respectively. Significant changes in capitalization during
2001 included dividends declared and repayment of long-term debt.
Cash and Cash Equivalents
Cash and cash equivalents are available for investment in projects
consistent with the company's strategic direction, retirement of debt,
payment of dividends and other corporate purposes.
In addition to cash generated from ongoing operations, PE has a
credit agreement which permits short-term borrowings of up to $500
million, and/or supports its commercial paper. This agreement expires
in 2003. SoCalGas has a $170 million line of credit which expires in
2002. These revolving lines of credit were unused at December 31, 2001
and 2000. At December 31, 2001, SoCalGas had $50 million in short-term
debt outstanding.
Commitments
The following is a summary of the company's contractual commitments at
December 31, 2001 (in millions of dollars). Additional information
concerning these commitments is provided above and in Notes 3, 4 and
11 of the notes to Consolidated Financial Statements.
By Period
-----------------------------------------------
Less than 2-3 4-5 More than
Description 1 year years years 5 years Total
- ---------------------------------------------------------------------------
SoCalGas:
Short-term debt $ 50 $ -- $ -- $ -- $ 50
Long-term debt 100 175 -- 404 679
Natural gas contracts 614 504 262 -- 1,380
Operating leases 30 61 61 172 324
Environmental commitments 12 22 21 -- 55
-----------------------------------------------
Total 806 762 344 576 2,488
PE - operating leases 12 24 26 45 107
-----------------------------------------------
Total PE consolidated $ 818 $ 786 $ 370 $ 621 $2,595
===============================================
Results of Operations$ 211 $ 207
- -----------------------------------------
To understand the operations and financial results of the company, it
is important to understand the ratemaking procedures that SoCalGas
follows.to which the
company is subject.
SoCalGas is regulated by the CPUC. Itsubject to various regulatory bodies and rules at national,
state and local levels. The primary regulatory body is the responsibilityCalifornia
Public Utilities Commission (CPUC), which regulates utility rates and
operations. The Federal Energy Regulatory Commission (FERC) regulates
interstate transportation of natural gas and various related matters.
Municipalities and other local authorities regulate the CPUC to determine that utilities operate in the best interestslocation of
their customers and have the opportunity to earn a reasonable return
on investment.utility assets, including natural gas pipelines.
The natural gas industry experienced an initial phase of restructuring
during the 1980s by deregulating natural gas sales to noncore
customers. In December 2001, the CPUC issued a decision
adopting several provisions that the company believes will make gas
service more reliable, efficient and better tailoredFurther restructuring continues to the desires of
customers. The CPUC is still considering the schedule for
implementation of these regulatory changes, but it is expected that
most of the changes will be implemented during 2002.
In connection with restructuring of energy regulation, SoCalGas
received approval from the CPUC for Performance-Based Ratemaking (PBR).
Under PBR, income potential is tied to achieving or exceeding specific
performance and productivity measures, rather than to expanding utility
plant in a market where a utility already has a highly developed
infrastructure.
See additional discussions of natural gas-industry restructuring
below under "Factors Influencing Future Performance" andconsidered, as
discussed in Note 129 of the notes to Consolidated Financial Statements.
Natural Gas Revenue and Cost of Natural Gas. Natural gas revenues
increased to $4.0 billion in 2004 from $3.5 billion in 2003, and the
cost of natural gas increased to $2.3 billion in 2004 from $1.8 billion
in 2003. The increases were primarily attributable to natural gas cost
increases, which are passed on to customers. For natural gas revenues,
this increase was offset by $48 million of Gas Cost Incentive Mechanism
(GCIM) awards and $1 million of Performance-Based Regulation (PBR)
awards recognized during 2003. Performance awards are discussed in Note
15
9 of the notes to Consolidated Financial Statements. SoCalGas' weighted
average cost per million British thermal units (mmbtu) of natural gas
was $5.92 in 2004, $5.05 in 2003 and $3.03 in 2002.
Under the current regulatory framework, the cost of natural gas
purchased for customers and the variations in that cost are passed
through to the customers on a substantially concurrent basis. However,
SoCalGas' GCIM allows SoCalGas to share in the savings or costs from
buying natural gas for customers below or above market-based 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. Further discussion is provided in Notes 1 and 9 of the
notes to Consolidated Financial Statements.
Natural gas revenues increased to $3.5 billion in 2003 from $2.9
billion in 2002, and the cost of natural gas increased to $1.8 billion
in 2003 from $1.2 billion in 2002. The change was primarily
attributable to natural gas price increases, partially offset by
reduced volumes. Revenues also increased due to the performance awards
recognized during 2003.
16
The table below summarizes SoCalGas' natural gas volumes and revenues
by customer class:class for the years ended December 31, 2004, 2003 and 2002.
NATURAL GAS SALES, TRANSPORTATION AND EXCHANGE
(Dollars in millions, volumes in billion cubic feet)
For the years ended December 31
Natural Gas Sales Transportation & Exchange Total
------------------------------------------------------------------------ ---------------------------------------------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
------------------------------------------------------------------------ ---------------------------------------------------------------------------------------------
2001:2004:
Residential 263 $2,336254 $ 2,572 2 $ 6 265 $2,3427 256 $ 2,579
Commercial and industrial 95 670 258 157 353 827108 871 273 195 381 1,066
Electric generation plants -- -- 361 86 361 86178 54 178 54
Wholesale -- -- 174 36 174 36
-----------------------------------------------------------------------
358 $3,006 795 $285 1,153 3,291156 45 156 45
---------------------------------------------------------------
362 $ 3,443 609 $ 301 971 3,744
Balancing accounts and other 425
---------253
--------
Total $3,716$ 3,997
- ---------------------------------------------------------------------------------------------
2000:2003:
Residential 251 $2,167 3241 $ 12 254 $2,1792,188 2 $ 7 243 $ 2,195
Commercial and industrial 86 621 317 209 403 830106 741 273 184 379 925
Electric generation plants -- -- 310 106 310 106179 49 179 49
Wholesale -- -- 166 54 166 54
-----------------------------------------------------------------------
337 $2,788 796 $381 1,133 3,169138 34 138 34
---------------------------------------------------------------
347 $ 2,929 592 $ 274 939 3,203
Balancing accounts and other (315)
---------341
--------
Total $2,854$ 3,544
- ---------------------------------------------------------------------------------------------
1999:2002:
Residential 275 $1,821 3256 $ 10 278 $1,8311,843 2 $ 7 258 $ 1,850
Commercial and industrial 84 452 306 229 390 681100 537 289 168 389 705
Electric generation plants -- -- 188 77 188 77201 38 201 38
Wholesale -- -- 150 57 150 57
-----------------------------------------------------------------------
359 $2,273 647 $373 1,006 2,646156 23 156 23
---------------------------------------------------------------
356 $ 2,380 648 $ 236 1,004 2,616
Balancing accounts and other (77)
---------242
--------
Total $2,569$ 2,858
- ---------------------------------------------------------------------------------------------
2001 Compared to 2000
Net income for SoCalGas increased to $208 million in 2001 compared to
$207 million in 2000 primarily due to higher gas volumes in 2001,
offset by the gain on sale of SoCalGas' investment in Plug Power
during 2000. In addition to the above factors, PE's net income
included less interest income from affiliates in 2001. Net income for
the fourth quarter of 2001 decreased compared to the fourth quarter of
2000 for both SoCalGas and PE. The decrease was primarily due to the
sale of the investment in Plug Power during the fourth quarter of
2000.
Natural gas revenues increased from $2.9 billion in 2000 to $3.7
billion in 2001, and the cost of natural gas distributed increased
from $1.4 billion in 2000 to $2.1 billion in 2001. These increases
were due to higher average gas prices and higher volumes of gas sales
in 2001. Under the current regulatory framework, changes in core-
market natural gas prices (gas purchased for customers who are
primarily residential and small commercial and industrial customers,
without alternative fuel capability) do not affect net income, since
current or future core customer rates generally recover the actual
cost of natural gas on a substantially concurrent basis. See
discussion of balancing accounts in Note 2 of the notes to
Consolidated Financial Statements.Other Operating Expenses. Other operating expenses increasedat SoCalGas were
$950 million, $954 million and $872 million in 2001 compared to 2000 due
to higher costs for company-use fuel (as a result of higher gas
prices), higher employee benefit expenses2004, 2003 and operation costs covered
by balancing accounts.
2000 Compared to 1999
Net income for 2000 increased compared to net income in 1999. The
increase was primarily due to higher non-core gas throughput, the gain
on sale of SoCalGas' investment in Plug Power noted above, and lower
operating and maintenance expenses. For the fourth quarter of 2000,
net income for SoCalGas decreased compared to the fourth quarter of
1999.2002,
respectively. The decrease in 2004 was due primarily due to the favorable
resolution of income taxregulatory issues in 1999, partially offset by higher non-core gas
throughputlitigation costs.
Additionally, operating expenses in 2003 include charges for litigation
costs and the salefor losses associated with a sublease of portions of the
investment in Plug Power. In addition
to the above factors, net income for PE increased in the fourth
quarter of 2000 due to higher expenses associated with other, former
PE subsidiaries in 1999.
Natural gas revenues increased from $2.6 billion in 1999 to $2.9
billion in 2000, primarily due to higher prices for natural gas in
2000 and higher revenues from electric-generation customers.SoCalGas headquarters building. The increase in 2003 compared to 2002
was primarily the result of these revenues was due tocharges, as well as higher demand for electricitylabor and
employee benefits costs. During 2002, the company recorded $13 million
in 2000 which increased prices and volumes.
The cost of natural gas distributed increased from $1.0 billion
in 1999 to $1.4 billion in 2000. The increase was largely due to
higher prices for natural gas. Prices for natural gas have increased
duelitigation costs related to the increased use of natural gas to fuel electric generation,
colder winter weather and population growth in California.California energy crisis.
Other operating expenses decreased in 2000 compared to 1999
primarily due to lower pension expense in 2000.
Other Income and Deductions, Interest Expense and Income Taxes
Other Income and DeductionsIncome. Other income and deductions consist primarily of interest
income from short-term investments, and interest income or income/expense from
regulatory balancing accounts. This decreasedaccounts and allowance for equity funds used
during construction. Excluding the impact of income taxes on non-
operating income, other income at SoCalGas was $31 million, $40
million, and $10 million in 2001 as2004, 2003 and 2002, respectively. The
17
decrease in 2004 was due to higher interest income in 2003 resulting
from the favorable $30 million before-tax resolution of income-tax
issues with the Internal Revenue Service (IRS), offset by the $15
million before-tax gain from the sale of partnership property in 2004.
The increase in 2003 compared to 20002002 was due to lowerhigher interest from affiliates,income
as discussed above.
Income Taxes. Income tax expense at SoCalGas was $154 million, $150
million and $178 million in 2004, 2003 and 2002, respectively. The
corresponding effective income tax rates were 39.8 percent, 41.7
percent and 45.5 percent. The decreases in 2003 compared to 2002 were
due to the 2000$12 million favorable resolution of income-tax issues in the
fourth quarter of 2003. In addition, income before taxes in 2003
included $30 million in interest income arising from the income tax
settlement, resulting in an offsetting $13 million income tax expense.
Net Income. SoCalGas recorded net income of $233 million, $210 million
and $213 million in 2004, 2003 and 2002, respectively. The increase in
2004 was due to higher margins, the resolution of the 2004 cost of
service proceedings, which favorably impacted net income by $34
million, and the $9 million after-tax gain on the sale of SoCalGas' investment in Plug Power. Otherpartnership
property, offset by $24 million of litigation costs. Additionally, 2003
net income increased in 2000was affected by the $32 million after-tax charge for
litigation costs and for losses associated with a long-term sublease of
portions of its headquarters building, offset by the favorable
resolution of income tax issues and by higher GCIM awards.
The decrease for 2003 compared to 19992002 was due primarily to the
litigation charges and sublease losses in 2003 and the end of sharing
of merger savings (which favorably impacted earnings by $17 million for
the year ended December 31, 2002), offset by the resolution of income
tax issues and higher GCIM awards in 2003.
CAPITAL RESOURCES AND LIQUIDITY
SoCalGas' operations are the major source of liquidity. 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 December 31, 2004, the company had $34 million in unrestricted cash
and $770 million in available unused, committed lines of credit, of
which PE had $500 million for the sole purpose of providing loans to
Sempra Global, another subsidiary of Sempra Energy, and SoCalGas had
$270 million.
Management believes that these amounts and cash flows from operations
and debt issuances will be adequate to finance capital expenditures and
meet liquidity requirements and other commitments. Forecasted capital
expenditures for the next five years are discussed in "Future Capital
Expenditures for Utility Plant". 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
18
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 consolidated operating activities totaled
$544 million, $375 million and $521 million for 2004, 2003 and 2002,
respectively. Net cash provided by SoCalGas' operating activities
totaled $501 million, $385 million and $527 million for 2004, 2003 and
2002, respectively.
The increase in net cash provided by operating activities was due to
changes in regulatory balancing accounts in 2004, offset by a higher
increase in accounts receivable in 2004.
The decrease in 2003 compared to 2002 was primarily attributable to
SoCalGas' decrease in overcollected regulatory balancing accounts in
2003 resulting from higher natural gas prices and lower usage and the
refunding of customer deposits, offset by lower tax payments in 2003.
During 2004, the company contributed $42 million to other postretirement
benefit plans but made no contribution to the pension plan.
CASH FLOWS FROM INVESTING ACTIVITIES
Net cash used in PE's consolidated investing activities totaled $293
million, $216 million and $508 million for 2004, 2003 and 2002,
respectively. Net cash used in SoCalGas' investing activities totaled
$253 million, $279 million and $417 million for 2004, 2003 and 2002,
respectively. The increase in cash used in investing activities was due
to lower affiliate loan repayments received in 2004. For SoCalGas, the
decrease in cash used in investing activities was due to higher
repayments received from Sempra Energy in 2004.
PE's decrease in 2003 compared to 2002 was primarily due to higher interest earnedthe $97
million repayment from Sempra Energy in 2003 compared to $177 million
of advances to Sempra Energy in 2002. For SoCalGas, the change in 2003
compared to 2002 was the same as PE except that SoCalGas received $34
million of the $97 million repayment in 2003 and made $86 million of
the $177 million in advances to Sempra Energy in 2002. Advances to
Sempra Energy are payable on loansdemand.
Future Capital Expenditures for Utility Plant
Significant capital expenditures in 2005 are expected to affiliates, and also dueinclude $350
million for improvements to the gain recognized ondistribution and transmission systems.
These expenditures are expected to be financed by cash flows from
operations and debt issuances.
Over the salenext five years, the company expects to make capital
expenditures of Plug
Power.
Interest Expense
Interest expense decreased in 2001 as compared to 2000 due to
SoCalGas' repayments of $270$1.8 billion, including $350 million in long-term debt duringeach of the
fourth quarternext five years.
Construction programs are periodically reviewed and revised by the
company in response to changes in economic conditions, competition,
19
customer growth, inflation, customer rates, the cost of 2001,capital, and
alsoenvironmental and regulatory requirements.
CASH FLOWS FROM FINANCING ACTIVITIES
Net cash used in PE's consolidated financing activities totaled $249
million, $149 million and $4 million for 2004, 2003 and 2002,
respectively. Net cash used in SoCalGas' financing activities totaled
$246 million, $96 million and $101 million for 2004, 2003 and 2002,
respectively.
The cash used in financing activities for 2004 increased due to lower
interest expenseissuances of long-term debt, offset by lower payments on long-term
debt. The increase in PE's cash used in financing activities in 2003
was attributable to affiliates. Interest expense increasedhigher repayments on long-term debt and an increase
of $150 million in 2000 as compareddividends paid to 1999
primarily due to SoCalGas' 1999 reversal of previously accrued
interest related to income-tax issues as a result of favorable income-
tax rulings.
Income Taxes
Income tax expense decreasedSempra Energy in 2001 as compared to 2000 due to lower
income before taxes, and higher deductions related to capitalized
costs. Income tax expense at PE increased in 2000 as compared to 1999
primarily due to2003, offset by
an increase in income before taxes.
Factors Influencing Future Performancethe issuances of long-term debt. The change in SoCalGas'
net cash used in financing activities is the same as PE, except for
dividends paid to PE, which are unchanged from 2002 to 2003.
Long-Term and Short-Term Debt
In December 2004, SoCalGas issued $100 million of floating-rate first
mortgage bonds maturing in December 2009. The interest rate is based on
the 3-month LIBOR rate plus 0.17%.
Repayments on long-term debt in 2004 included $175 million of SoCalGas'
first mortgage bonds.
In 2003, SoCalGas issued $500 million of first mortgage bonds.
Repayments on long-term debt in 2003 included $325 million of SoCalGas'
first mortgage bonds. In addition, $70 million of SoCalGas' $75
million medium-term notes were put back to the company.
In October 2002, SoCalGas publicly offered and sold $250 million of
4.80% first mortgage bonds, maturing in October 2012.
Repayments on long-term debt in 2002 included $100 million of first
mortgage bonds.
In May 2004, the California Utilities obtained a combined $500 million
three-year syndicated revolving credit facility to replace their
expiring 364-day facility of a like amount. No amounts were outstanding
under this facility at December 31, 2004. SoCalGas had $30 million of
commercial paper outstanding at December 31, 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. No amounts were
outstanding under this facility at December 31, 2004.
Notes 2 and 3 of the notes to Consolidated Financial Statements provide
further discussion of debt activity and lines of credit.
20
Dividends
Common dividends paid to Sempra Energy were $200 million in 2004,
compared to $250 million in 2003 and $100 million in 2002. Dividends
paid by SoCalGas to PE amounted to $200 million in each of 2004, 2003
and 2002.
The payment and amount of future dividends are within the discretion of
the companies' boards of directors. The CPUC's regulation of SoCalGas'
capital structure limits the amounts that are available for loans and
dividends to Sempra Energy from SoCalGas. At December 31, 2004, the
company could have provided a total (combined loans and dividends) of
$200 million to Sempra Energy.
Capitalization
Total capitalization, including short-term debt and the current portion
of long-term debt, at December 31, 2004 was $2.7 billion, of which $2.3
billion applied to SoCalGas. The debt-to-capitalization ratios were 33
percent and 39 percent at December 31, 2004 for PE and SoCalGas,
respectively.
Commitments
The following is a summary of the company's principal contractual
commitments at December 31, 2004. Liabilities related to fixed-price
contracts and other derivatives are excluded as they are primarily
offset against regulatory assets and will be recovered from customers
through the ratemaking process. Additional information concerning
commitments is provided above and in Notes 3, 5 and 10 of the notes to
Consolidated Financial Statements.
21
2006 2008
and and
(Dollars in millions) 2005 2007 2009 Thereafter Total
- -------------------------------------------------------------------------------
SOCALGAS
Short-term debt $ 30 $ -- $ -- $ -- $ 30
Long-term debt -- 8 100 756 864
Interest on debt (1) 37 74 74 160 345
Natural gas contracts 921 128 5 -- 1,054
Operating leases 43 89 92 91 315
Environmental commitments 14 28 -- -- 42
Pension and postretirement
benefit obligations (2) 136 295 326 939 1,696
Asset retirement obligations 1 3 1 4 9
---------------------------------------------------
Total 1,182 625 598 1,950 4,355
PE - operating leases 13 26 28 7 74
---------------------------------------------------
Total PE consolidated $1,195 $ 651 $ 626 $1,957 $4,429
- -------------------------------------------------------------------------------
(1) Based on rates in effect at December 31, 2004.
(2) Amounts are before reduction for the Medicare Part D subsidy and only include
expected payments for the next 10 years.
Credit Ratings
Credit ratings of the company remained at investment grade levels in
2004. As of January 31, 2005, company credit ratings were as follows:
Standard Moody's Investor
& Poor's Services, Inc. Fitch
- ----------------------------------------------------------------
SOCALGAS
Secured debt A+ A1 AA
Unsecured debt A- A2 AA-
Preferred stock BBB+ Baa1 A+
Commercial paper A-1 P-1 F1+
------------------------------------
PE - preferred stock BBB+ - A
- ----------------------------------------------------------------
As of January 31, 2005, SoCalGas has a stable outlook rating from all
three credit rating agencies.
FACTORS INFLUENCING FUTURE PERFORMANCE
Performance of PE in the near futurecompanies will depend primarily on the results of
SoCalGas. The factors influencing SoCalGas' future performance are
summarized below.
Natural Gas Restructuringratemaking
and Gas Rates
On December 11, 2001, the CPUC issued a decision adopting the
following provisions affecting the structure of theregulatory process, natural gas industry in California, some of which could introduce additional
volatility into the earnings of SoCalGas and other market
participants: a system for shippers to hold firm, tradable rights to
capacity on SoCalGas' major gas transmission lines with SoCalGas'
shareholders at risk for whether market demand for these rights will
cover the cost of these facilities; a further unbundling of SoCalGas'
storage services, giving SoCalGas greater upward pricing flexibility
(except for storage service for core customers) but with increased
shareholder risk for whether market demand will cover storage costs;
new balancing services including separate core and noncore balancing
provisions; a reallocation among customer classes of the cost of
interstate pipeline capacity held by SoCalGas and an unbundling of
interstate capacity for gas marketers serving core customers;restructuring, and the
elimination of noncore customers' option to obtain gas supply service
from SoCalGas. The CPUC is still considering the schedule for
implementation of these regulatory changes, but it is expected that
most of the changes will be implemented during 2002.
Allowed Rate of Return
SoCalGas is authorized to earn a rate of return on rate base (ROR) of
9.49 percent and a rate of return on common equity (ROE) of 11.6
percent, the same as in 2001 and 2000.changing energy marketplace. These rates will continue to be
effective until the next periodic review by the CPUC unless interest-
rate changesfactors are large enough to trigger an automatic adjustment prior
thereto. SoCalGas can earn more than the authorized rate by
controlling costs below approved levels or by achieving favorable
results in certain areas, such as various incentive mechanisms. In
addition, earnings are affected by changes in sales volumes, except
for the majority of core sales.
Utility Integration
On September 20, 2001 the CPUC approved Sempra Energy's request to
integrate the management teams of SoCalGas and SDG&E. The decision
retains the separate identities of each utility and is not a merger.
Instead, utility integration is a reorganization that consolidates
senior management functions of the two utilities and returns to the
utilities a significant portion of shared support services currently
provided by Sempra Energy's centralized corporate center. Once
implementation is completed, the integration is expected to result in
more efficient and effective operations.
In a related development, a CPUC draft decision would allow
SoCalGas and SDG&E to combine their natural gas procurement
activities. The CPUC is scheduled to act on the draft decision at its
April 4, 2002 meeting.
Environmental Matters
The company's operations are subject to federal, state and local
environmental laws and regulations governing such things as hazardous
wastes, air and water quality, land use, solid-waste disposal and the
protection of wildlife.
Utility capital costs to comply with environmental requirements
are generally recovered through customer rates. Therefore, the
likelihood of the company's financial position or results of
operations being adversely affected in a significant manner is
believed to be remote.
The environmental issues currently facing the company or resolved
during the latest three-year period include investigation and
remediation of its manufactured-gas sites and cleanup of third-party
waste-disposal sites used by the company. See additional discussions
of environmental issuesdiscussed in Note 119 of
the notes to Consolidated Financial Statements.
Market Risk
Market risk is the risk of erosion of the company's cash flows, net
income, asset values and equity due to adverse changes in prices for
natural gas,various commodities, and in interest rates.
The company's policy is to use derivative financial instruments
to reduce its exposure to fluctuations in interest rates and natural
gas prices. Transactions involving these financial instruments are
with firms believed to be credit-worthy and major exchanges. The use
of these instruments exposes the company to market and credit risks
which, at times, may be concentrated with certain counterparties.
There were no unusual concentrations at December 31, 2001 that would
indicate an unacceptable level of risk.
SoCalGas uses energy derivatives to manage natural gas price risk
associated with servicing its load requirements. In addition, SoCalGas
makes limited use of natural gas derivatives for trading purposes.
These instruments can include forward contracts, futures, swaps,
options and other contracts. In the case of both price-risk management
and trading activities, the use of derivative financial instruments by
the company is subject to certain limitations imposed by company
policy and regulatory requirements. See Note 8 of the notes to
Consolidated Financial Statements for further information regarding
the use of energy derivatives by the company.
Sempra Energy has adopted corporate-wide policies governing its market-riskmarket
risk management and trading activities. AnAssisted by Sempra Energy's Energy Risk
22
Management Group (ERMG), Sempra Energy's Energy Risk Management
Oversight Committee (ERMOC), consisting of senior officers, oversees
company-wide energy risk management activities and monitors the results
of activities to ensure compliance with Sempra Energy'sthe company's stated energy-riskenergy
risk management policies. Utility management receives daily information
on positions and trading policies.the ERMG receives information detailing positions
creating market and credit risk for the company, consistent with
affiliate rules. The ERMG independently measures and reports the market
and credit risk associated with these positions. In addition, SoCalGas' risk-management committeethe ERMOC
monitors and controls energy-priceenergy price risk management and trading activities independently from the
employeesgroups responsible for creating or actively managing these risks.
Along with other tools, the company uses Value at Risk (VaR) to measure
its exposure to market risk. VaR is an estimate of the potential loss
on a position or portfolio of positions over a specified holding
period, based on normal market conditions and within a given
statistical confidence interval. The company has adopted the
variance/covariance methodology in its calculation of VaR, and uses
both the 95-percent and 99-percent confidence interval. Holding
periods are specific tointervals. VaR is
calculated independently by the types of positions being measured, and are
determined based onERMG for the size of the position or portfolios, market
liquidity, purpose and other factors.company. Historical
volatilities and correlations between instruments and positions are
used in the calculation. As of December 31, 2001,2004, the total VaR of SoCalGas'the
company's natural gas positions was not material.
The company uses energy and natural gas derivatives to manage natural
gas price risk associated with servicing its load requirements. The use
of derivative financial instruments is subject to certain limitations
imposed by company policy and regulatory requirements.
Revenue recognition is discussed in Note 1 and the additional market
risk information regarding derivative instruments is discussed in Note
7 of the notes to Consolidated Financial Statements.
The following discussion of the company's primary market-riskmarket risk exposures
as of December 31, 2001,2004 includes furthera discussion of how these exposures
are managed.
Commodity-PriceCommodity Price Risk
Market risk related to physical commodities is based upon potential
fluctuationscreated by volatility in
the prices and basis of natural gas. The company's market risk is
impacted by changes in volatility and liquidity in the markets in which
natural gasthese commodities or related financial instruments are traded. The
company is exposed, in varying degrees, to price risk primarily in the
natural gas markets. The company's policy is to manage this risk within
a framework that considers the unique markets, and operating and
regulatory environments.
SoCalGas'The company's market risk exposure is limited due to CPUC-authorized
rate recovery of natural gas purchase, sale, intrastate transportation
and storage activity. However, the company may, at times, it may be exposed to limited
market risk as a result of activities under the Gas Cost Incentive Mechanism (GCIM),SoCalGas' GCIM, which is discussed in Note 129
of the notes to Consolidated Financial Statements. SoCalGasIf commodity prices
were to rise too rapidly, it is likely that volumes would decline. This
would increase the per-unit fixed costs, which could lead to further
volume declines. The company manages thisits risk within the parameters of
23
the company's market-riskmarket risk management and trading framework. Interest-RateAs of December 31,
2004, the company's exposure to market risk was not material.
Interest Rate Risk
The company is exposed to fluctuations in interest rates primarily as a
result of its fixed-rate long-term debt. The company historically has historically funded utility
operations through long-term debt issues with fixed interest rates and
these interest rates are recovered in utility rates. With the restructuring of the regulatory process, the
CPUC has permitted greater flexibility within the debt-management
process. As a result,Some recent debt
offerings have been selected with
short-term maturities to take advantage of yield curves, or have used a combination of fixed-rate and floating-rate debt.
Subject to regulatory constraints, interest-rate swaps may be used to
adjust interest-rate exposures when appropriate, based upon market
conditions.exposures.
At December 31, 2001, SoCalGas2004, the company had $508$613 million of fixed-rate debt
and $175$252 million of variable-rate debt. Interest on fixed-rate utility
debt is fully recovered in rates on a historical cost basis and
interest on variable-rate debt is provided for in rates on a forecasted
basis. At December 31, 2001,2004, SoCalGas' fixed-rate debt had a one-year
VaR of $96$76 million and SoCalGasits variable-rate debt had a one-year VaR of $1$11
million.
At December 31, 2001,2004, the notional amount of interest-rate swap
transactions totaled $175$150 million. See Notes 4 and 8Note 3 of the notes to Consolidated
Financial Statements forprovides further information regarding theseinterest
rate swap transactions.
In addition, the company is ultimately subject to the effect of
interest-rate fluctuation on the assets of its pension plan and other
postretirement plans.
Credit Risk
Credit risk relates tois the risk of loss that would be incurred as a result of
nonperformance by counterparties pursuant to the terms of their contractual obligations. As
with market risk, the company has adopted corporate-wide policies
governing the management of credit risk. Credit risk management is
performed by the ERMG and the company's credit department and overseen
by the ERMOC. Using rigorous models, the ERMG and the company calculate
current and potential credit risk to counterparties on a daily basis
and monitor actual balances in comparison to approved limits. The
company avoids concentration of counterparties whenever possible, and
maintainsmanagement believes its credit policies associated with regard to
counterparties
that management believes significantly minimizereduce overall credit risk. These policies include an
evaluation of prospective counterparties' financial condition
(including credit ratings), collateral requirements under certain
circumstances, and the use of standardized agreements that allow for the
netting of positive and negative exposures associated with a single
counterparty.counterparty and other security such as lock-box liens and downgrade
triggers.
The company monitors credit risk through a credit-approvalcredit approval process and
the assignment and monitoring of credit limits. These credit limits are
established based on risk and return considerations under terms
customarily available in the industry.
The company periodically enters into interest-rate swap agreements to
moderate exposure to interest-rate changes and to lower the overall
24
cost of borrowing. The company would be exposed to interest-rate
fluctuations on the underlying debt should other partiescounterparties to the
agreement not perform. Critical Accounting PoliciesAdditional information regarding the company's
use of interest-rate swap agreements is provided under "Interest Rate
Risk".
CRITICAL ACCOUNTING POLICIES AND KEY NON-CASH PERFORMANCE INDICATORS
Certain accounting policies are viewed by management as critical
because their application is the most relevant, judgmental and/or
material to the company's financial position and results of operations,
and/or because they require the use of material judgments and
estimates.
The company's most significant accounting policies are described in Note 21
of the notes to Consolidated Financial Statements. The most critical
policies, are Statementall of Financial Accounting Standards
(SFAS) 71 "Accounting for the Effects of Certain Types of Regulation,"
and SFAS 133 and SFAS 138 "Accounting for Derivative Instruments and
Hedging Activities" and "Accounting for Certain Derivative Instruments
and Certain Hedging Activities," (see below). All of these policieswhich are mandatory under generally accepted
accounting principles and the regulations of the Securities and
Exchange Commission. EachCommission, are the following:
Statement of these
policiesFinancial Accounting Standards (SFAS) 5, "Accounting
for Contingencies," establishes the amounts and timing of when
the company provides for contingent losses. Details of the
company's issues in this area are discussed in Note 10 of the
notes to Consolidated Financial Statements.
SFAS 71, "Accounting for the Effects of Certain Types of
Regulation," has a materialsignificant effect on the timingway the California
Utilities record assets and liabilities, and the related revenues
and expenses that would not be recorded absent the principles
contained in SFAS 71.
SFAS 109, "Accounting for Income Taxes," governs the way the
company provides for income taxes. Details of revenuethe company's
issues in this area are discussed in Note 4 of the notes to
Consolidated Financial Statements.
SFAS 123, "Accounting for Stock-Based Compensation" and expense
recognitionSFAS 148
"Accounting for Stock-Based Compensation - Transition and
Disclosure," give companies the choice of recognizing a cost at
the time of issuance of stock options or merely disclosing what
that cost would have been and not recognizing it in its financial
statements. Sempra Energy has elected the disclosure option for
all options that are so eligible. The effect of this is discussed
in Note 1 of the notes to Consolidated Financial Statements.
SFAS 123R, "Share-Based Payment" requires public companies to
measure and record the cost of employee services received in
exchange for an award of equity instruments based on the grant-
date fair value of the awards and gives companies three methods
to do so. This statement is effective for Sempra Energy on July
1, 2005. Further discussion is provided in Note 1 of the notes to
Consolidated Financial Statements.
SFAS 133, "Accounting for Derivative Instruments and Hedging
Activities," SFAS 138 "Accounting for Certain Derivative
Instruments and Certain Hedging Activities" and SFAS 149
25
"Amendment of Statement 133 on Derivative Instruments and Hedging
Activities," have a significant effect on the balance sheets of
the company operations.but have no significant effect on its income
statements because of the principles contained in SFAS 71.
In connection with the application of these and other accounting
policies, the company makes estimates and judgments about various
matters. The most significant of these involve theinvolve:
The calculation of fair values,or realizable values.
The collectibility of receivables, regulatory assets, deferred
tax assets and other assets.
The resolution of various income-tax issues between the company
and the collectibility of regulatoryvarious taxing authorities.
The various assumptions used in actuarial calculations for
pension and other assets.postretirement benefit plans.
The probable costs to be incurred in the resolution of litigation.
Differences between estimates and actual amounts have had significant
impacts in the past and are likely to have significant impacts in the
future.
As discussed elsewhere herein, the company uses exchange quotations or
other third-party pricing to estimate fair values whenever possible.
When no such data is available, it uses internally developed models or
other techniques.values. The assumed
collectibility of receivables considers the aging of the receivables,
the creditworthiness of customers and the enforceability of contracts,
where applicable. The assumed collectibility of regulatory assets
considers legal and regulatory decisions involving the specific items
or similar items. The assumed collectibility of other assets considers
the nature of the item, the enforceability of contracts where
applicable, the creditworthiness of the other parties and other
factors. New Accounting Standards
Effective January 1, 2001,The anticipated resolution of income-tax issues considers past
resolution of the same or similar issue, the status of any income-tax
examination in progress and positions taken by taxing authorities with
other taxpayers with similar issues. Actuarial assumptions are based on
the advice of the company's independent actuaries. The likelihood of
deferred tax recovery is based on analyses of the deferred tax assets
and the company's expectation of future financial and/or taxable
income, based on its strategic planning.
Choices among alternative accounting policies that are material to the
company's financial statements and information concerning significant
estimates have been discussed with the audit committee of the board of
directors.
Key non-cash performance indicators for the company adopted SFAS No. 133
"Accounting for Derivative Instrumentsinclude numbers of
customers and Hedging Activities,quantities of natural gas sold. The information is
provided in "Introduction" and "Results of Operations."
as
amended by SFAS No. 138, "Accounting for Certain Derivative
Instruments26
NEW ACCOUNTING STANDARDS
Relevant pronouncements that have recently become effective and Certain Hedging Activities." As amended, SFAS 133
requires that an entity recognize all derivatives as either assets or
liabilities in the statement of financial position, measure those
instruments at fair value and recognize changes in the fair value of
derivatives in earnings in the period of change unless the derivative
qualifies as an effective hedge that offsets certain exposure.
The company utilizes derivative financial instruments to reduce
its exposure to unfavorable changes in energy prices, which are
subject tohave
had a significant and often volatile fluctuation. Derivative
financial instruments are comprised of futures, forwards, swaps,
options and long-term delivery contracts. These contracts allow
SoCalGas to predict with greater certainty the effective prices to be
received and the prices to be charged to its customers.
Upon adoption of SFAS 133 on January 1, 2001, the company is
classifying its forward contracts as follows:
Normal Purchase and Sales: These forward contracts are excluded from
the requirements of SFAS No. 133. The realized gains and losses on
these contracts are reflected in the income statement at the contract
settlement date. The contracts that generally qualify as normal
purchases and sales are long-term contracts that are settled by
physical delivery.
Cash Flow Hedges: The unrealized gains and losses related to these
forward contracts are included in accumulated other comprehensive
income, a component of shareholders' equity, and reflected in the
Statements of Consolidated Income when the corresponding hedged
transaction is settled.
Gas Purchases and Sales: The unrealized gains and losses related to
these forward contracts are reflectedeffect on the balance sheet as
regulatory assetscompany's financial statements are SFAS
132 (revised 2003) and liabilities, to the extent derivative gains and
losses will be recoverable or payable143. They are described in future rates.
If gains and losses at SoCalGas are not recoverable or payable through
future rates, SoCalGas will apply hedge accounting if certain criteria
are met. In instances where hedge accounting is applied to energy
derivatives, cash flow hedge accounting is elected and, accordingly,
changes in fair values of the derivatives are included in other
comprehensive income and reflected in the Statements of Consolidated
Income when the corresponding hedged transaction is settled. The
effect on other comprehensive income for the year ended December 31,
2001 was not material. In instances where energy derivatives do not
qualify for hedge accounting, gains and losses are recorded in the
Statements of Consolidated Income.
The adoption of this new standard on JanuaryNote 1 2001, did not
impact the company's earnings. However, $982 million in current
assets, $1.1 billion in noncurrent assets, and $4 million in current
liabilities were recorded as of January 1, 2001, in the Consolidated
Balance Sheets as fixed-priced contracts and other derivatives. Due to
the regulatory environment in which SoCalGas operates, regulatory
assets and liabilities were established to the extent that derivative
gains and losses are recoverable or payable through future rates. As
such, $982 million in current regulatory liabilities, $1.1 billion in
noncurrent regulatory liabilities, and $4 million in current
regulatory assets were recorded as of January 1, 2001, in the
Consolidated Balance Sheets. See Note 8 of the notes
to Consolidated Financial Statements for additional information onStatements. Pronouncements of particular
importance to the effects of SFAS
133 on thecompany's financial statements at December 31, 2001. The ongoing
effects will depend on future market conditions and the company's
hedging activities.
In July 2001, the Financial Accounting Standards Board (FASB)
issued three statements, SFAS 141 "Business Combinations," SFAS 142
"Goodwill and Other Intangible Assets" andare described below.
SFAS 143, "Accounting for Asset Retirement Obligations." The first two are not presently
relevant to the company.Obligations": SFAS 143 addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs. This applies to
legal obligations associated with the retirement of long-lived assets
that result from the acquisition, construction, development and/or
normal operation of a long-lived asset. It
requires entities to record the fair value of a liabilityliabilities for anlegal
obligations related to asset retirement obligationretirements in the period in which it isthey
are incurred. WhenIt also requires the liability is initially
recorded, the entity increases the carrying amount of the related
long-lived assetcompany to reflect thereclassify amounts
recovered in rates for future retirement cost. Over time, the
liability is accretedremoval costs not covered by a legal
obligation from accumulated depreciation to its present value and paid, and the
capitalized cost is depreciated over the useful life of the related
asset. SFAS 143 is effective for financial statements issued for
fiscal years beginning after June 15, 2002. The company has not yet
determined the effect of SFAS 143 on its Consolidated Balance Sheets,
but has determined that it will not have a material impact on its
Statements of Consolidated Income.
In August 2001, the FASB issued SFAS 144 "Accounting for the
Impairment or Disposal of Long-Lived Assets" that replaces SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." SFAS 144 applies to all long-lived assets,
including discontinued operations. SFAS 144 requires that those long-
lived assets classified as held for sale be measured at the lower of
carrying amount or fair value less cost to sell. Discontinued
operations will no longer be measured at net realizable value or
include amounts for operating losses that have not yet occurred. SFAS
144 also broadens the reporting of discontinued operations to include
all components of an entity with operations that can be distinguished
from the rest of the entity and that will be eliminated from the
ongoing operations of the entity in a disposal transaction. The
provisions of SFAS 144 are effective for fiscal years beginning after
December 15, 2001. The company has not yet determined the effect of
SFAS 144 on its financial statements.regulatory liability.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.RISK
The information required by Item 7A is set forth under "Item 7.
Management's Discussion and Analysis of Financial Condition and Results
of Operations --- Market Risk."27
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -
Pacific Enterprises
REPORT OF INDEPENDENT AUDITORS' REPORTREGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Pacific Enterprises:
We have audited the accompanying consolidated balance sheets of Pacific
Enterprises and subsidiaries (the "Company") as of December 31, 20012004
and 2000,2003, and the related consolidated statements of consolidated income,
shareholders' equity and cash flows and
changes in shareholders' equity for each of the three years in the
period ended December 31, 2001.2004. These financial statements are the
responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditingthe standards generally accepted inof the United States of America.Public
Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly,
in all material respects, the financial position of Pacific
Enterprises and subsidiariesthe Company as of
December 31, 20012004 and 2000,2003, and the results of theirits operations and theirits
cash flows for each of the three years in the period ended December 31,
2001,2004, in conformity with accounting principles generally accepted in
the United States of America.
We have also audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the effectiveness
of the Company's internal control over financial reporting as of
December 31, 2004, based on the criteria established in Internal
Control-Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission and our report dated February
22, 2005 expressed an unqualified opinion on management's assessment of
the effectiveness of the Company's internal control over financial
reporting and an unqualified opinion on the effectiveness of the
Company's internal control over financial reporting.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
February 4, 2002 (March 5, 200222, 2005
28
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Pacific Enterprises:
We have audited management's assessment, included in the accompanying
Management's Report on Internal Control over Financial Reporting, that
Pacific Enterprises and subsidiaries (the "Company") maintained
effective internal control over financial reporting as of December 31,
2004, based on criteria established in Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. The Company's management is responsible for
maintaining effective internal control over financial reporting and for
its assessment of the effectiveness of internal control over financial
reporting. Our responsibility is to Note 12)express an opinion on management's
assessment and an opinion on the effectiveness of the Company's
internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable
assurance about whether effective internal control over financial
reporting was maintained in all material respects. Our audit included
obtaining an understanding of internal control over financial
reporting, evaluating management's assessment, testing and evaluating
the design and operating effectiveness of internal control, and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis
for our opinions.
A company's internal control over financial reporting is a process
designed by, or under the supervision of, the company's principal
executive and principal financial officers, or persons performing
similar functions, and effected by the company's board of directors,
management, and other personnel to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally
accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the
assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company are being
made only in accordance with authorizations of management and directors
of the company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or
disposition of the company's assets that could have a material effect
on the financial statements.
Because of the inherent limitations of internal control over financial
reporting, including the possibility of collusion or improper
management override of controls, material misstatements due to error or
fraud may not be prevented or detected on a timely basis. Also,
29
projections of any evaluation of the effectiveness of the internal
control over financial reporting to future periods are subject to the
risk that the controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In our opinion, management's assessment that the Company maintained
effective internal control over financial reporting as of December 31,
2004, is fairly stated, in all material respects, based on the criteria
established in Internal Control-Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Also
in our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31,
2004, based on the criteria established in Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission.
We have also audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the consolidated
financial statements as of and for the year ended December 31, 2004 of
the Company and our report dated February 22, 2005 expressed an
unqualified opinion on those financial statements.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 22, 2005
30
PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
Dollars(Dollars in millionsmillions)
Years ended December 31,
2001 2000 1999
------ ------ ------2004 2003 2002
------- ------- -------
Operating Revenues $3,716 $2,854 $2,569
------ ------ ------revenues $ 3,997 $ 3,544 $ 2,858
------- ------- -------
Operating Expensesexpenses
Cost of natural gas distributed 2,117 1,361 1,0332,283 1,830 1,192
Other operating expenses 794 696 748953 950 879
Depreciation 268 263 261255 289 276
Income taxes 167 175 163
Other157 132 172
Franchise fees and other taxes and franchise payments 101 96114 106 93
------ ------ ------------- ------- -------
Total operating expenses 3,447 2,591 2,298
------ ------ ------3,762 3,307 2,612
------- ------- -------
Operating Income 269 263 271
------ ------ ------income 235 237 246
------- ------- -------
Other Incomeincome and (Deductions)(deductions)
Interest income 40 64 4017 38 11
Regulatory interest (19) (12) (14)- net 9 3 (4)
Allowance for equity funds used during
construction 6 3 --
Taxes5 9 10
Income taxes on non-operating income (4) (10) (3)2 (8) 2
Preferred dividends of subsidiaries (1) (1) (1)
Gain on sale of partnership assets 15 -- --
Other - net 1 3 (21)
------ ------ -------- (6) 9
------- ------- -------
Total 23 47 1
------ ------ ------35 27
------- ------- -------
Interest Chargescharges
Long-term debt 63 68 8235 41 40
Other 25 33 812 13 23
Allowance for borrowed funds used during
construction (2) (2) (2)
------ ------ ------(1) (3) (3)
------- ------- -------
Total 86 99 88
------ ------ ------46 51 60
------- ------- -------
Net Income 206 211 184income 236 221 213
Preferred Dividend Requirementsdividend requirements 4 4 4
------ ------ ------------- ------- -------
Earnings Applicableapplicable to Common Sharescommon shares $ 202232 $ 207217 $ 180
====== ====== ======209
======= ======= =======
See notes to Consolidated Financial Statements.
31
PACIFIC ENTERPRISES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Dollars(Dollars in millionsmillions)
Balance at
December 31, 2001 2000
-------- --------December 31,
2004 2003
------------- -------------
ASSETS
Property,Utility plant and equipment $6,590 $6,337- at original cost $ 7,254 $ 7,007
Accumulated depreciation (3,793) (3,571)
------ ------
Property,(2,863) (2,739)
------- -------
Utility plant and equipment - net 2,797 2,766
------ ------4,391 4,268
------- -------
Current assets:
Cash and cash equivalents 13 20534 32
Accounts receivable - trade 415 589673 509
Accounts receivable - other 14 8336
Interest receivable 32 30
Due from unconsolidated affiliates -- 2147 76
Income taxes receivable 20 --31 48
Deferred income taxes 33 439 --
Regulatory assets arising from fixed-price
contracts and other derivatives 103 --97 85
Other regulatory assets -- 24
Fixed-price contracts and other derivatives 59 --26 8
Inventories 42 6772 74
Other 4 84
------ ------10 12
------- -------
Total current assets 703 1,309
------ ------1,005 910
------- -------
Other assets:
Due from unconsolidated affiliates 409 617396 356
Regulatory assets arising from fixed-price
contracts and other derivatives 157 --
Other regulatory assets -- 1252 148
Sundry 125 52
------ ------109 151
------- -------
Total other assets 691 681
------ ------557 655
------- -------
Total assets $4,191 $4,756
====== ======$ 5,953 $ 5,833
======= =======
See notes to Consolidated Financial Statements.
32
PACIFIC ENTERPRISES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Dollars(Dollars in millionsmillions)
Balance at
December 31, 2001 2000
-------- --------December 31,
2004 2003
------------- ------------
CAPITALIZATION AND LIABILITIES
Capitalization:
Common Stock (600,000,000stock (600 million shares authorized;
83,917,66484 million shares outstanding) $1,317 $1,282$ 1,453 $ 1,367
Retained earnings 177 165285 253
Accumulated other comprehensive income (loss) -- (1)
------ ------(4) (3)
------- -------
Total common equity 1,494 1,4461,734 1,617
Preferred stock 80 80
------ ------------- -------
Total shareholder'sshareholders' equity 1,574 1,5261,814 1,697
Long-term debt 579 821
------ ------864 762
------- -------
Total capitalization 2,153 2,347
------ ------2,678 2,459
------- -------
Current liabilities:
Short-term debt 5030 --
Accounts payable - trade 314 227
Accounts payable - other 65 44
Due to unconsolidated affiliates 127 121
Interest payable 10 18
Deferred income taxes -- 24
Regulatory balancing accounts - net 178 86
Fixed-price contracts and other derivatives 97 86
Customer deposits 49 43
Current portion of long-term debt 100 120
Accounts payable - trade 160 368
Accounts payable - other 81 43
Due to unconsolidated affiliates 168 365
Regulatory balancing accounts - net 85 465
Income taxes payable -- 50
Dividends and interest payable 31 28
Regulatory liabilities 18 --
Fixed-price contracts and other derivatives 103 --175
Other 390 321
------ ------259 262
------- -------
Total current liabilities 1,186 1,760
------ ------1,129 1,086
------- -------
Deferred credits and other liabilities:
Customer advances for construction 24 16
Post-retirement55 40
Postretirement benefits other than pensions 88 9764 72
Deferred income taxes 110 150123 121
Deferred investment tax credits 50 5341 44
Regulatory liabilities 86 --arising from cost of
removal obligations 1,446 1,392
Other regulatory liabilities 67 109
Fixed-price contracts and other derivatives 162 --
Deferred credits and other liabilities 312 31352 148
Preferred stock of subsidiary 20 20
------ ------Deferred credits and other 278 342
------- -------
Total deferred credits and other liabilities 852 649
------ ------
Contingencies2,146 2,288
------- -------
Commitments and commitmentscontingencies (Note 11)10)
Total liabilities and shareholder'sshareholders' equity $4,191 $4,756
====== ======$ 5,953 $ 5,833
======= =======
See notes to Consolidated Financial Statements.
33
PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
Dollars(Dollars in millionsmillions)
Years ended December 31,
2001 2000 1999
------ ------ ------2004 2003 2002
------- ------- -------
Cash Flows from Operating ActivitiesCASH FLOWS FROM OPERATING ACTIVITIES
Net Incomeincome $ 206236 $ 211221 $ 184213
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation 268 263 261255 289 276
Deferred income taxes and investment
tax credits 24 5 135
(Increase) decrease(15) 38 38
Gain on sale of partnership assets (15) -- --
Changes in other assets (12) 40 11
Increase (decrease)3 (3) 16
Changes in other liabilities 32 (16) 33(46) (46) --
Changes in working capital components:
Accounts and notes receivable 244 (377) 158
Income taxes receivable/payable (71) 84 (59)(145) (44) (67)
Interest receivable (1) (30) --
Fixed-price contracts and other derivatives 16 -- --(2) (2) 6
Inventories 25 11 (18)2 2 (34)
Other current assets 4 (75) (2)1 10 (4)
Accounts payable (171) 191 (19)107 35 (4)
Income taxes 61 38 (69)
Due to/from affiliates 5 35 (39)- net 34 37 12
Regulatory balancing accounts (380) 309 3693 (99) 80
Regulatory assets and liabilities 39 (2) (2)(23) (24) 1
Customer deposits 6 (64) 66
Other current liabilities 71 93 10
------ ------ ------(7) 17 (9)
------- ------- -------
Net cash provided by operating activities 300 772 689
------ ------ ------
Cash Flows544 375 521
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (311) (318) (331)
Affiliate loans 11 97 (177)
Net proceeds from Investing Activities
Capital expenditures (294) (198) (146)
Loans repaid by (paid to) affiliates 220 (267) (336)
Other - netsale of assets 7 5 --
21 (1)
------ ------ ------------- ------- -------
Net cash used in investing activities (74) (444) (483)
------ ------ ------
Cash Flows from Financing Activities(293) (216) (508)
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid (190) (100)(200) (250) (100)
Preferred dividends paid (4) (4) (4)
Issuance of long-term debt 100 500 250
Payments on long-term debt (270) (30) (75)(175) (395) (100)
Increase (decrease) in short-term debt 5030 -- (43)
Other (4) -- --
------ ------ ------(50)
------- ------- -------
Net cash used in financing activities (418) (134) (222)
------ ------ ------(249) (149) (4)
------- ------- -------
Increase (decrease) in cash and cash equivalents (192) 194 (16)2 10 9
Cash and cash equivalents, January 1 205 11 27
------ ------ ------32 22 13
------- ------- -------
Cash and cash equivalents, December 31 $ 1334 $ 20532 $ 11
====== ====== ======
Supplemental Disclosure of Cash Flow Information:22
======= ======= =======
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized $ 8349 $ 12754 $ 90
====== ====== ======50
======= ======= =======
Income tax payments, net of refunds $ 209111 $ 99 $ 92
====== ====== ======
See notes to Consolidated Financial Statements
PACIFIC ENTERPRISES200
======= ======= =======
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING
AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS (continued)
Dollars in millions
Years ended December 31 2001 2000 1999
------ ------ ------
Supplemental Schedule of Noncash Activities:
Dividend of affiliates toFINANCING ACTIVITIES
Assets contributed by Sempra Energy $ -- $ 48 $ --
$ 417
====== ====== ======
Capital contribution fromLiabilities assumed -- (17) --
------- ------- -------
Net assets contributed by Sempra Energy $ -- $ 31 $ --
$ 85
====== ====== ============= ======= =======
See notes to Consolidated Financial Statements.
34
PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
Years ended December 31, 2001, 20002004, 2003 and 1999
Dollars2002
(Dollars in millionsmillions)
Deferred Accumulated
Compensation
Other Total
Comprehensive Preferred Common Retained Relating Comprehensive Shareholders'
Income Stock Stock Earnings to ESOP Income(Loss) Equity
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 19982001 $ 80 $1,117 $395 $(45) $1,547$ 1,317 $ 177 $ -- $ 1,574
Net income $184 184 184
Other income/comprehensive income (loss):
Available-for-sale
securities 10 $ 10 10
Pension (4) (4) (4)
-----
Comprehensive income $190
Preferred stock dividends =====
declared (4) (4)
Common stock dividends
declared (100) (100)
Capital contribution 85 85
Quasi-reorganization
Adjustment (Note 2) 80 80
Dividend of subsidiaries to
Sempra Energy (417) (417)
Transfer of ESOP to
Sempra Energy 45 45
----------------------------------------------------------------------
Balance at December 31, 1999 80 1,282 58 -- 6 1,426
Net income $211 211 211
Other comprehensive income (loss):
Available-for-sale
securities (10) (10) (10)
Pension 3 3 3
-----
Comprehensive income $204213 213 213
=====
Preferred stock dividends declared (4) (4)
Common stock dividends declared (100) (100)
----------------------------------------------------------------------Capital contribution 1 1
-----------------------------------------------------------------------------------------------------------------------
Balance at December 31, 20002002 80 1,282 1651,318 286 -- (1) 1,5261,684
Net income $206 206 206$ 221 221 221
Other comprehensive income
(loss):
Other 1 1 1adjustment - pension (3) (3) (3)
-----
Comprehensive income $207$ 218
=====
Quasi-reorganization adjustment
(Note 2) 35 351) 18 18
Preferred stock dividends declared (4) (4)
Common stock dividends declared (190) (190)
----------------------------------------------------------------------(250) (250)
Capital contribution 31 31
-----------------------------------------------------------------------------------------------------------------------
Balance at December 31, 20012003 80 1,367 253 (3) 1,697
Net income $ 236 236 236
Other comprehensive income
adjustment - pension (1) (1) (1)
-----
Comprehensive income $ 235
=====
Quasi-reorganization adjustment
(Note 1) 86 86
Preferred stock dividends declared (4) (4)
Common stock dividends declared (200) (200)
-----------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2004 $ 80 $1,317 $ 1771,453 $ --285 $ -- $1,574
============================================================================================================(4) $ 1,814
=======================================================================================================================
See notes to Consolidated Financial Statements.
35
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. BUSINESS COMBINATION
Sempra Energy was formed as a holding company forSIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The Consolidated Financial Statements include the accounts of Pacific
Enterprises (PE)(PE or the parent company ofcompany) and its subsidiary, Southern California
Gas Company (SoCalGas)
and Enova Corporation (Enova),(SoCalGas or the parent company of San Diego Gas &
Electric (SDG&E),company). The financial statements herein
are, in connection with a business combination that was
completed on June 26, 1998. As a result ofone case, the combination, each
outstanding share of common stock of Enova was converted into one
share of common stock of Sempra Energy, and each outstanding share of
common stockConsolidated Financial Statements of PE was converted into 1.5038 sharesand its
subsidiary, SoCalGas, and, in the second case, the Consolidated
Financial Statements of common stockSoCalGas and its subsidiaries, which comprise
less than one percent of Sempra Energy.
As a resultSoCalGas' consolidated financial position and
results of the business combination, PE dividended its
nonutility subsidiaries to Sempra Energy during 1998operations. All material intercompany accounts and
early 1999.
SoCalGas is now the sole direct subsidiary of PE.
NOTE 2. SIGNIFICANT ACCOUNTING POLICIEStransactions have been eliminated.
As a subsidiary of Sempra Energy, the company receives certain services
therefrom. Althoughtherefrom, for which it is charged its allocable share of the cost of
such services,services. Management believes that cost is believed to bereasonable, but
probably less than if the company had to provide those services itself.
Effects of Regulation
The accounting policies of the company conform with generally accepted
accounting principles for regulated enterprises and reflect the
policies of the California Public Utilities Commission (CPUC) and the
Federal Energy Regulatory Commission (FERC).
The company prepares its financial statements in accordance with
the provisions of Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation,"
under which a regulated utility records a regulatory asset if it is
probable that, through the ratemaking process, the utility will
recover that asset from customers. Regulatory liabilities represent
future reductions in rates for amounts due to customers. To the extent
that portions of the utility operations cease to be subject to SFAS
No. 71, or recovery is no longer probable as a result of changes in
regulation or the utility's competitive position, the related
regulatory assets and liabilities would be written off. In addition,
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to Be Disposed Of," affects utility plant and
regulatory assets such that a loss must be recognized whenever a
regulator excludes all or part of an asset's cost from rate base. The
application of SFAS No. 121 continues to be evaluated in connection
with industry restructuring. Information concerning regulatory assets
and liabilities is described below in "Revenues," "Regulatory
Balancing Accounts" and "Regulatory Assets and Liabilities," and
industry restructuring is described in Note 12.
Revenues
Revenues for SoCalGas are derived from deliveries of natural gas to
customers and changes in related regulatory balancing accounts.
Revenue for natural gas sales and services are generally recorded
under the accrual method and these revenues are recognized upon
delivery. Natural gas storage contract revenues are accrued on a
monthly basis and reflect reservation, storage and injection charges
in accordance with negotiated agreements, which have one-year to
three-year terms. Operating revenue includes amounts for services
rendered but unbilled (approximately one-half month's deliveries) at
the end of each year.
Additional information concerning utility revenue recognition is
discussed below under "Regulatory Balancing Accounts" and "Regulatory
Assets and Liabilities."
Regulatory Balancing Accounts
The amounts included in regulatory balancing accounts represent net
payables (overcollected balancing accounts less undercollected
balancing accounts) of $85 million and $465 million at December 31,
2001 and 2000, respectively.
Balancing accounts provide a mechanism for charging utility
customers the exact amount incurred for certain costs, primarily
commodity costs. As a result, fluctuations in most costs and
consumption levels do not affect earnings from SoCalGas' operations.
Additional information on regulatory matters is included in Note 12.
Regulatory Assets and Liabilities
In accordance with the accounting principles of SFAS 71 for rate-
regulated enterprises, the company records regulatory assets (which
represent probable future revenues associated with certain costs that
will be recovered from customers through the rate-making process) and
regulatory liabilities (which represent probable future reductions in
revenue associated with amounts that are to be credited to customers
through the rate-making process). They are amortized over the periods
in which the costs are recovered from or refunded to customers in
regulatory revenues.
Regulatory assets (liabilities) as of December 31 consist of the
following (dollars in millions):
2001 2000
------ ------
SoCalGas
----------
Environmental remediation $ 55 $ 58
Fixed-price contracts and other
derivatives 257 --
Unamortized loss on retirement of
debt - net 41 36
Deferred taxes recoverable in rates (158) (100)
Employee benefit costs (132) (60)
Other 5 6
----- -----
Total 68 (60)
PE
-----------
Employee benefit costs 88 96
----- -----
Total PE consolidated $ 156 $ 36
===== =====
Net regulatory assets are recorded on the Consolidated Balance
Sheets at December 31 as follows (dollars in millions):
2001 2000
SoCalGas ------- ------
- --------
Current regulatory assets $ 103 $ 24
Noncurrent regulatory assets 157 --
Current regulatory liabilities (18) --
Noncurrent regulatory liabilities (174) (84)
------ ------
Total 68 (60)
PE
- --------
Noncurrent regulatory assets 88 96
------ ------
Total PE consolidated $ 156 $ 36
====== ======
All assets earn a return or the cash has not yet been expended and the
assets are offset by liabilities that do not incur a carrying cost.
Allowance for Doubtful Accounts
The allowance for doubtful accounts was $14 million, $19 million and
$17 million at December 31, 2001, 2000, and 1999, respectively. The
company recorded a provision for doubtful accounts of $9 million, $9
million and $7 million in 2001, 2000 and 1999, respectively.
Inventories
At December 31, 2001, inventory included natural gas of $34 million,
and materials and supplies of $8 million. The corresponding balances
at December 31, 2000 were $56 million and $11 million, respectively.
Natural gas is valued by the last-in first-out (LIFO) method. When the
inventory is consumed, differences between this LIFO valuation and
replacement cost will be reflected in customer rates. Materials and
supplies are generally valued at the lower of average cost or market.
Due to/from Unconsolidated Affiliates
PE has promissory notes due from Sempra Energy and from Sempra Energy
Global Enterprises (Global) which bear variable interest rates based
on short-term commercial paper rates. These notes were $268 million
and $138 million, respectively, at December 31, 2001 and were included
in noncurrent assets under the caption "due from unconsolidated
affiliates". The corresponding balances at December 31, 2000 were
$469 million and $133 million, respectively. PE also had $3 million
and $15 million due from other affiliates at December 31, 2001 and
2000, respectively.
SoCalGas had a promissory note receivable from Sempra Energy of
$214 million at December 31, 2000, included in current assets under
the caption "due from unconsolidated affiliates." Sempra Energy paid
this promissory note during 2001.
In addition, PE had intercompany payables due to various
affiliates of $168 million and $365 million at December 31, 2001, and
2000, respectively, which are recorded as a current liability. These
balances are due on demand. Of the $168 million balance, $24 million
was recorded at SoCalGas.
Property, Plant and Equipment
Utility plant primarily represents the buildings, equipment and other
facilities used by SoCalGas to provide natural gas service.
The cost of utility plant includes labor, materials, contract
services and related items, and an allowance for funds used during
construction (AFUDC). The cost of most retired depreciable utility
plant, plus removal costs minus salvage value, is charged to
accumulated depreciation. Accumulated depreciation was $3.8 billion and
$3.6 billion at December 31, 2001 and 2000, respectively, which
primarily reflects accumulated depreciation for natural gas utility
plant at SoCalGas of $3.7 billion and $3.6 billion, respectively.
Depreciation expense is based on the straight-line method over the
useful lives of the assets, an average of 23 years in each of 2001,
2000 and 1999, or a shorter period prescribed by the CPUC. The
provision for depreciation as a percentage of average depreciable
utility plant was 4.33, 4.36 and 4.39 in 2001, 2000 and 1999,
respectively. See Note 12 for discussion of industry restructuring.
Maintenance costs are expensed as incurred.
AFUDC, which represents the cost of funds used to finance the
construction of utility plant, is added to the cost of utility plant.
AFUDC also increases income, partly as an offset to interest charges
and partly as a component of other income, shown in the Statements of
Consolidated Income, although it is not a current source of cash.
Long-Lived Assets
In accordance with SFAS 121, "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to Be Disposed Of," the company
periodically evaluates whether events or circumstances have occurred
that may affect the recoverability or the estimated useful lives of
long-lived assets. Impairment occurs when the estimated future
undiscounted cash flows exceed the carrying amount of the assets. If
that comparison indicates that the assets' carrying value may be
permanently impaired, such potential impairment is measured based on
the difference between the carrying amount and the fair value of the
assets based on quoted market prices or, if market prices are not
available, on the estimated discounted cash flows. This calculation is
performed at the lowest level for which separately identifiable cash
flows exist. The effects of ratemaking procedures and SFAS 71
significantly reduce the likelihood of any impairment.
Comprehensive Income
Comprehensive income includes all changes, except those resulting from
investments by owners and distributions to owners, in the equity of a
business enterprise from transactions and other events, including, as
applicable, foreign-currency translation adjustments, minimum pension
liability adjustments, unrealized gains and losses on marketable
securities that are classified as available-for-sale, and certain
hedging activities. The components of other comprehensive income are
shown in the Statements of Consolidated Changes in Shareholders'
Equity.
Quasi-Reorganization
In 1993, PE divested its merchandising operations and most of its oil
and gas exploration and production business. In connection with the
divestitures, PE effected a quasi-reorganization for financial reporting
purposes as of December 31, 1992. Certain of the liabilities
established in connection with the quasi-reorganization including
various income-tax issues, have beenwere favorably
resolved. Excess
liabilities of $35 millionresolved in 2003 and $80 million2004, resulting from the
favorable resolution ofin adjustments to common stock in
these issues were restored to shareholders'
equity in December 2001 and November 1999, respectively, but did not
affect the calculation of net income.years. The remaining liabilities will be resolved in future years. Managementyears
and management believes the provisions established for these matters
are adequate.
Use of Estimates in the Preparation of the Financial Statements
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of revenues and
expenses during the reporting period, and the reported amounts of
assets and liabilities and the disclosure of contingent assets and
liabilities at the date of the financial statements, and the reportedstatements. Actual amounts of
revenues and expenses during the reporting period. Actual results can
differ significantly from those estimates.
Basis of Presentation
Certain prior-year amounts have been reclassified to conform to the
current year's presentation.
Regulatory Matters
Effects of Regulation
The accounting policies of the company conform with generally accepted
accounting principles for regulated enterprises and reflect the
policies of the California Public Utilities Commission (CPUC) and the
Federal Energy Regulatory Commission (FERC). SoCalGas and its
affiliate, San Diego Gas & Electric (SDG&E), are collectively referred
to herein as "the California Utilities."
36
The company prepares its financial statements in accordance with the
provisions of SFAS 71, Accounting for the Effects of Certain Types of
Regulation, under which a regulated utility records a regulatory asset
if it is probable that, through the ratemaking process, the utility
will recover that asset from customers. To the extent that recovery is
no longer probable as a result of changes in regulation or the
utility's competitive position, the related regulatory assets would be
written off. In addition, SFAS 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, requires that a loss be recognized
whenever a regulator excludes all or part of utility plant or
regulatory assets from ratebase. Regulatory liabilities represent
reductions in future rates for amounts due to customers. Information
concerning regulatory assets and liabilities is provided below in
"Revenues," "Regulatory Balancing Accounts" and "Regulatory Assets and
Liabilities."
Regulatory Balancing Accounts
The amounts included in regulatory balancing accounts at December 31,
2004, represent net payables (payables net of receivables) that are
returned by reducing future rates.
Except for certain costs subject to balancing account treatment,
fluctuations in most operating and maintenance accounts affect utility
earnings. Balancing accounts provide a mechanism for charging utility
customers the amount actually incurred for certain costs, primarily
commodity costs. The CPUC has also approved balancing account treatment
for variances between forecast and actual for SoCalGas' commodity costs
and volumes, eliminating the impact on earnings from any throughput and
revenue variances from adopted forecast levels. Additional information
on regulatory matters is included in Note 9.
Regulatory Assets and Liabilities
In accordance with the accounting principles of SFAS 71, the company
records regulatory assets and regulatory liabilities as discussed
above.
37
Regulatory assets (liabilities) as of December 31 relate to the
following matters:
(Dollars in millions) 2004 2003
- ---------------------------------------------------------------------
SoCalGas
- ---------
Fixed-price contracts and other derivatives $ 148 $ 233
Environmental remediation 42 44
Unamortized loss on retirement of debt, net 44 45
Cost of removal obligation** (1,446) (1,392)
Deferred taxes refundable in rates (199) (194)
Employee benefit costs 65 (77)
Other 7 9
---------------------
Total (1,339) (1,332)
PE - Employee benefit costs (transferred to
SoCalGas in 2004) -- 72
---------------------
Total PE consolidated $(1,339) $(1,260)
- ---------------------------------------------------------------------
** This is related to SFAS 143, Accounting for Asset Retirement
Obligations, which is discussed below in "New Accounting Standards."
Net regulatory assets (liabilities) are recorded on the Consolidated
Balance Sheets at December 31 as follows:
(Dollars in millions) 2004 2003
- ---------------------------------------------------------------------
SoCalGas
- --------
Current regulatory assets $ 123 $ 93
Noncurrent regulatory assets 52 148
Current regulatory liabilities* (1) --
Noncurrent regulatory liabilities (1,513) (1,573)
---------------------
Total (1,339) (1,332)
PE - Noncurrent regulatory liabilities -- 72
---------------------
Total PE consolidated $(1,339) $(1,260)
- ---------------------------------------------------------------------
* Included in Other Current Liabilities.
All of these assets either earn a return, generally at short-term
rates, or the cash has not yet been expended and the assets are offset
by liabilities that do not incur a carrying cost.
Cash and Cash Equivalents
Cash equivalents are highly liquid investments with maturities of three
months or less at the date of purchase.
Basis38
Collection Allowances
The allowance for doubtful accounts was $5 million, $4 million and $4
million at December 31, 2004, 2003 and 2002, respectively. The company
recorded a provision (reduction thereof) for doubtful accounts of Presentation
Certain prior-year amounts have been reclassified to conform to$9
million, $3 million and $(5) million in 2004, 2003 and 2002,
respectively.
Inventories
At December 31, 2004, inventory shown on the Consolidated Balance
Sheets included natural gas of $61 million and materials and supplies
of $11 million. The corresponding balances at December 31, 2003 were
$63 million and $11 million, respectively. Natural gas is valued by the
last-in first-out (LIFO) method. When the inventory is consumed,
differences between the LIFO valuation and replacement cost are
reflected in customer rates. Materials and supplies at SoCalGas are
generally valued at the lower of average cost or market.
Income Taxes
Income tax expense includes current year's presentation.
Newand deferred income taxes from
operations during the year. In accordance with SFAS 109, Accounting Standards
Effective January 1, 2001,for
Income Taxes, the company adoptedrecords deferred income taxes for temporary
differences between the book and tax bases of assets and liabilities.
Investment tax credits from prior years are being amortized to income
over the estimated service lives of the properties. Other credits are
recognized in income as earned. The company follows certain provisions
of SFAS No. 133
"Accounting for Derivative Instruments and Hedging Activities,"109 that permit regulated enterprises to recognize deferred
taxes as amended by SFAS No. 138, "Accounting for Certain Derivative
Instruments and Certain Hedging Activities." As amended, SFAS 133
requires that an entity recognize all derivatives as eitherregulatory assets or liabilities if it is probable that such
amounts will be recovered from, or returned to, customers.
Property, Plant and Equipment
Utility plant primarily represents the buildings, equipment and other
facilities used by SoCalGas to provide natural gas services.
The cost of plant includes labor, materials, contract services and
certain expenditures, including refurbishments, replacement of major
component parts and labor and overheads incurred to install the parts,
incurred during a major maintenance outage of a generating plant.
Maintenance costs are expensed as incurred. In addition, the cost of
plant includes an allowance for funds used during construction (AFUDC).
The cost of most retired depreciable utility plant minus salvage value
is charged to accumulated depreciation.
Accumulated depreciation for natural gas utility plant at SoCalGas was
$2.9 billion and $2.7 billion at December 31, 2004 and 2003,
respectively. A discussion of SFAS 143 is provided below under "New
Accounting Standards." Depreciation expense is based on the straight-
line method over the useful lives of the assets, an average of 23 years
in each of 2004, 2003 and 2002, or a shorter period prescribed by the
statementCPUC. The provision for depreciation as a percentage of financial position, measure those
instruments at fair valueaverage
depreciable utility plant was 3.68, 4.36 and recognize changes4.34 in 2004, 2003 and
2002, respectively. Note 9 includes a discussion of industry
restructuring, which affected recorded depreciation.
39
AFUDC, which represents the fair valuecost of derivatives in earnings indebt and equity funds used to
finance the periodconstruction of change unlessutility plant, is added to the derivative
qualifiescost of
utility plant. Although it is not a current source of cash, AFUDC
increases income and is recorded partly as an effective hedge that offsets certain exposure.
The company utilizes derivative financial instrumentsoffset to reduce
its exposure to unfavorable changes in energy prices, which are
subject to significantinterest
charges and often volatile fluctuation. Derivative
financial instruments include futures, forwards, swaps, options and
long-term delivery contracts. These contracts allow SoCalGas to
predict with greater certainty the effective prices to be received and
the prices to be charged to its customers.
Upon adoption of SFAS 133 on January 1, 2001, the company classifies
its forward contractspartly as follows:
Normal Purchase and Sales: These forward contracts are excluded from
the requirements of SFAS No. 133. The realized gains and losses on
these contracts are reflected in the income statement at the contract
settlement date. The contracts that generally qualify as normal
purchases and sales are long-term contracts that are settled by
physical delivery.
Cash Flow Hedges: The unrealized gains and losses related to these
forward contracts are included in accumulated other comprehensive
income, a component of shareholders' equity, but not reflected in the
Statements of ConsolidatedOther Income until the corresponding hedged
transaction is settled.
Gas Purchases and Sales: The unrealized gains and losses related to
these forward contracts are reflected on the balance sheet as
regulatory assets and liabilities, to the extent derivative gains and
losses will be recoverable or payable in future rates.
If gains and losses at SoCalGas are not recoverable or payable through
future rates, SoCalGas will apply hedge accounting if certain criteria
are met.
In instances where hedge accounting is applied to energy
derivatives, cash flow hedge accounting is elected and, accordingly,
changes in fair values of the derivatives are included in other
comprehensive income, but not reflected in the Statements of
Consolidated Income until the corresponding hedged transaction is
settled. The effect on other comprehensive income for the year ended
December 31, 2001 was not material. In instances where energy
derivatives do not qualify for hedge accounting, gains and losses are
recordedDeductions in the
Statements of Consolidated Income. AFUDC amounted to $6 million, $12
million and $13 million for 2004, 2003 and 2002, respectively.
Legal Fees
Legal fees that are associated with a past event and not expected to be
recovered in the future are accrued when it is probable that they will
be incurred.
Comprehensive Income
Comprehensive income includes all changes, except those resulting from
investments by owners and distributions to owners, in the equity of a
business enterprise from transactions and other events, including
foreign-currency translation adjustments minimum pension liability
adjustments, and certain hedging activities. The adoptioncomponents of this new standardOther
Comprehensive Income, which consists of all these changes other than
net income as shown on January 1, 2001, did not
impact the company's earnings. However, $982Statement of Consolidated Income, are shown
in the Statements of Consolidated Changes in Shareholders' Equity. At
December 31, 2004, Accumulated Other Comprehensive Income consisted
entirely of minimum pension liability adjustments, net of income tax.
Revenues
Revenues of SoCalGas are primarily derived from deliveries of natural
gas to customers and changes in related regulatory balancing accounts.
Revenues from natural gas sales and services are generally recorded
under the accrual method and recognized upon delivery. Natural gas
storage contract revenues are accrued on a monthly basis and reflect
reservation, storage and injection charges in accordance with
negotiated agreements, which have terms of up to three years. Operating
revenue includes amounts for services rendered but unbilled
(approximately one-half month's deliveries) at the end of each year.
Additional information concerning utility revenue recognition is
discussed above under "Regulatory Matters."
Transactions with Affiliates
On a daily basis, SoCalGas and SDG&E share numerous functions with each
other and they also receive various services from and provide various
services to Sempra Energy.
At December 31, 2004, PE has intercompany receivables from Sempra
Energy and other affiliates of $4 million and $3 million, respectively.
The corresponding amounts at December 31, 2003 were $73 million and $3
million, respectively. Of the total balances, $22 million was recorded
at SoCalGas at December 31, 2003 but no balance was recorded at
SoCalGas at December 31, 2004. Such amounts are included in current
assets $1.1 billionas Due from Unconsolidated Affiliates. PE has a promissory note
due from Sempra Energy which bears a variable interest rate based on
40
short-term commercial paper rates. The balances of the note were $394
million and $354 million at December 31, 2004 and 2003, respectively,
and are included in noncurrent assets as Due from Unconsolidated
Affiliates. PE also had $2 million due from other affiliates at both
December 31, 2004 and $42003.
In addition, PE had intercompany payables due to various affiliates of
$127 million in current
liabilities were recorded as of January 1, 2001, in the Consolidated
Balance Sheets as fixed-priced contracts and other derivatives. Due to
the regulatory environment in which SoCalGas operates, regulatory
assets and liabilities were established to the extent that derivative
gains and losses are recoverable or payable through future rates. As
such, $982$121 million in current regulatory liabilities, $1.1 billion in
noncurrent regulatory liabilities, and $4 million in current
regulatory assets were recorded in the Consolidated Balance Sheets as
of January 1, 2001. See Note 8 for additional information on the
effects of SFAS 133 on the financial statements at December 31, 2001.
The ongoing effects will depend2004 and 2003,
respectively, which are reported as a current liability. These balances
are due on future market conditionsdemand. Of the total balances, $55 million was recorded at
SoCalGas at both December 31, 2004 and the
company's hedging activities.2003.
New Accounting Standards
SFAS 123 (revised 2004), "Share-Based Payment" (SFAS 123R): In July 2001,December
2004, the Financial Accounting Standards Board (FASB) issued SFAS 123R,
a revision of SFAS 123, Accounting for Stock-Based Compensation (SFAS
123), which establishes the accounting for transactions in which an
entity exchanges its equity instruments for goods or services received.
This statement requires companies to measure and record the cost of
employee services received in exchange for an award of equity
instruments based on the grant-date fair value of the award and gives
companies three alternative transition methods. The modified
prospective method requires companies to recognize compensation cost
for unvested awards that are outstanding on the effective date based on
the fair value that the company had originally estimated for purposes
of preparing its SFAS 123 pro forma disclosures. For all new awards
that are granted or modified after the effective date, a company would
use SFAS 123R's measurement model. The second alternative is a
variation of the modified prospective method, allowing companies to
restate earlier interim periods in the year that SFAS 123R is adopted
using applicable SFAS 123 pro forma amounts. Under the third
alternative, the modified retrospective method, companies would apply
the modified prospective method, but also restate their prior financial
statements to include the amounts that were previously reported in
their pro forma disclosures under the original provisions of SFAS 141 "Business Combinations,"123.
The company has not determined the transition method it will use. The
effective date of this statement is July 1, 2005 for Sempra Energy.
SFAS 142
"Goodwill132 (revised 2003), "Employers' Disclosures about Pensions and
Other Intangible Assets"Postretirement Benefits": This statement revised employers'
disclosures about pension plans and other postretirement benefit plans.
It requires disclosures beyond those in the original SFAS 132 about the
assets, obligations, cash flows and net periodic benefit cost of
defined benefit pension plans and other defined postretirement plans.
It does not change the measurement or recognition of those plans. Note
5 provides additional information on employee benefit plans.
SFAS 143, "Accounting for Asset Retirement Obligations." The first two are not presently
relevant to the company.Obligations": Beginning in
2003, SFAS 143 addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs. This applies to
legal obligations associated with the retirement of long-lived assets
that result from the acquisition, construction, development and/or
normal operation of a long-lived asset. It requires entities to record liabilities for future costs
expected to be incurred when assets are retired from service, if the
fair value of a liability for an asset retirement obligation in
the period in which itprocess is incurred. When the liability is initially
recorded, the entity increases the carrying amountlegally required. It requires recording of the
related
long-lived asset to reflect the futureestimated retirement cost. Over time, the
liability is accreted to its present value and paid, and the
capitalized cost is depreciated over the useful life of the related asset.asset by
depreciating the present value of the obligation (measured at the time
of the asset's acquisition) and by accreting the present value of the
estimated future obligation over the asset's estimated useful life. The
adoption of SFAS 143 on January 1, 2003 resulted in the recording of
41
asset retirement obligations of $10 million associated with the future
retirement of three storage facilities. It also requires the
reclassification of estimated removal costs, which had historically
been recorded in accumulated depreciation, to a regulatory liability.
At both December 31, 2004 and 2003, these costs were $1.4 billion.
Implementation of SFAS 143 has had no effect on results of operations
and is not expected to have a significant effect in the future.
The changes in the asset retirement obligations for the years ended
December 31, 2004 and 2003 are as follows (dollars in millions):
2004 2003
- ------------------------------------------------------------------
Balance as of January 1 $ 11* $ --
Adoption of SFAS 143 -- 10
Accretion expense 1 1
Revision of estimated cash flows (3) --
------ ------
Balance as of December 31 $ 9* $ 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. A final interpretation is expected to be
issued by the FASB in the first quarter of 2005 and would be effective
for the company on December 31, 2005. The company has not determined
the effect the proposed interpretation would have on its financial
statements if the proposed interpretation is adopted.
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, including certain
derivative instruments embedded in other contracts, 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. ("Unplanned
netting" refers to situations whereby contracts are settled by paying or
receiving money for the difference between the contract price and the
market price at the date on which physical delivery would have
occurred. The "normal purchases and normal sales exception" provides
for not marking to market contracts that are very rarely settled by
means other than physical delivery of the commodity involved in the
transaction.) In addition, effective January 1, 2004, power contracts
that are subject to unplanned netting and that do not meet the normal
purchases and normal sales exception under SFAS 149 will continue to be
marked to market. Implementation of SFAS 149 did not have a material
impact on reported net income.
42
SFAS 151, "Inventory Costs, an amendment of ARB No. 43, Chapter 4":
This statement amends the guidance in Accounting Research Bulletin
(ARB) No. 43, Chapter 4, Inventory Pricing, to clarify the accounting
for abnormal amounts of idle facility expense, freight, handling cost
and wasted material. This statement requires that those items be
recognized as current-period charges regardless of whether they meet
the criteria of "abnormal". The statement is effective for financial statements issued forinventory
costs incurred during fiscal years beginning after June 15, 2002.2005. The
company hasdoes not yet
determined the effect of SFAS 143 on its Consolidated Balance Sheets,
but has determinedexpect that itthis statement will not have a material impact on its
Statements of Consolidated Income.
In August 2001, the FASB issued SFAS 144 "Accounting for the
Impairment or Disposal of Long-Lived Assets" that replaces SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." SFAS 144 applies to all long-lived assets,
including discontinued operations. SFAS 144 requires that those long-
lived assets be measured at the lower of carrying amount (cost less
accumulated depreciation) or fair value less cost to sell.
Discontinued operations will no longer be measured at net realizable
value or include amounts for operating losses that have not yet
occurred. SFAS 144 also broadens the reporting of discontinued
operations to include all components of an entity with operations that
can be distinguished from the rest of the entity and that will be
eliminated from the ongoing operations of the entity in a disposal
transaction. The provisions of SFAS 144 are effective for fiscal years
beginning after December 15, 2001. The effect of adopting SFAS 144 is
not expected to have a material impact
on the company's financial statements.
NOTE 3. SHORT-TERM BORROWINGSFASB Staff Position (FSP) 106-2, "Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003": The Medicare Prescription Drug, Improvement
and Modernization Act of 2003 (the "Act") was enacted in December of
2003. 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. At December
31, 2001, PE had2003, the company elected a one-time deferral of the accounting for
the Act, as permitted by FSP 106-1, Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003.
In May 2004, the FASB issued FSP 106-2, which supersedes FSP 106-1 and
provides guidance on the accounting, disclosure, effective date and
transition requirements related to the Medicare Prescription Drug Act.
During 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 the net postretirement benefit cost for 2004
by $12 million. Employee benefit plans are discussed further in Note 5.
NOTE 2. SHORT-TERM BORROWINGS
Committed Lines of Credit
SoCalGas and its affiliate, SDG&E, have a combined $500 million two-yearthree-year
syndicated revolving linecredit facility under which each utility individually
may borrow up to $300 million, subject to a combined borrowing limit for
both utilities of $500 million. Borrowings under the agreement bear
interest at rates varying with market rates and SoCalGas' credit rating.
The agreement requires SoCalGas to maintain, at the end of each quarter, a
ratio of total indebtedness to total capitalization (as defined in the
agreement) of no more than 60 percent. Borrowings under the agreement are
individual obligations of the borrowing utility and a default by one
utility would not constitute a default, or preclude borrowings by, the
other. At December 31, 2004, SoCalGas had no amounts outstanding under this
facility. SoCalGas had $30 million of commercial paper outstanding at
December 31, 2004.
43
PE has a revolving credit commitment of $500 million that expires in
September 2005. Borrowings under the credit agreement are available to
provide loans to Sempra Global and would bear interest at rates varying
with market rates, PE's credit ratings and amounts borrowed. Borrowings are
guaranteed by Sempra Energy for the purpose of providing
loans to Sempra Energy Global Enterprises (Global). The revolving
credit commitment expires in April 2003, at which time then
outstanding borrowings may be converted into a two-year term loan.
Borrowingsand would be subject to mandatory prepayment should PE's issuer
credit rating cease to be at least BBB- by Standard & Poors (S&P),
should SoCalGas' unsecured long-term credit ratings cease to be at
least BBB by S&P and Baa2 by Moody's, shouldrepayment if
Sempra Energy's or SoCalGas' debt-to-totalratio of debt to total capitalization ratios (as
defined in the agreement) were to exceed 65 percent, or should there be a
change in law materially and adversely affecting the ability of SoCalGas to
pay dividends or make other distributions to PE. Borrowings would bear interest
at rates varying with market rates and the amount of theNo amounts were
outstanding borrowings. PE's line of credit was unusedunder this facility at December 31, 2001.
At December 31, 2001, SoCalGas had a $170 million syndicated
revolving line of credit, which is available to support commercial
paper. Borrowings under the agreement, which expires on May 26, 2002,
would bear interest at various rates based on market rates and
SoCalGas' credit rating. The agreement requires SoCalGas to maintain a
debt-to-total capitalization ratio (as defined in the agreement) of
not to exceed 65 percent. At December 31, 2001, SoCalGas had $50
million of commercial paper outstanding. The revolving line of credit
was unused at December 31, 2001 and 2000.2004.
The company's weighted average interest rate foron the total short-term borrowingsdebt
outstanding was 2.25% at December 31, 2001 was 2.04%.2004.
NOTE 4.3. LONG-TERM DEBT
- --------------------------------------------------------------
December 31,
(Dollars in millions) 2001 20002004 2003
- --------------------------------------------------------------
First-mortgageFirst mortgage bonds
6.875% August 15, 2002Variable rate (2.63% at December 31,
2004)December 1, 2009 $ 100 $ 100
5.75% November--
4.375% January 15, 20032011 100 100
7.375% MarchVariable rates after fixed-to-
floating rate swaps (2.69% at
December 31, 2004) January 15, 2011 150 150
4.8% October 1, 2023 100 100
7.5% June2012 250 250
5.45% April 15, 2023 125 125
Variable rates2018 250 250
6.875% November 1, 2025 (1.95% at December 31, 2001)-- 175
175
8.75% October 1, 2021 -- 150
-----------------------
600 750
-----------------------
Unsecured----------------------
850 925
----------------------
Other long-term debt
5.67% January 18, 2028 75 75
6.375% May 14, 2006 8 8
6.375% October 29, 2001 -- 120
-----------------------
83 203
-----------------------
Total 683 953
Less:5.67% January 18, 2028 5 5
Market value adjustments for interest
rate swaps - net (Expires 2011) 2 -
----------------------
15 13
----------------------
865 938
----------------------
Current portion of long-term debt 100 120-- (175)
Unamortized discount on long-term debt - 12
Market value adjustment on
Interest-rate swap 4 -
-----------------------(1) (1)
----------------------
Total $ 579864 $ 821762
- --------------------------------------------------------------
MaturitiesExcluding market value adjustments for interest-rate swaps, maturities
of long-term debt are $8 million in 2006, $100 million in 2002, $1752009 and $755
million in
2003 and $408 million after 2006.
First-mortgagethereafter.
First Mortgage Bonds
First-mortgageFirst mortgage bonds are secured by a lien on SoCalGas' utility plant.
SoCalGas may issue additional first-mortgagefirst mortgage bonds upon compliance with44
the provisions of its bond indentures, which require, among other
things, the satisfaction of pro forma earnings-coverage tests on first-first
mortgage bond interest and the availability of sufficient mortgaged
property to support the additional bonds.bonds, after giving effect to prior
bond redemptions. The most restrictive of these tests (the property
test) would permit the issuance, subject to CPUC authorization, of an
additional $753$598 million of first-mortgagefirst mortgage bonds as ofat December 31, 2001.
In November 2001,2004.
SoCalGas called its $150 million 8.75 percent
first-mortgage bonds at a premium of 3.59 percent.
On December 11, 2001, SoCalGas entered into an interest-rate swap
which effectively exchanged the fixed rate on its $175 million 6.875
percent first-mortgageof long-term debt in January 2004 and
incurred $2 million in call premium costs. This amount has been
recorded as a regulatory asset and is being amortized over the life of
the original issue.
In December 2004, the company issued $100 million of first mortgage
bonds for a floating rate. Additional
information is provided under "Interest-Rate Swaps" below.maturing in 2009. The bonds bear interest at 0.17% above LIBOR.
Unsecured Long-term Debt
Various long-term obligations totaling $83$13 million are unsecured at
December 31, 2001. In October 2001, SoCalGas repaid $1202004.
On January 15, 2003, $70 million of 6.38 percent medium-termSoCalGas' 5.67% $75 million medium-
term notes upon maturity.
Callable Bonds
At SoCalGas' option, certain fixed-rate bonds may be called at a
premium, including $400 million that are callable in 2003 and $8
million in 2006.were put back to the company.
Interest-Rate Swaps
SoCalGasThe company periodically enters into interest-rate swap agreements to
moderate its exposure to interest-rate changes and to lower its overall
cost of borrowing. AtIn December 31, 2001,2003, SoCalGas entered into an interest-
rate swap that effectively exchanged the company had one
such swap agreement. On December 11, 2001, SoCalGas executed a
cancelable-call interest-rate swap, exchanging its fixed rate obligationon $150 million of
6.875 percent on its $175$250 million first-mortgage4.375% first mortgage bonds for a floating rate of LIBOR plus 4 basis points.rate. The
transaction may
be cancelled every 5 years by either party by payment of the mark-to-
market value, or may be cancelled by the counterparty at any time the
bonds are callable, by payment to SoCalGas of the applicable call
premium on the bonds. The company believes the swap is fully
effectiveexpires in its purpose of converting the fixed rate stated in the
debt to a floating rate and the swap meets the criteria for accounting
under the short-cut method defined in SFAS no. 133 for fair value
hedges of debt instruments. Accordingly, a market value adjustment to
long-term debt of $4 million was recorded at December 31, 2001 to
reflect, without affecting net income or other comprehensive income,
the favorable economic consequences (as measured at December 31, 2001)
of having entered into the swap transaction. See additional
discussion of interest rate swaps in Note 8.
Financial Covenants
SoCalGas' first-mortgage bond indentures require the satisfaction of
certain bond interest coverage ratios and the availability of
sufficient mortgaged property to issue additional first-mortgage
bonds, but do not restrict other indebtedness. Note 3 discusses the
financial covenants applicable to short-term debt.2011.
NOTE 5.4. INCOME TAXES
The reconciliation of the statutory federal income tax rate to the
effective income tax rate is as follows:
Years ended December 31,
2001 2000 19992004 2003 2002
- -----------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 5.45.1 6.1 5.2 7.4
State income taxes, - net of
federal income tax benefit 6.9 6.9 7.34.8 5.8 5.4
Tax credits (0.7) (0.8) (0.7) (0.9)(0.8)
Settlement of Internal Revenue Service audit -- (3.1) --
Equity AFUDC (3.6) (1.0) (1.0)
Other, - net (1.1) 0.3 (1.4)
-----------------------------(3.2) 0.6
------------------------
Effective income tax rate 45.4% 46.7% 47.4%39.5% 38.8% 44.4%
- ---------------------------------------------------------------------------------------------------------------------------------------------
45
The components of income tax expense are as follows:
Years ended December 31,
(Dollars in millions) 2001 2000 19992004 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------------------
Current:
Federal $ 116125 $ 13973 $ 22103
State 30 41 9
----------------------------45 29 29
-----------------------
Total 146 180 31
----------------------------170 102 132
-----------------------
Deferred:
Federal 20 7 113(1) 37 36
State 8 -- 25
----------------------------(11) 4 5
-----------------------
Total 28 7 138
----------------------------(12) 41 41
-----------------------
Deferred investment tax credits - net (3) (2) (3) ----------------------------(3)
-----------------------
Total income tax expense $ 171155 $ 185140 $ 166170
- ----------------------------------------------------------------------
FederalOn the Statements of Consolidated Income, federal and state income
taxes are allocated between operating income and other income. PE is
included in the consolidated income tax return of Sempra Energy and is
allocated income tax expense from Sempra Energy in an amount equal to
that which would result from filingPE's having always filed a separate
return.46
Accumulated deferred income taxes at December 31 result fromrelate to the
following:
(Dollars in millions) 2001 20002004 2003
- ----------------------------------------------------------------------
Deferred Tax Liabilities:tax liabilities:
Differences in financial and
tax bases of utility plant and other assets $ 295266 $ 373269
Regulatory balancing accounts 56 1150 76
Regulatory assets 36 39-- 32
Global settlement -- (1)
Loss on reacquired debt 18 17
Other 49 111 30
--------------------
Total deferred tax liabilities 436 434335 423
--------------------
Deferred Tax Assets:tax assets:
Investment tax credits 34 3829 31
Postretirement benefits 36 3940 77
Deferred compensation 14 19
State income taxes 15 11
Workers compensation 21 20
Lease 15 18
Other deferred liabilities 174 143
Restructuring costs 42 43accruals not yet deductible 79 95
Other 73 648 7
--------------------
Total deferred tax assets 359 327221 278
--------------------
Net deferred income tax liability $ 77114 $ 107145
- ----------------------------------------------------------------------
The net deferred income tax liability is recorded on the Consolidated
Balance Sheets at December 31 as follows:
(Dollars in millions) 2001 20002004 2003
- ----------------------------------------------------------------------
Current asset(asset) liability $ (33)(9) $ (43)24
Noncurrent liability 110 150123 121
--------------------
Total $ 77114 $ 107145
- ----------------------------------------------------------------------
Pacific Enterprises' Quasi-Reorganization
Effective December 31, 1992, PE effected a quasi-reorganization for
financial reporting purposes. The reorganization resulted in a
restatement of the company's assets and liabilities to their estimated
fair value at December 31, 1992 and the elimination of PE's retained
earnings deficit. Since the reorganization was for financial purposes
and not a taxable transaction, the company established deferred taxes
relative to the book and tax bases differences.
During 2004, the company completed an extensive analysis of PE's
deferred tax accounts. The analysis resulted in a $72 million reduction
of the deferred tax liabilities and an offsetting credit to equity.
The credit was recorded to equity because the balances related to tax
47
effects of transactions prior to the quasi-reorganization. In 2004,
the company also concluded its outstanding IRS examinations and appeals
related to PE and its subsidiaries. As of December 31, 2004, the
company's balance sheet includes a net deferred tax asset of $15
million related to remaining reserves arising from the quasi-
reorganization.
NOTE 6.5. EMPLOYEE BENEFIT PLANS
Pension and Other Postretirement Benefits
The company sponsors qualifiedhas funded and nonqualified pensionunfunded noncontributory defined benefit
plans that together cover substantially all of its employees. The
plans provide defined benefits based on years of service and either
final average or career salary.
The company also has other postretirement benefit plans forcovering
substantially all of its employees. Effective March
1, 1999, the Pacific Enterprises Pension Plan merged with the Sempra
Energy Cash Balance Plan.
During 2000, the company participated in a voluntary
separation program. As a result, the company recorded a $40
million special termination benefit.
The following tables provide a reconciliation of the changes in
the plans' benefit obligationslife insurance plans are both
contributory and fair value of assets over the two
years,noncontributory, and a statement of the funded status as of each year end:
Other
Pension Benefits Postretirement Benefits
-----------------------------------------------
(Dollars in millions) 2001 2000 2001 2000
- ---------------------------------------------------------------------------------
Weighted-Average Assumptions
as of December 31:
Discount rate 7.25% 7.25%(1) 7.25% 7.25%
Expected return on plan assets 8.00% 8.00% 8.00% 8.00%
Rate of compensation increase 5.00% 5.00% 5.00% 5.00%
Cost trend of covered
health care charges -- -- 7.25%(2) 7.50%(2)
Change in Benefit Obligation:
Net benefit obligation at
January 1 $1,125 $1,057 $ 415 $ 408
Service cost 25 23 9 8
Interest cost 78 84 32 28
Actuarial (gain)loss (46) 79 23 (17)
Curtailments -- (4) -- 4
Special termination benefits -- 34 -- 2
Benefits paid (71) (148) (22) (18)
-----------------------------------------------
Net benefit obligation at
December 31 1,111 1,125 457 415
-----------------------------------------------
Change in Plan Assets:
Fair value of plan assets
at January 1 1,682 1,971 434 463
Actual return on plan assets (162) (141) (33) (23)
Employer contributions -- -- 13 10
Transfer of assets (3) 3 -- -- 2
Benefits paid (71) (148) (22) (18)
-----------------------------------------------
Fair value of plan assets
at December 31 1,452 1,682 392 434
-----------------------------------------------
Plan assets net of benefit
obligation at December 31 341 557 (65) 19
Unrecognized net actuarial gain (322) (591) (23) (116)
Unrecognized prior service cost 35 38 -- --
Unrecognized net transition
obligation 2 2 -- --
-----------------------------------------------
Net recorded asset (liability)
at December 31 $ 56 $ 6 $ (88) $ (97)
- ---------------------------------------------------------------------------------
(1) Discount rate decreased from 7.75% to 7.25%, effective March 1, 2000.
(2) Decreasing to ultimate trend of 6.50% in 2004.
(3) To reflect transfer of plan assets and liability to Sempra Energy.
The following table provides the amounts recognized on the
Consolidated Balance Sheets (under "sundry" and under "postretirement
benefits other than pensions") at December 31:
Other
Pension Benefits Postretirement Benefits
---------------------------------------------
(Dollars in millions) 2001 2000 2001 2000
- ------------------------------------------------------------------------------------
Prepaid benefit cost $ 67 $ 15 -- --
Accrued benefit cost (11) (9) $(88) $(97)
Additional minimum liability (2) (4) -- --
Intangible asset 1 1 -- --
Accumulated other
comprehensive income, pre-tax 1 3 -- --
- ------------------------------------------------------------------------------------
Net recorded asset(liability) $ 56 $ 6 $(88) $(97)
- ------------------------------------------------------------------------------------
The following table provides the components of net periodic
benefit cost for the plans:
Other
Pension Benefits Postretirement Benefits
(Dollars in millions) -----------------------------------------------
For the years ended December 31 2001 2000 1999 2001 2000 1999
- ---------------------------------------------------------------------------------
Service cost $ 25 $ 23 $ 28 $ 9 $ 8 $ 11
Interest cost 78 84 77 32 28 30
Expected return on assets (129) (131) (112) (34) (32) (27)
Amortization of:
Transition obligation 1 1 1 8 9 9
Prior service cost 3 4 4 -- -- --
Actuarial gain (28) (29) (14) (3) (8) --
Special termination benefits -- 33 -- -- 7 --
Regulatory adjustment 51 18 17 29 28 24
-----------------------------------------------
Total net periodic benefit cost $ 1 $ 3 $ 1 $ 41 $ 40 $ 47
- ---------------------------------------------------------------------------------
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A one-percent change in
assumed health care cost trend rates would have the following effects:
- -----------------------------------------------------------------------
(Dollars in millions) 1% Increase 1% Decrease
- -----------------------------------------------------------------------
Effect on total of service and interest cost
components of net periodic postretirement
health care benefit cost $ 8 $ (6)
Effect on the health care component of the
accumulated other postretirement benefit $76 $(60)
obligation
- -----------------------------------------------------------------------
Except for one nonqualified, unfunded retirement plan, all pension
plans had plan assets in excess of accumulated benefit obligations.
For that one plan the projected benefit obligation and accumulated
benefit obligation were $13 million and $12 million, respectively, as
of December 31, 2001, and $16 million and $12 million, respectively,
as of December 31, 2000.are
contributory, with participants' contributions adjusted annually. Other
postretirement benefits include retiree life insurance, medical
benefits for retirees and their spouses, and Medicare Part B
reimbursement for certain retirees.
There were no amendments to the company's pension and other
postretirement benefit plans in 2003 or 2004. During 2002, the company
had amendments reflecting retiree cost of living adjustments, which
resulted in an increase in the pension plan benefit obligation of $48
million.
December 31 is the measurement date for the pension and other
postretirement benefit plans. The following table provides a
reconciliation of the changes in the plans' projected benefit
obligations during the latest two years, the fair value of assets and a
statement of the funded status as of the latest two year ends:
48
Other
Pension Benefits Postretirement Benefits
---------------- -----------------------
(Dollars in millions) 2004 2003 2004 2003
- -----------------------------------------------------------------------------------------
CHANGE IN PROJECTED BENEFIT OBLIGATION:
Net obligation at January 1 $ 1,551 $ 1,368 $ 820 $ 682
Service cost 30 27 17 15
Interest cost 93 90 43 47
Actuarial loss (gain) 84 172 (74) 103
Transfer of liability from Sempra Energy 2 6 -- --
Benefit payments (135) (112) (34) (27)
---------------------------------------------
Net obligation at December 31 1,625 1,551 772 820
---------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at January 1 1,473 1,289 471 370
Actual return on plan assets 176 294 53 83
Employer contributions -- 2 42 45
Transfer of assets from Sempra Energy 2 -- -- --
Benefit payments (135) (112) (34) (27)
---------------------------------------------
Fair value of plan assets at December 31 1,516 1,473 532 471
---------------------------------------------
Benefit obligation, net of plan assets
at December 31 (109) (78) (240) (349)
Unrecognized net actuarial loss 74 71 176 277
Unrecognized prior service cost 65 71 -- --
Unrecognized net transition obligation -- 1 -- --
---------------------------------------------
Net recorded asset (liability)
at December 31 $ 30 $ 65 $ (64) $ (72)
- -----------------------------------------------------------------------------------------
The net asset (liability) is recorded on the Consolidated Balance
Sheets at December 31 as follows:
Other
Pension Benefits Postretirement Benefits
---------------- -----------------------
(Dollars in millions) 2004 2003 2004 2003
- -----------------------------------------------------------------------------------------
Prepaid benefit cost $ 46 $ 78 $ -- $ --
Accrued benefit cost (16) (13) (64) (72)
Additional minimum liability (7) (6) -- --
Accumulated other comprehensive
income (pretax) 7 6 -- --
-------------------------------------------
Net recorded asset (liability) $ 30 $ 65 $ (64) $ (72)
- -----------------------------------------------------------------------------------------
At December 31, 2004 and 2003, the company had an unfunded and a funded
pension plan. The funded plan had projected benefit obligations in
excess of its plan assets. The following table provides information for
the funded plan at December 31:
(Dollars in millions) 2004 2003
- -------------------------------------------------------------
Projected benefit obligation $ 1,596 $ 1,526
Accumulated benefit obligation $ 1,384 $ 1,333
Fair value of plan assets $ 1,516 $ 1,473
49
The following table provides the components of net periodic benefit
costs (income) for the years ended December 31:
Other
Pension Benefits Postretirement Benefits
---------------- -----------------------
(Dollars in millions) 2004 2003 2002 2004 2003 2002
- -----------------------------------------------------------------------------------------
Service cost $ 30 $ 27 $ 27 $ 17 $ 15 $ 10
Interest cost 93 90 86 43 47 35
Expected return on assets (98) (107) (130) (34) (32) (35)
Amortization of:
Transition obligation -- 1 1 -- 8 8
Prior service cost 7 6 4 -- -- --
Actuarial (gain) loss 3 1 (19) 8 9 --
Regulatory adjustment (61) (14) 32 10 (4) 24
--------------------------------------------------
Total net periodic benefit
cost (income) $ (26) $ 4 $ 1 $ 44 $ 43 $ 42
- -----------------------------------------------------------------------------------------
As described in Note 1, the company adopted FSP 106-2 in 2004
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 the net
postretirement benefit cost for 2004 by $12 million.
The significant assumptions related to the company's pension and other
postretirement benefit plans are as follows:
Other
Pension Benefits Postretirement Benefits
---------------- -----------------------
2004 2003 2004 2003
- ----------------------------------------------------------------------------------------
WEIGHTED-AVERAGE ASSUMPTIONS USED
TO DETERMINE BENEFIT OBLIGATION
AS OF DECEMBER 31:
Discount rate 5.66% 6.00% 5.66% 6.00%
Rate of compensation increase 4.50% 4.50% 4.50% 4.50%
WEIGHTED-AVERAGE ASSUMPTIONS USED
TO DETERMINE NET PERIODIC BENEFIT
COSTS FOR YEARS ENDED DECEMBER 31:
Discount rate 6.00% 6.50% 6.00% 6.50%
Expected return on plan assets 7.50% 7.50% 7.50% 7.50%
Rate of compensation increase 4.50% 4.50% 4.50% 4.50%
- ----------------------------------------------------------------------------------------
50
The expected long-term rate of return on plan assets is derived from
historical returns for broad asset classes consistent with
expectations from a variety of sources, including pension consultants
and investment advisors.
2004 2003
- -----------------------------------------------------------------------------------------
ASSUMED HEALTH CARE COST
TREND RATES AT DECEMBER 31:
Health-care cost trend rate 19.00% * 30.00% *
Rate to which the cost trend rate is assumed to
decline (the ultimate trend) 5.50% 5.50%
Year that the rate reaches the ultimate trend 2008 2008
- ----------------------------------------------------------------------------------------
* This is the weighted average of the increases for all health plans. The rate for these
plans ranged from 10% to 20% in 2004 and from 15% to 40% in 2003, respectively.
Assumed health-care cost trend rates have a significant effect on the
amounts reported for the health-care plan costs. A one-percent change
in assumed health-care cost trend rates would have the following
effects:
(Dollars in millions) 1% Increase 1% Decrease
- -----------------------------------------------------------------------------------------
Effect on total of service and interest cost
components of net periodic postretirement
health-care benefit cost $ 12 $ 9
Effect on the health-care component of the
accumulated other postretirement
benefit obligation $ 123 $ 97
- -----------------------------------------------------------------------------------------
Pension Plan Investment Strategy
The asset allocation for Sempra Energy's pension trust (which includes
SoCalGas' pension plan) at December 31, 2004 and 2003 and the target
allocation for 2005 by asset categories are as follows:
Target Percentage of Plan
Allocation Assets at December 31,
---------- ----------------------
Asset Category 2005 2004 2003
- ------------------------------------------------------------------------------------------
U.S. Equity 45% 45% 45%
Foreign Equity 25 32 30
Fixed Income 30 23 25
-------------------------------------------
Total 100% 100% 100%
- ------------------------------------------------------------------------------------------
51
The company's investment strategy is to stay fully invested at all
times and maintain its strategic asset allocation, keeping the
investment structure relatively simple. The equity portfolio is
balanced to maintain risk characteristics similar to the Standard &
Poor's 1500 with respect to market capitalization, and industry and
sector exposures. The foreign equity portfolios are managed to track
the MSCI Europe, Pacific Rim and Emerging Markets indexes. Bond
portfolios are managed with respect to the Lehman Aggregate Index. The
plan does not invest in Sempra Energy securities.
Investment Strategy for Other Postretirement Benefit Plans
The asset allocation for the company's other postretirement benefit
plans at December 31, 2004 and 2003 and the target allocation for 2005
by asset categories are as follows:
Target Percentage of Plan
Allocation Assets at December 31,
---------- ----------------------
Asset Category 2005 2004 2003
- ------------------------------------------------------------------------------------------
U.S. Equity 70% 73% 71%
Fixed Income 30 27 27
Cash 0 0 2
-------------------------------------------
Total 100% 100% 100%
- ------------------------------------------------------------------------------------------
The company's other postretirement benefit plans, which are distinct
from other postretirement benefit plans included in Sempra Energy's
pension trust (shown above), are funded by cash contributions from the
company and the retirees. The asset allocation is designed to match the
long-term growth of the plan's liability. These plans are managed using
index funds.
Future Payments
The company expects to contribute $2 million to its pension plan and
$45 million to its other postretirement benefit plans in 2005.
The following table reflects the total benefits expected to be paid for
the next 10 years to current employees and retirees from the plans or
from the company's assets, including both the company's share of the
benefit cost and, where applicable, the participants' share of the
costs, which is funded by participant contributions to the plans.
52
Other
(Dollars in millions) Pension Benefits Postretirement Benefits
- -------------------------------------------------------------------------------
2005 $ 104 $ 32
2006 $ 109 $ 34
2007 $ 115 $ 37
2008 $ 120 $ 39
2009 $ 126 $ 41
2010-2014 $ 705 $ 234
- -------------------------------------------------------------------------------
The expected future Medicare Part D subsidy payments are as follows:
(Dollars in millions)
- -------------------------------------------------------------------------------
2005 $ --
2006 $ 3
2007 $ 3
2008 $ 3
2009 $ 3
2010-2014 $ 21
- -------------------------------------------------------------------------------
Savings Plan
SoCalGasThe company offers a trusteed savings plan administered by plan trustees, to all eligible employees.
Eligibility to participate in the plan is immediate for salary
deferrals. Employees may contribute, subject to plan provisions, from
one percent to 1525 percent of their regular earnings. After one year of
completed service, the company begins to make matching contributions.
Employer contributions are equal to 50 percent of the first 6 percent
of eligible base salary contributed by employees.employees and, if certain
company goals are met, an additional amount related to incentive
compensation payments.
Employer contributions are invested in Sempra Energy common stock (new issuances or market purchases) and
musthad been required to remain so invested until termination of employment. Atemployment
or until the directionemployee's attainment of age 55, when they could be
transitioned into other investments. Effective January 1, 2005, all
employees have the employees,
the employee'sability to transfer employer contributions into
other investments. The employees' contributions are invested in Sempra
Energy stock, mutual funds, or institutional trusts.trusts (the same
investments in which employees may now direct the employer
contributions). Employer contributions for the SoCalGas planplans are
partially funded by the Sempra Energy Employee Stock
Ownership Plan and Trust (formerly the Pacific Enterprises Employee
Stock Ownership Plan and Trust).Trust. Company contributions to the savings plan
were $7$10 million in 2001, $52004, $9 million in 20002003 and $6$8 million in 1999.2002.
NOTE 7.6. STOCK-BASED COMPENSATION
Sempra Energy has stock-based compensation plans intended to align
employee and shareholder objectives related to Sempra Energy's long-
term growth.the long-term growth of
the company. The plans permit a wide variety of stock-based awards,
53
including Sempra Energy non-qualifiednonqualified stock options, incentive stock options,
restricted stock, stock appreciation rights, performance awards, stock
payments and dividend equivalents.
In 1995, SFAS No. 123, "AccountingAccounting for Stock-Based Compensation," was issued.
It encourages a fair value-basedfair-value-based method of accounting for stock-based
compensation. As permitted by SFAS No. 123, Sempra Energy and its
subsidiaries adopted only its disclosure requirements and continue to
account for stock-based compensation in accordance with the provisions
of Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees."25. Discussion of SFAS 123R (a
revision of SFAS 123) is provided in Note 1. The subsidiaries record an
expense for the plans to the extent that subsidiary employees
participate in the plans or that subsidiaries are allocated a portion
of Sempra Energy's costs of the plans. PE recorded expenses (credits) of $3$9
million, $2$9 million and ($4 million)$1 million in 2001, 20002004, 2003 and 1999,2002,
respectively.
NOTE 8.7. FINANCIAL INSTRUMENTS
Fair Value
The fair values of certain of the company's financial instruments
(cash, temporary investments, notes receivable, dividends payable,
short-term debt and
customer deposits) approximate thetheir carrying amounts. The following
table provides the carrying amounts and fair values of the remaining
financial instruments at December 31:
2004 2003
Carrying Fair Carrying Fair
(Dollars in millions) Amount Value Amount Value
(Dollars in millions) 2001 2000
- ---------------------------------------------------------------------------------------------------------------------------------------------------------
Long-termFirst mortgage bonds $ 850 $ 856 $ 925 $ 925
Other long-term debt $683 $682 $953 $936
- --------------------------------------------------------------------------15 12 13 10
-------------------------------------------
Total long-term debt $ 865 $ 868 $ 938 $ 935
-------------------------------------------
PE:
Preferred stock $ 80 $ 4766 $ 80 $ 4265
Preferred stock of subsidiary 20 17 20 14
------ ------ ------ ------
$10020 19
-------------------------------------------
$ 64 $100100 $ 56
- --------------------------------------------------------------------------86 $ 100 $ 84
-------------------------------------------
SoCalGas:
Preferred stock $ 22 $ 1821 $ 22 $ 1520
- --------------------------------------------------------------------------
The fair values of the long-term debt and preferred stock were estimated based on
quoted market prices for them or for similar issues.-------------------------------------------------------------------------------
The fair values of long-term debt and preferred stock are based on
their quoted market prices or quoted market prices for similar
securities.
Accounting for Derivative Instruments and Hedging Activities
Effective January 1, 2001,The company follows the company adoptedguidance of SFAS 133 as amended byand related amendments
SFAS 138 "Accountingand 149 (collectively SFAS 133) to account for Certainits derivative
54
instruments and hedging activities. Derivative Instrumentsinstruments and Certain
Hedging Activities." As amended, SFAS 133 requires that an entity
recognize all derivative instrumentsrelated
hedges are recognized as either assets or liabilities inon the statement of financial position, measure those instrumentsbalance
sheet, measured at fair value and recognize changesvalue. Changes in the fair value of derivatives
are recognized in earnings in the period of change unless the
derivative instruments
qualifies as an effective hedge that offsets certain
exposures.
Atexposure.
SFAS 133 provides for hedge accounting treatment when certain criteria
are met. For derivative instruments designated as fair value hedges,
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; therefore, there is no effect on
net income. 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
similarly reflected. The ineffective portion is reported in earnings
immediately. There was no effect on other comprehensive income for the
years ended December 31, 2001, $59 million2004 and 2003. In instances where derivatives
do not qualify for hedge accounting, gains and losses are recorded in
currentearnings 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 by the company and the prices to be charged to
its customers. The use of derivative financial instruments is subject
to certain limitations imposed by company policy and regulatory
requirements. The company classifies its forward contracts as follows:
Contracts that meet the definition of normal purchase and sales, i.e.,
those that rarely settle by means other than physical delivery of the
commodities involved in the transaction, are eligible for the normal
purchases and sales exception of SFAS 133, whereby they are accounted
for under accrual accounting and recorded in Revenues or Cost of
Natural Gas on the Statements of Consolidated Income at the time of
delivery. Due to the adoption of SFAS 149, the company has determined
that its natural gas contracts entered into after June 30, 2003
generally do not qualify for the normal purchases and sales exception.
Natural Gas Purchases and Sales: The unrealized gains and losses
related to these forward contracts are offset by regulatory assets $1 millionand
liabilities on the Consolidated Balance Sheets to the extent derivative
gains and losses will be recoverable or payable in other noncurrent assets, $103 million in current liabilitiesfuture rates. If
gains and $162 million in noncurrent liabilitieslosses are not recoverable or payable through future rates,
the company applies hedge accounting if certain criteria are met. When
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.
55
The following were recorded in the Consolidated Balance Sheets for fixed-priced contracts and other
derivatives.at
December 31 related to derivatives:
(Dollars in millions) 2004 2003
- -------------------------------------------------------------------------
Fixed-price Contracts and Other Derivatives:
Current liabilities $ 97 $ 86
Noncurrent liabilities 52 148
----------------------
Total 149 234
----------------------
Current assets 1 --
Noncurrent assets 2 --
----------------------
Total 3 --
----------------------
Net liabilities $ 146 $ 234
- -------------------------------------------------------------------------
Regulatory assets and liabilities were establishedrelated to the
extent that derivative gains and losses are recoverable or payable
through future rates.derivatives held by SoCalGas
at December 31 were:
(Dollars in millions) 2004 2003
- -------------------------------------------------------------------------
Regulatory Assets and Liabilities:
Current regulatory assets $ 97 $ 85
Noncurrent regulatory assets 52 148
----------------------
Total 149 233
Current regulatory liabilities 1 --
----------------------
Net $ 148 $ 233
- -------------------------------------------------------------------------
As such, $103 million in current regulatory
assets, $157 million in noncurrent regulatory assets, $50 million in
regulatory balancing account liabilities, $3 million in other current
liabilities and $1 million in accumulated other comprehensive income
were recorded in the Consolidated Balance Sheets as of December 31, 2001. For2004, the year ended December 31, 2001, $3 million in other
operating incomedifference between net liabilities and net
regulatory assets was recorded in the Statements of Consolidated
Income. The remaining $4 million was aprimarily due to market value adjustment to
long-term debtadjustments of $2
million related to a fixed-to-floating interest rate swap
agreement discussed below.
Changes in the fair value of derivative instruments of $53
millionswaps. The above had
no impact on net income during 2004 and $72 million for 2001 and 2000, respectively, have
been recognized in the Statements of Consolidated Income under
"cost of natural gas distributed").2003.
Market Risk
The company's policy is to use derivative physical and financial
instruments to managereduce its exposure to fluctuations in interest rates
foreign-currency
exchange rates and energycommodity prices. Transactions involving these financial instruments are with
major exchanges and other firms believed to be credit worthy and
major exchanges.credit-worthy. The use
of these instruments exposes the company to market and credit risk,56
which may at times be concentrated with certain counterparties,
although counterparty nonperformance is not anticipated.
Interest-Rate Risk Management
The company periodically enters into interest-rate swap agreements to
moderate its exposure to interest-rate changes and to lower the overall
cost of borrowing. At December 31, 2001, SoCalGas had one such
agreement, a cancelable-call interest-rate swap, exchanging a fixed
rate obligation of 6.875% on its $175 million first-mortgage bonds,
maturingThis is described in 2025, for a floating rate of LIBOR plus 4 basis points.
The transaction may be canceled every 5 years by either party by
payment of the mark-to-market value, or may be canceled by the
counterparty at any time the bonds are callable, by payment to
SoCalGas of the applicable call premium on the bonds. SoCalGas assumes
the swap is fully effective in its purpose of converting the fixed
rate stated in the debt to a floating rate since the swap meets the
criteria for accounting under the short-cut method defined in SFAS No.
133 for fair value hedges of debt instruments. Accordingly, a market
value adjustment of $4 million (as discussed above) was recorded in
long-term debt at December 31, 2001 and no net gains or losses were
recorded in income in respect of the swap.
Energy Derivatives
SoCalGas utilizes derivative financial instruments to reduce its
exposure to unfavorable changes in natural gas prices which are
subject to significant and often volatile fluctuation. Derivative
financial instruments are comprised of futures, forwards, swaps,
options and long-term delivery contracts. These contracts allow
SoCalGas to predict with greater certainty the effective prices to be
received and the prices to be charged to their customers. See Note 2
of the notes to Consolidated Financial Statements for discussion of
how these derivatives are classified under SFAS 133.3.
Energy Contracts
SoCalGas records transactions for natural gas contracts in "CostCost of
gas distributed"Natural Gas in the Statements of Consolidated Income. For open
contracts not expected to result in physical delivery, changes in
market value of the contracts are recorded in these accounts during the
period the contracts are open, with an offsetting entry to a regulatory
asset or liability. The majority of SoCalGas'the company's contracts result in
physical delivery.
NOTE 9.8. PREFERRED STOCK
OF SOUTHERN CALIFORNIA GAS COMPANYPreferred Stock of Southern California Gas Company
- -----------------------------------------------------------------
December 31,
(Dollars in millions) 2001 20002004 2003
- -----------------------------------------------------------------
(in millions)
$25 par value, authorized 1,000,000 shares
6% Series, 28,04928,041 shares outstanding $ 1 $ 1
6% Series A, 783,032 shares outstanding 19 19
Without par value, authorized 10,000,000 shares -- --
--------------
$ 20 $ 20
- -
--------------
$20 $20
- ---------------------------------------------------------------------------------------------------------------------------------
None of SoCalGas' preferred stock is callable. All series have one
vote per share and cumulative preferences as to dividends, and have a
liquidation value of $25 per share plus any unpaid dividends.
In
addition, the 6% Series preferred stock would also share pro rata with
common stock in the remaining assets.
NOTE 10. PREFERRED STOCK OF PACIFIC ENTERPRISES
- -------------------------------------------------------------------
Call December 31,
(Dollars in millions) Price 2001 2000
- -------------------------------------------------------------------
$4.75 Dividend,
200,000 shares outstanding $100.00 $ 20 $ 20
$4.50 Dividend,
300,000 shares outstanding $100.00 30 30
$4.40 Dividend,
100,000 shares outstanding $101.50 10 10
$4.36 Dividend,
200,000 shares outstanding $101.00 20 20
$4.75 Dividend,
253 shares outstanding $101.00 - -
------------------
Total preferred stock $ 80 $ 80
- -------------------------------------------------------------------57
Preferred Stock of Pacific Enterprises
- -----------------------------------------------------------------------------
December 31,
Call Price 2004 2003
- -----------------------------------------------------------------------------
(in millions)
$4.75 Dividend, 200,000 shares outstanding $ 100.00 $ 20 $ 20
$4.50 Dividend, 300,000 shares outstanding $ 100.00 30 30
$4.40 Dividend, 100,000 shares outstanding $ 101.50 10 10
$4.36 Dividend, 200,000 shares outstanding $ 101.00 20 20
$4.75 Dividend, 253 shares outstanding $ 101.00 -- --
------------------
$ 80 $ 80
- -----------------------------------------------------------------------------
PE is authorized to issue 15,000,000 shares of preferred stock without
par value. The preferred stock is subject to redemption at PE's option
at any time upon not less than 30 days' notice, at the applicable
redemption price for each series, together withplus any unpaid dividends. All
series have one vote per share and cumulative preferences as to
dividends, and have a liquidation value of $100 per share plus any
unpaid dividends.
NOTE 11.9. REGULATORY MATTERS
Natural Gas Industry Restructuring (GIR)
In December 2001, the CPUC issued a decision related to GIR, with
implementation anticipated during 2002. On April 1, 2004, after many
delays and changes, the CPUC issued a decision that adopts tariffs to
implement the 2001 decision. However, by that same decision, the CPUC
stayed implementation of the GIR tariffs until it issues a decision in
Phase I of the Natural Gas Market Order Instituting Ratemaking (OIR)
discussed below. At that time, the CPUC will reconcile the GIR market
structure with whatever structure results from the Phase I decision of
the Natural Gas Market OIR. If implemented, the stayed decision would
unbundle the costs of SoCalGas' backbone transmission system from rates
and result in revising noncore balancing account treatment to exclude
the balancing of SoCalGas' backbone transmission costs and place
SoCalGas at risk for recovery of $80 million for transmission and $81
million for storage (current dollars). The decision would create firm
tradable rights for the transmission system. Other noncore
costs/revenues would continue to be fully balanced until the decision
in the next Biennial Cost Allocation Proceeding (BCAP) discussed below.
Natural Gas Market OIR
The CPUC's Natural Gas Market OIR was instituted in January 2004, and
will be addressed in two phases. A decision on Phase I was issued in
58
September 2004 and Phase II is awaiting CPUC direction on further
proceedings. In Phase I, the CPUC's objective was to develop a process
enabling the CPUC to review and pre-approve new interstate capacity
contracts before they are executed. In addition, the California
Utilities must submit proposals on any liquefied natural gas (LNG)
project to which interconnection is planned, providing costs and terms,
including access to the pipelines in Mexico being developed by an
affiliated company, Sempra Pipelines and Storage. Phase II will
primarily address emergency reserves and ratemaking policies. The
CPUC's objective in the ratemaking policy component of Phase II is to
identify and propose changes to policies that create incentives that
are consistent with the goal of providing adequate and reliable long-
term supplies and that do not conflict with energy efficiency programs.
The focus of the Gas OIR is the period from 2006 to 2016. Since GIR,
discussed above, 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 LNG, which is the business
of an affiliated company, Sempra 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 approved the California
Utilities' transportation capacity pre-approval procedures with some
modifications. SoCalGas' existing pipeline capacity contracts with
Transwestern Pipeline Company expire in November 2005 and its primary
contracts with El Paso Natural Gas Company expire in August 2006.
SoCalGas recently was granted pre-approval by the CPUC of a contract
for released capacity on the Kern River Gas Transmission Company
system, and four capacity contracts with El Paso. The contracts would
expire between 2007 and 2011. In February 2005, SoCalGas filed for pre-
approval of two new capacity contracts with Transwestern that would
expire in 2009 and 2011. The CPUC's decision on pre-approval of the
Transwestern contracts is expected to be received by March 2005. All
interstate transportation capacity under the pre-approved contracts
will be used to transport natural gas supplies on behalf of the
California Utilities' core residential and small commercial customers,
and all costs of the capacity will be recovered in the customers' rates
through each utility's Purchased Gas Account, a balancing account. In
December 2004, pursuant to the Phase I decision, SoCalGas filed an
application to implement proposals for transmission system integration,
firm access rights, and off-system delivery services. The CPUC has
determined that the ratemaking treatment and cost responsibility for
any access-related infrastructure will be addressed in future
59
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
On December 2, 2004, the CPUC issued a decision in the California
Utilities' cost of service proceedings that essentially approved a
settlement recommended by all major parties to the proceedings. The
decision reduces the California Utilities' annual rate revenues,
effective retroactively to January 1, 2004, by an aggregate net amount
of approximately $33 million from the rates in effect during 2003. The
reduced rates will remain in effect through 2007, subject to annual
attrition allowances.
Attrition allowances, performance-based incentive mechanisms (PBR),
which is described in the following section, and related matters will
be addressed by the CPUC in Phase II of the cost of service
proceedings, expected to be decided in the first quarter of 2005. In
addition to recommending changes in the PBR formulas, the CPUC's Office
of Ratepayer Advocates (ORA) also proposed the possibility of
performance penalties for service quality, safety and service
reliability, without the possibility of performance awards. Hearings
took place in June 2004. In July 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 earnings sharing. The proposed settlement 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, each of which
limits the adjustment to approximately two to four percent of the prior
year's authorized base rate revenues.
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
extent of rewards or penalties. As part of the proposed Phase II
Settlement Agreement, earnings 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
earnings sharing mechanism also provides the utility the option to file
for suspension of the earnings sharing mechanism if earnings fall 175
basis points or more below its authorized rate of return; however, if
earnings are more than 300 basis points above the utility's authorized
rate of return, the earnings 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.
On February 15, 2005, the Administrative Law Judge (ALJ) and the CPUC
Commissioner assigned to Phase II of the cost of service proceedings
issued differing proposed decisions for consideration by the CPUC. If
60
adopted by the CPUC, the ALJ's decision would not approve the parties'
settlement of the Phase II issues, but would authorize the California
Utilities to adjust their authorized revenues in each of years 2005
through 2007 on a formula basis similar to that proposed by the
California Utilities and also establish performance measures with
reward and penalty potentials of approximately $20 million. In
addition, the ALJ's decision would have the utilities' cost of capital
reviewed on an annual basis. If adopted by the CPUC, the Commissioner's
proposed decision would approve the parties' settlement and also
approve performance measures for customer service, safety and
reliability with the same reward and penalty provisions as the ALJ's
proposed decision. The Commissioner's proposed decision also would
continue the use of the cost of capital adjustment mechanism currently
in place, which adjusts each utility's rate of return automatically
based on market indices. The CPUC may adopt either proposed decision,
as proposed or with modifications, or reject both and adopt a different
result.
The California Utilities had been equally sharing between ratepayers
and shareholders the estimated savings for the 1998 business
combination that created Sempra Energy. Pursuant to an October 2001
CPUC decision, that sharing has ceased and all merger savings go to
ratepayers beginning with 2003.
Performance-Based Regulation
PBR consists of three primary components. The first is a mechanism to
adjust rates in years between general rate cases or cost of service
cases. It annually adjusts base rates from those of the prior year to
provide for inflation, changes in the number of customers and
efficiencies.
The second component is a mechanism whereby any earnings in excess of
those authorized plus a narrow band above that are shared with
customers in varying degrees depending upon the amount of the
additional earnings.
The third component consists of a series of measures of utility
performance. Generally, if performance is outside of a band around the
specified benchmark, the utility is rewarded or penalized certain
dollar amounts.
The three areas that have been eligible for PBR rewards or penalties
are operational incentives based on measurements of safety, reliability
and customer satisfaction; demand-side management (DSM) rewards based
on the effectiveness of the programs; and natural gas procurement
rewards or penalties. However, as noted under "Cost of Service," Phase
II of the California Utilities' current cost of service proceeding is
not complete. As a result, these safety, reliability and customer
satisfaction incentive mechanisms (i.e., those that are reviewed in the
Cost of Service proceeding) were not in effect during 2004. However, it
is not expected that the effect would be other than a one-year
moratorium of the mechanisms.
PBR, 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 2004 consisted of $6.3
61
million related to SoCalGas' Year 9 GCIM, which was approved in
February 2004. This reward was awarded by the CPUC subject to refund
based on the outcome of the Border Price Investigation 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 in 2004, or previously.
On December 30, 2004, a joint settlement agreement between the
California Utilities and the ORA (collectively, the joint parties) was
filed with the CPUC for approval. The settlement agreement resolves
all outstanding shareholder earnings claims filed with the CPUC
commencing in 2000 and those claims that would have been filed through
2009 associated with DSM, energy efficiency and low-income energy
efficiency programs. The proposed settlement is for $14 million,
respectively, for SDG&E and SoCalGas (including interest, franchise
fees, uncollectible amounts and awards earned in prior years that had
not yet then been requested). The joint parties requested expeditious
approval of the settlement agreement, without modification. A CPUC
decision is expected by the end of the second quarter of 2005.
At December 31, 2004, other performance incentives were pending CPUC
approval and, therefore, were not included in the company's earnings
(dollars in millions):
Program
-----------------------------------
GCIM Year 10 $ 2.4
2003 safety .5
-----------------------------------
Total $ 2.9
-----------------------------------
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 5.03 percent and the
Global Insight forecast was 5.44 percent at December 31, 2004.
Potential changes in this process are described above in "Cost of
Service."
Biennial Cost Allocation Proceeding
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 stayed 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
62
Restructuring above, in May 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 in the GIR implementation
proceeding 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 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.
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 their 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 a May 2004 opinion, 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.
CPUC Investigation of Compliance With Affiliate Rules
In February 2003, the CPUC opened an investigation of the business
activities of SDG&E, SoCalGas and Sempra Energy to determine if they
have complied with statutes and CPUC decisions in the management,
oversight and operations of their companies. In September 2003, the
CPUC suspended the procedural schedule until it completes an
independent audit to evaluate energy-related holding company systems
and affiliate activities undertaken by Sempra Energy within the service
territories of SDG&E and SoCalGas. The audit, covering years 1997
through 2003, is expected to be completed by the third quarter of 2005.
The scope of the audit will be broader than the annual affiliate audit.
In accordance with existing CPUC requirements, the California
Utilities' transactions with other Sempra Energy affiliates have been
audited by an independent auditing firm each year, with results
reported to the CPUC, and there have been no material adverse findings
in those audits.
63
NOTE 10. COMMITMENTS AND CONTINGENCIES
Natural Gas Contracts
SoCalGas buys natural gas under short-term and long-term contracts.
Short-term purchasesPurchases are from various Southwest U.S.
and Canadian suppliers and are primarily based on monthly
spot-
marketspot-market prices. SoCalGas transports natural gas primarily under
long-term firm pipeline capacity agreements that provide for annual
reservation charges, which are recovered in rates. SoCalGas has
commitments with pipeline companies for firm pipeline capacity under
contracts with pipeline
companies that expire at various dates through 2006.2007.
At December 31, 2001,2004, the future minimum payments under existing
natural gas contracts were:
- -----------------------------------------------------------------
Storage and
(Dollars in millions) Transportation Natural Gas
- -----------------------------------------------------------------
2002 $ 170 $ 444
2003 172 158
2004 174 --
2005 170 --
2006 92 --
----------------------------------
Total minimum payments $ 778 $ 602
- -----------------------------------------------------------------
Natural
(Dollars in millions) Transportation Gas Total
- -----------------------------------------------------------------------------
2005 $ 183 $ 738 $ 921
2006 104 19 123
2007 2 3 5
2008 -- 3 3
2009 -- 2 2
Thereafter -- -- --
-------------------------------------------
Total minimum payments $ 289 $ 765 $ 1,054
- -----------------------------------------------------------------------------
Total payments under natural gas contracts were $2.1$2.3 billion in 2001, $1.42004,
$1.8 billion in 2000,2003 and $1.1$1.2 billion in 1999.2002.
Leases
PE and SoCalGas have operating leases on real and personal property
expiring at various dates from 20022005 to 2030. Certain leases on office
facilities contain escalation clauses requiring annual increases in
rent ranging from 4 percent to 75 percent. The rentals payable under
these leases are determined on both fixed and percentage bases, and
most leases contain extension options which are exercisable by PE or SoCalGas.the
companies.
64
At December 31, 2001,2004, the minimum rental commitments payable in future
years under all noncancellable leases were:were as follows:
- -----------------------------------------------------------------
(Dollars in millions) PE SoCalGas
- -----------------------------------------------------------------
20022005 $ 4256 $ 30
2003 42 30
2004 43
31
20052006 56 43
30
2006 44 312007 59 46
2008 60 46
2009 60 46
Thereafter 217 172
- -----------------------------------------------------------------98 91
---------------------
Total future rental commitmentcommitments $ 431389 $ 324315
- -----------------------------------------------------------------
In connection with the quasi-reorganization described in Note 2,1, PE
recorded liabilities of $102 million to adjust to fair value the
operating leases related to its headquarters and other facilities at
December 31, 1992. The remaining amount of these liabilities was $49$30
million at December 31, 2001.2004. These leases are included in the above
table.
PE's renttable at the amounts provided in the lease.
Rent expense for operating leases totaled $51$57 million in 2001, $552004, $56
million in 20002003 and $52$54 million in 1999,2002, which included rent expense
for SoCalGas of $39$44 million, $41$43 million and $39$42 million, respectively.
Guarantees
As of December 31, 2004, SoCalGas did not have any outstanding
guarantees.
Environmental Issues
The company's operations are subject to federal, state and local
environmental laws and regulations governing hazardous wastes, air and
water quality, land use, solid waste disposal and the protection of
wildlife. As applicable, appropriate and relevant, these laws and
regulations require that the company investigate and remediate the
effects of the release or disposal of materials at sites associated
with past and present operations, including sites at which the company
has been identified as a Potentially Responsible Party (PRP) under the
federal Superfund laws and comparable state laws. The company is
required to obtain numerous governmental permits, licenses and other
approvals to construct facilities and operate its businesses.
Additionally, to comply with these legal requirements, it must spend
significant sums on environmental monitoring, pollution control
equipment and emissions fees. In addition, existing environmental
regulations could be revised or reinterpreted and other new laws and
regulations could be adopted or become applicable to the company and
its facilities. Costs incurred to operate the facilities in compliance
with these laws and regulations generally have been recovered in
customer rates.
Costs thatSignificant costs incurred to mitigate or prevent future environmental65
contamination or extend the life, increase the capacity or improve the
safety or efficiency of property utilized in current operations are
capitalized. The company's capital expenditures to comply with
environmental laws and regulations were $2 million in 2004, $6 million
in 2003 and $4 million in 2001, $1 million in 2000 and $1
million in 1999. The increase in 2001 is due to purchases of
endangered species habitat land to mitigate the impact of a new
natural gas transmission line and the installation of air quality-
control equipment at a compressor station and at various storage
fields.2002. The cost of compliance with these
regulations over the next five years is not expected to be significant.
Costs that relate to current operations or an existing condition caused
by past operations are generally recorded as a regulatory asset due to
the assurance that these costs will be recovered in rates.
In
1994, the CPUC approved the Hazardous Waste Collaborative Memorandum
account, allowing California's energy utilities to recover their
hazardous waste cleanup costs, including those related to Superfund
sites or similar sites requiring cleanup. Recovery of 90 percent of
hazardous waste cleanup costs and related third-party litigation costs
and 70 percent of the related insurance-litigation expenses is
permitted. In addition, the company has the opportunity to retain a
percentage of any insurance recoveries to offset the 10 percent of
costs not recovered in rates.
The environmental issues currently facing the company or resolved
during the latest three-year periodlast three years include investigation and remediation of
its manufactured-gas sites (18(27 completed as of December 31, 20012004 and 2415
to be completed), and cleanup of third-party waste-
disposalwaste-disposal sites used
by the company, which has been identified as a Potentially Responsible PartyPRP (investigations and
remediations are continuing).
Environmental liabilities are recorded when the company's liability is
probable and the costs are reasonably estimable. In many cases,
however, investigations are not yet at a stage where the company has
been able to determine whether it is liable or, if the liability is
probable, to reasonably estimate the amount or range of amounts of the
cost or certain components thereof. Estimates of the company's
liability are further subject to other uncertainties, such as the
nature and extent of site contamination, evolving remediation standards
and imprecise engineering evaluations. The accruals are reviewed
periodically and, as investigations and remediation proceed,
adjustments are made as necessary. Costs of future expenditures for
environmental remediation obligations are not discounted to their
present value. At December 31, 2001,2004, the company's accrued liability
for environmental matters was $55$41.9 million, of which approximately $53$40.5 million wasis
related to manufactured-gas sites, and $2$0.9 million to waste-disposal sites
used by the company (which has been identified as a Potentially Responsible Party). ThePRP) and $0.5
million to other hazardous waste sites. These accruals for the
manufactured-gas and waste-disposal sites are expected to
be paid ratably over the next fivethree years.
There are no circumstances currently
known to management that would require adjustment to this accrual.
Litigation
Lawsuits filed in 2000 and currently consolidated in San Diego
Superior Court seek class-action certification and allege that
Sempra Energy, SoCalGas, SDG&E and El Paso Energy Corp. acted to
drive up the price of natural gas for Californians by agreeing to
stop a pipeline project that would have brought new and less
expensive natural gas supplies into California. Management believes
the allegations are without merit.Legal Proceedings
Except for the mattermatters referred to above,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. At December 31, 2004, the company had
accrued approximately $89 million to provide for the costs of legal
proceedings, of which $77 million related to cases arising from the
2000-2001 California energy crisis. Management believes that none of
these matters will not have afurther material adverse effect on the
company's financial condition or results of operations.
California Energy Crisis
In 2000 and 2001, California experienced a severe energy crisis
characterized by dramatic increases in the prices of natural gas. The
energy crisis has generated many, often duplicative, governmental
investigations, regulatory proceedings and lawsuits involving numerous
energy companies seeking recovery of tens of billions of dollars for
allegedly unlawful activities asserted to have caused or contributed to
66
the energy crisis. The material proceedings arising out of the energy
crisis that involve the company are 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 will pay approximately $1.6
billion to resolve these claims (including cases involving unrelated
claims not applicable to Sempra Energy, SoCalGas or SDG&E). The
proceeding against Sempra Energy and the California Utilities has not
been settled and continues to be litigated. 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. During the third quarter of
2004, the court denied motions for summary judgment in favor of Sempra
Energy and the California Utilities. The Court of Appeal has declined
to review the summary judgment denial and the companies have petitioned
for review by the California Supreme Court. Interim review pending a
final decision on the merits of the case is entirely at the discretion
of the California Supreme Court. On January 18, 2005, the judge stated
that pre-trial motions will be heard on June 3, 2005, and set a trial
date of September 2, 2005.
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. The Nevada Attorney
General's lawsuit remains pending.
The company is cooperating with an investigation being conducted by the
California Attorney General into possible anti-competitive behavior in
the natural gas and electricity markets during the 2000-2001 energy
crisis. In December 2004, several of the company's senior officers
testified at investigational hearings conducted by the California
Attorney General's Office. The company expects additional hearings to
take place in early 2005.
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, and included 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
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. Sempra Energy filed another motion to dismiss on plaintiffs'
amended complaint. After argument on November 29, 2004, the federal
court dismissed the Sierra Pacific case with prejudice. Plaintiffs have
filed a notice of appeal with the Ninth Circuit Court of Appeals.
67
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, Sempra Commodities, SoCalGas and
SDG&E.
CPUC 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
December 31, 2004, the cumulative amount of shareholder awards,
substantially all of which has been included in net income, was $56.9
million.
On November 16, 2004, the CPUC Administrative Law Judge assigned to the
investigation issued a proposed decision for consideration by the full
CPUC in the first phase of the investigation that was highly critical
of SoCalGas' natural gas purchase, sales, hedging and storage
activities and would find that SoCalGas exercised market power and
manipulated the natural gas market, significantly contributing to
natural gas price spikes that also increased electricity prices. The
proposed decision did not include any adverse findings or make any
adverse recommendations regarding SDG&E.
On December 16, 2004, the CPUC rejected the proposed decision by a 3-2
vote. The two commissioners who voted in favor of the proposed decision
were Commissioners Lynch and Wood, whose terms on the CPUC expired at
year end. It is now up to the remaining commissioners plus any new
appointees to determine whether to issue an alternate proposed
decision, hold additional hearings, or issue an order terminating the
investigation.
The CPUC may hold additional rounds of hearings to consider whether
other companies, including other California utilities, contributed to
the natural gas price spikes. No hearings have yet been scheduled.
Concentration of Credit Risk
The company maintains credit policies and systems to minimizemanage overall
credit risk. These policies include an evaluation of potential
counterparties' financial condition and an assignment of credit limits.
These credit limits are established based on risk and return
considerations under terms customarily available in the industry.
SoCalGas grants credit to its utility customers and counterparties, substantially68
all of whom are located in its service territory,territories, which coverscover most of
Southern California and a portion of Centralcentral California.
NOTE 12. REGULATORY MATTERS
Gas Industry Restructuring
The natural gas industry in California experienced an initial phase
of restructuring during the 1980s, but the CPUC did not make major
changes after the early 1990s. In January 1998, the CPUC released a
staff report initiating a project to assess the current market and
regulatory framework for California's natural gas industry. In July
1999, after hearings, the CPUC issued a decision stating which
natural gas regulatory changes it found most promising, encouraging
parties to submit settlements addressing those changes, and
providing for further hearings if necessary.
On December 11, 2001, the CPUC issued a decision adopting much
of a settlement that had been submitted in 2000 by SoCalGas and
approximately 30 other parties representing all segments of the gas
industry in Southern California, but which was opposed by other
parties. The CPUC decision adopts the following provisions: a system
for shippers to hold firm, tradable rights to capacity on SoCalGas'
major gas transmission lines with SoCalGas' shareholders at risk for
whether market demand for these rights will cover the cost of these
facilities; a further unbundling of SoCalGas' storage services
giving SoCalGas greater upward pricing flexibility (except for
storage service for core customers) but with increased shareholder
risk for whether market demand will cover storage costs; new
balancing services including separate core and noncore balancing
provisions; a reallocation among customer classes of the cost of
interstate pipeline capacity held by SoCalGas and an unbundling of
interstate capacity for gas marketers serving core customers; and
the elimination of noncore customers' option to obtain gas supply
service from SoCalGas. The CPUC modified the settlement to provide
increased protection against the exercise of market power by persons
who would acquire rights on the SoCalGas gas transmission system.
The CPUC also rejected certain aspects of the settlement that would
have provided more options for gas marketers serving core customers.
The CPUC is still considering the schedule for implementation
of these regulatory changes, but it is expected that most of the
changes will be implemented during 2002.
SoCalGas believes the decision will make gas service more
reliable, efficient and better tailored to the desires of customers.
The decision is not expected to negatively impact SoCalGas'
earnings.
Performance-Based Regulation (PBR)
To promote efficient operations and improved productivity and to
move away from reasonableness reviews and disallowances, the CPUC
has been directing utilities to use PBR. PBR has replaced the
general rate case and certain other regulatory proceedings for
SoCalGas. Under PBR, regulators require future income potential to
be tied to achieving or exceeding specific performance and
productivity goals, as well as cost reductions, rather than relying
solely on expanding utility plant in a market where a utility
already has a highly developed infrastructure.
SoCalGas' PBR mechanism was to have been in effect through
December 31, 2002, at which time the mechanism was to be updated.
That update was to include, among other things, a reexamination of
SoCalGas' reasonable costs of operation to be allowed in rates. The
PBR and Cost of Service (COS) cases for SoCalGas were both due to be
filed on December 21, 2001. However, the company's PBR/COS cases
were delayed by an October 10, 2001 CPUC decision such that the
resulting rates would be effective in 2004 instead of 2003. The
decision also denies SoCalGas' request to continue equal sharing
between ratepayers and shareholders of the estimated savings for the
merger discussed in Note 1 and, instead, orders that all of the
estimated 2003 merger savings go to ratepayers. Merger savings
allocable to SoCalGas ratepayers will be refunded through once-a-
year bill credits, as has been the case.
Key elements of the current mechanisms include an annual
indexing mechanism that adjusts rates by the inflation rate less a
productivity factor and other adjustments to accommodate major
unanticipated events, a sharing mechanism with customers that
applies to earnings that exceed the authorized rate of return on
rate base, rate refunds to customers if service quality deteriorates
or awards if service quality exceeds set standards, and a change in
authorized rate of return and customer rates if interest rates
change by more than a specified amount. The rate change is triggered
if the 12-month trailing average of actual market interest rates
increases or decreases by more than 150 basis points and is
forecasted to continue to vary by at least 150 basis points for the
next year. If these events occur, there would be an automatic
adjustment of rates for the change in the cost of capital according
to a formula which applies a percentage of the change to various
capital components.
Gas Cost Incentive Mechanism
The Gas Cost Incentive Mechanism (GCIM) evaluates SoCalGas' natural
gas purchases by comparing their cost with the average price of 30-
day firm spot supplies in the basins in which SoCalGas purchases
natural gas. 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. The CPUC approved the use of natural gas futures for
managing risk associated with the GCIM. SoCalGas enters into natural
gas futures contracts in the open market to mitigate risk and better
manage natural gas costs.
Shareholder awards associated with the GCIM normally are
recorded to SoCalGas' Purchased Gas Balancing Account after the
close of the GCIM period, which covers the utility's gas supply
operations for the twelve months ended March 31. These awards are
not included in earnings until receipt of CPUC approval. In May
2001, the CPUC approved a $10 million shareholder award for GCIM
Year Six ended March 31, 2000, and the CPUC is addressing whether
the GCIM should be extended and, if so, whether it should be with or
without modifications. The CPUC's Energy Division had previously
issued an evaluation report recommending the continuation of the
GCIM with modifications. In July 2001, SoCalGas, the CPUC's Office
of Ratepayer Advocates (ORA) and The Utility Reform Network (TURN),
a consumer-advocacy group, filed a Joint Motion for Adoption of a
settlement agreement to resolve all Phase 2 issues and to continue
the GCIM with modifications. On March 5, 2002, a proposed decision
was issued that, if adopted by the CPUC, would approve the
settlement agreement and continue the mechanism, applying the
modified GCIM beginning with the GCIM Year Seven (see below). A CPUC
decision is expected by the third quarter of 2002.
In June 2001, SoCalGas filed its annual GCIM application with
the CPUC requesting a shareholder award of $106 million for GCIM
Year Seven ended March 31, 2001. Notwithstanding this request the
July 2001 settlement agreement among SoCalGas, the ORA and TURN
would retroactively reduce the award request to $31 million. This
proceeding is separate from the Phase 2 proceeding discussed above
and final CPUC approval is not expected until early 2003.
Demand Side Management Awards
In recent years, the IOUs have participated in a CPUC program whereby
they could earn awards for operating and/or administering energy-
conservation efforts involving their retail customers. SoCalGas has
participated in these programs and has consistently achieved
significant earnings therefrom. As part of the CPUC's review of the
program, a draft decision is proposing that the program be reduced in
scope and that award potentials for the IOUs be eliminated. An
alternate proposal would maintain the award concept, but the potential
awards would probably be reduced. The CPUC is scheduled to review both
proposals at its March 21, 2002 meeting.
Biennial Cost Allocation Proceeding (BCAP)
Rates to recover the changes in the cost of natural gas
transportation services are determined in the BCAP. The BCAP adjusts
rates to reflect variances in customer demand from estimates
previously used in establishing customer natural gas transportation
rates. The mechanism substantially eliminates the effect on income
of variances in market demand and natural gas transportation costs.
SoCalGas filed its 2003 BCAP on September 21, 2001.
On April 20, 2000, the CPUC issued a decision on the 1999 BCAP,
adopting overall decreases in natural gas revenues of $210 million
for transportation rates effective June 1, 2000. There is a return
to 75/25 (customer/shareholder) balancing account treatment for
noncore transportation revenues, excluding certain transactions. In
addition, unbundled noncore storage revenues are balanced 50/50
between customers and shareholders. Since the decreases reflect
anticipated changes in corresponding costs, they have no effect on
net income.
Cost Of Capital
SoCalGas is authorized to earn a rate of return on common equity
(ROE) of 11.6 percent and a 9.49 percent return on rate base (ROR),
the same as in 2001 and 2000. These rates will continue to be
effective in until the next periodic review by the CPUC unless
interest-rate changes are large enough to trigger an automatic
adjustment prior thereto as discussed above under "Performance-Based
Regulation."
Utility Integration
On September 20, 2001 the CPUC approved Sempra Energy's request to
integrate the management teams of SoCalGas and SDG&E. The decision
retains the separate identities of each utility and is not a merger.
Instead, utility integration is a reorganization that consolidates
senior management functions of the two utilities and returns to the
utilities a significant portion of shared support services currently
provided by Sempra Energy's centralized corporate center. Once
implementation is completed, the integration is expected to result
in more efficient and effective operations.
In a related development, a CPUC draft decision would allow
SoCalGas and SDG&E to combine their natural gas procurement activities.
The CPUC is scheduled to act on the draft decision at its April 4, 2002
meeting.
CPUC Investigation of Energy-Utility Holding Companies
The CPUC has initiated an investigation into the relationship
between California's investor owned utilities (IOUs) and their
parent holding companies. Among the matters to be considered in the
investigation are utility dividend policies and practices and
obligations of the holding companies to provide financial support
for utility operations under the agreements with the CPUC permitting
the formation of the holding companies. On January 11, 2002, the
CPUC issued a decision to clarify under what circumstances, if any,
a holding company would be required to provide financial support to
its utility subsidiaries. The CPUC broadly determined that it would
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 cover their
utility subsidiaries' capital requirement, as the IOUs have
previously acknowledged in connection with the holding companies'
formations. On January 14, 2002, the CPUC ruled on jurisdictional
issues, deciding that the CPUC had jurisdiction to create the
holding company system and, therefore, retains jurisdiction to
enforce conditions to which the holding companies had agreed. The
company has filed to request rehearing on the issues.
NOTE 13.11. QUARTERLY FINANCIAL DATA (UNAUDITED)
QuarterQuarters ended
-----------------------------------------------------
Dollars(Dollars in millionsmillions) March 31 June 30 September 30 December 31
------------------------------------------------------ --------------------------------------------------------------------------------------
20012004
Operating revenues $ 1,5481,148 $ 927847 $ 561826 $ 6841,176
Operating expenses 1,480 864 489 613
----------------------------------------------------1,082 792 761 1,127
------------------------------------------------
Operating income $ 6866 $ 6355 $ 7265 $ 71
----------------------------------------------------49
------------------------------------------------
Net income $ 5059 $ 49 $ 5767 $ 5061
Dividends on preferred stock 1 1 1 1
----------------------------------------------------------------------------------------------------
Earnings applicable
to common shares $ 4958 $ 48 $ 5666 $ 49
====================================================
200060
- --------------------------------------------------------------------------------------
2003
Operating revenues $ 6981,008 $ 630820 $ 722794 $ 804922
Operating expenses 632 565 652 742
----------------------------------------------------940 768 738 861
------------------------------------------------
Operating income $ 6668 $ 6552 $ 7056 $ 62
----------------------------------------------------61
------------------------------------------------
Net income $ 5258 $ 4936 $ 52 $ 5875
Dividends on preferred stock 1 1 1 1
----------------------------------------------------------------------------------------------------
Earnings applicable
to common shares $ 5157 $ 4835 $ 51 $ 57
====================================================
The sum of the quarterly amounts does not necessarily equal the annual totals due to
rounding.74
- --------------------------------------------------------------------------------------
Operating revenues and expenses in the fourth quarter of 2004 included
the favorable impact of the final cost of service decision and
operating expenses included litigation costs recorded in the fourth
quarter.
Operating revenues in the third quarter of 2003 included the
recognition of $48 million of natural gas procurement awards. The
after-tax impact to net income was $29 million. Additionally, operating
expenses in the third quarter of 2003 were impacted by a $55 million
before-tax charge for litigation and for losses associated with a
sublease of portions of the SoCalGas headquarters building. The after-
tax impact was $32 million.
Net income in the fourth quarter of 2003 included $29 million related
to the favorable resolution of income tax issues.
69
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA --
Southern California Gas Company
REPORT OF INDEPENDENT AUDITORS' REPORTREGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Southern California Gas
Company:
We have audited the accompanying consolidated balance sheets of
Southern California Gas Company and subsidiaries (the "Company") as of
December 31, 20012004 and 2000,2003, and the related consolidated statements of
consolidated income, shareholders' equity and cash flows and changes in shareholders' equity for each of the three years
in the period ended December 31, 2001.2004. These financial statements are
the responsibility of the Company's management. Our responsibility is
to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with auditingthe standards generally accepted inof the United States of America.Public
Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly,
in all material respects, the financial position of Southern
California Gasthe Company and subsidiaries as of
December 31, 20012004 and 2000,2003, and the results of theirits operations and theirits
cash flows for each of the three years in the period ended December 31,
2001,2004, in conformity with accounting principles generally accepted in
the United States of America.
We have also audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the effectiveness
of the Company's internal control over financial reporting as of
December 31, 2004, based on the criteria established in Internal
Control-Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission and our report dated February
22, 2005 expressed an unqualified opinion on management's assessment of
the effectiveness of the Company's internal control over financial
reporting and an unqualified opinion on the effectiveness of the
Company's internal control over financial reporting.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
February 4, 2002 (March 5, 200222, 2005
70
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Southern California Gas
Company:
We have audited management's assessment, included in the accompanying
Management's Report on Internal Control over Financial Reporting, that
Southern California Gas Company and subsidiaries (the "Company")
maintained effective internal control over financial reporting as of
December 31, 2004, based on criteria established in Internal Control-
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. The Company's management is
responsible for maintaining effective internal control over financial
reporting and for its assessment of the effectiveness of internal
control over financial reporting. Our responsibility is to Note 12)express an
opinion on management's assessment and an opinion on the effectiveness
of the Company's internal control over financial reporting based on our
audit.
We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable
assurance about whether effective internal control over financial
reporting was maintained in all material respects. Our audit included
obtaining an understanding of internal control over financial
reporting, evaluating management's assessment, testing and evaluating
the design and operating effectiveness of internal control, and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis
for our opinions.
A company's internal control over financial reporting is a process
designed by, or under the supervision of, the company's principal
executive and principal financial officers, or persons performing
similar functions, and effected by the company's board of directors,
management, and other personnel to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally
accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1)
pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the
assets of the company; (2) provide reasonable assurance that
transactions are recorded as necessary to permit preparation of
financial statements in accordance with generally accepted accounting
principles, and that receipts and expenditures of the company are being
made only in accordance with authorizations of management and directors
of the company; and (3) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or
disposition of the company's assets that could have a material effect
on the financial statements.
Because of the inherent limitations of internal control over financial
reporting, including the possibility of collusion or improper
71
management override of controls, material misstatements due to error or
fraud may not be prevented or detected on a timely basis. Also,
projections of any evaluation of the effectiveness of the internal
control over financial reporting to future periods are subject to the
risk that the controls may become inadequate because of changes in
conditions, or that the degree of compliance with the policies or
procedures may deteriorate.
In our opinion, management's assessment that the Company maintained
effective internal control over financial reporting as of December 31,
2004, is fairly stated, in all material respects, based on the criteria
established in Internal Control-Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Also
in our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31,
2004, based on the criteria established in Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission.
We have also audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the consolidated
financial statements as of and for the year ended December 31, 2004 of
the Company and our report dated February 22, 2005 expressed an
unqualified opinion on those financial statements.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 22, 2005
72
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
Dollars(Dollars in millionsmillions)
Years ended December 31,
2001 2000 1999
------2004 2003 2002
------- ------- -------
Operating Revenues $3,716 $2,854 $2,569
------ ------ ------revenues $ 3,997 $ 3,544 $ 2,858
------- ------- -------
Operating Expensesexpenses
Cost of natural gas distributed 2,117 1,361 1,0322,283 1,830 1,192
Other operating expenses 792 695 738950 954 872
Depreciation 268 263 260255 289 276
Income taxes 165 173 179
Other157 142 183
Franchise fees and other taxes and franchise payments 101 96 92
------ ------ ------114 106 93
------- ------- -------
Total operating expenses 3,443 2,588 2,301
------ ------ ------3,759 3,321 2,616
------- ------- -------
Operating Income 273 266 268
------ ------ ------income 238 223 242
------- ------- -------
Other Incomeincome and (Deductions)(deductions)
Interest income 22 27 164 34 5
Regulatory interest (19) (12) (14)- net 9 3 (4)
Allowance for equity funds used during
construction 6 3 --
Taxes5 9 10
Income taxes on non-operating income (4) (10) (3)3 (8) 5
Gain on sale of partnership assets 15 -- --
Other - net (2) 7 (6) ------ ------ ------(1)
------- ------- -------
Total 334 32 15
(7)
------ ------ ------------- ------- -------
Interest Chargescharges
Long-term debt 63 68 7435 41 40
Other 5 7 8 (12)7
Allowance for borrowed funds used during
construction (2) (2) (2)(1) (3) (3)
------- ------ ------------- -------
Total 68 74 60
------ ------ ------39 45 44
------- ------- -------
Net Income 208 207 201income 233 210 213
Preferred Dividend Requirementsdividend requirements 1 1 1
------ ------ ------------- ------- -------
Earnings Applicableapplicable to Common Sharescommon shares $ 207232 $ 206209 $ 200
====== ====== ======212
======= ======= =======
See notes to Consolidated Financial Statements.
73
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Dollars(Dollars in millionsmillions)
Balance at
December 31, 2001 2000
-------- --------December 31,
2004 2003
------------- ------------
ASSETS
Utility plant - at original cost $6,467 $6,314$ 7,254 $ 7,007
Accumulated depreciation (3,710) (3,557)
------ ------(2,863) (2,739)
------- -------
Utility plant - net 2,757 2,757
------ ------4,391 4,268
------- -------
Current assets:
Cash and cash equivalents 13 20534 32
Accounts receivable - trade 415 589673 509
Accounts and receivable - other 14 8313 36
Interest receivable 31 30
Due from unconsolidated affiliates -- 21422
Income taxes receivable -- 1
Deferred income taxes 62 7417 --
Regulatory assets arising from fixed-pricedfixed-price contracts
and other derivatives 103 --97 85
Other regulatory assets -- 24
Fixed-price contracts and other derivatives 59 --26 8
Inventories 42 6772 74
Other 4 80
------ ------10 9
------- -------
Total current assets 712 1,336
------ ------973 806
------- -------
Other assets:
Regulatory assets arising from fixed-pricedfixed-price contracts
and other derivatives 157 --52 148
Sundry 136 35
------ ------86 127
------- -------
Total other assets 293 35
------ ------138 275
------- -------
Total assets $3,762 $4,128
====== ======$ 5,502 $ 5,349
======= =======
See notes to Consolidated Financial Statements.
74
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Dollars(Dollars in millionsmillions)
Balance at
December 31, 2001 2000
-------- --------December 31,
2004 2003
------------- ------------
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock (100,000,000(100 million shares authorized;
91,300,00091 million shares outstanding) $ 835866 $ 835866
Retained earnings 470 453523 491
Accumulated other comprehensive income (loss) -- (1)
------ ------(4) (3)
------- -------
Total common equity 1,305 1,2871,385 1,354
Preferred stock 22 22
------ ------------- -------
Total shareholders' equity 1,327 1,309
Long term1,407 1,376
Long-term debt 579 821
------ ------864 762
------- -------
Total capitalization 1,906 2,130
------ ------2,271 2,138
------- -------
Current liabilities:
Short-term debt 5030 --
Accounts payable - trade 314 227
Accounts payable - other 65 44
Due to unconsolidated affiliates 55 55
Interest payable 10 18
Income taxes payable 63 --
Deferred income taxes -- 15
Regulatory balancing accounts - net 178 86
Fixed-price contracts and other derivatives 97 86
Customer deposits 49 43
Current portion of long-term debt 100 120
Accounts payable - trade 160 368
Accounts payable - other 81 44
Due to unconsolidated affiliates 24 -- Regulatory balancing accounts - net 85 465
Income taxes payable 32 90
Interest payable 29 26
Regulatory liabilities 18 --
Fixed-price contracts and other derivatives 103 --175
Other 390 321
------ ------257 262
------- -------
Total current liabilities 1,072 1,434
------ ------1,118 1,011
------- -------
Deferred credits and other liabilities:
Customer advances for construction 24 1655 40
Postretirement benefits other than pensions 64 --
Deferred income taxes 183 240147 136
Deferred investment tax credits 50 5341 44
Regulatory liabilities 174 84arising from cost
of removal obligations 1,446 1,392
Other regulatory liabilities 67 181
Fixed-price contracts and other derivatives 162 --52 148
Deferred credits and other liabilities 191 171
------ ------241 259
------- -------
Total deferred credits and other liabilities 784 564
------ ------
Contingencies2,113 2,200
------- -------
Commitments and commitmentscontingencies (Note 11)10)
Total liabilities and shareholders' equity $3,762 $4,128
====== ======$ 5,502 $ 5,349
======= =======
See notes to Consolidated Financial Statements.
75
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
Dollars(Dollars in millionsmillions)
Years ended December 31,
2001 2000 1999
------ ------ ------2004 2003 2002
------- ------- -------
Cash Flows From Operating ActivitiesCASH FLOWS FROM OPERATING ACTIVITIES
Net Incomeincome $ 208233 $ 207210 $ 201213
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation 268 263 260255 289 276
Deferred income taxes and investment tax credits 9 (4) 133
(Increase) decrease(17) 44 23
Gain on sale of partnership assets (15) -- --
Changes in other assets (12) 13 22
Increase (decrease)1 (4) 12
Changes in other liabilities 12 12 (64)(24) (39) 8
Changes in working capital components:
Accounts receivable 244 (378) 154(144) (44) (67)
Interest receivable (1) (30) --
Fixed-price contracts and other derivatives 16 -- --(2) (2) 6
Inventories 25 11 (18)2 2 (34)
Other current assets 4 (75) 1 13 (4)
Accounts payable (171) 203 (18)107 36 (5)
Income taxes payable (58) 86 (26)62 42 (52)
Due to/from affiliates 5 (3) (83)- net (26) 37 12
Regulatory balancing accounts (380) 309 3693 (99) 80
Regulatory assets and liabilities 39 (2) (2)(23) (24) 1
Customer deposits 6 (64) 66
Other current liabilities 71 92 6
------ ------ ------(7) 18 (8)
------- ------- -------
Net cash provided by operating activities 280 734 602
------ ------ ------
Cash Flows501 385 527
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (311) (318) (331)
Affiliate loan 51 34 (86)
Net proceeds from Investing Activities
Capital expenditures (294) (198) (146)
Loan repaid by (paid to) affiliate 233 (132) (101)
Other - netsale of assets 7 5 --
21 (1)
------ ------ ------------- ------- -------
Net cash used in investing activities (61) (309) (248)
------ ------ ------
Cash Flows from Financing Activities
Dividends(253) (279) (417)
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid (191) (201) (279)(200) (200) (200)
Preferred dividends paid (1) (1) (1)
Issuance of long-term debt 100 500 250
Payments on long-term debt (270) (30) (75)(175) (395) (100)
Increase (decrease) in short-term debt 5030 -- --
------ ------ ------(50)
------- ------- -------
Net cash used in financing activities (411) (231) (354)
------ ------ ------(246) (96) (101)
------- ------- -------
Increase (decrease) in cash and cash equivalents (192) 194 --2 10 9
Cash and cash equivalents, January 1 205 11 11
------ ------ ------32 22 13
------- ------- -------
Cash and cash equivalents, December 31 $ 1334 $ 20532 $ 11
====== ====== ======
Supplemental Disclosure of Cash Flow Information:22
======= ======= =======
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized $ 6543 $ 7747 $ 77
====== ====== ======36
======= ======= =======
Income tax payments, net of refunds $ 216111 $ 10199 $ 100
====== ====== ======206
======= ======= =======
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING
AND FINANCING ACTIVITIES
Assets contributed by Sempra Energy $ -- $ 48 $ --
Liabilities assumed -- (18) --
------- ------- -------
Net assets contributed by Sempra Energy $ -- $ 30 $ --
======= ======= =======
See notes to Consolidated Financial Statements.
76
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
Years ended December 31, 2001, 20002004, 2003 and 1999
Dollars2002
(Dollars in millionsmillions)
Accumulated
Other Total
Comprehensive Preferred Common Retained Comprehensive Shareholders'
Income Stock Stock Earnings Income(Loss) Equity
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 19982001 $ 22 $ 835 $ 525470 $ 1,382-- $ 1,327
Net income/comprehensive income $ 201 201 201
Other comprehensive income (loss):
Available-for-sale securities 10 $ 10 10
Pension (4) (4) (4)
-----
Comprehensive income $ 207
Preferred stock dividends declared ===== (1) (1)
Common stock dividends declared (278) (278)
--------------------------------------------------------
Balance at December 31, 1999 22 835 447 6 1,310
Net income $ 207 207 207
Other comprehensive income (loss):
Available-for-sale securities (10) (10) (10)
Pension 3 3 3
-----
Comprehensive income $ 200213 213 213
=====
Preferred stock dividends declared (1) (1)
Common stock dividends declared (200) (200)
--------------------------------------------------------Capital contribution 1 1
- -------------------------------------------------------------------------------------------------------------
Balance at December 31, 20002002 22 835 453 (1) 1,309836 482 -- 1,340
Net income $ 208 208 208210 210 210
Other comprehensive income
(loss):
Other 1 1 1adjustment - pension (3) (3) (3)
-----
Comprehensive income $ 209207
=====
Preferred stock dividends declared (1) (1)
Common stock dividends declared (190) (190)
--------------------------------------------------------(200) (200)
Capital contribution 30 30
- -------------------------------------------------------------------------------------------------------------
Balance at December 31, 20012003 22 866 491 (3) 1,376
Net income $ 233 233 233
Other comprehensive income
adjustment - pension (1) (1) (1)
-----
Comprehensive income $ 232
=====
Preferred stock dividends declared (1) (1)
Common stock dividends declared (200) (200)
- -------------------------------------------------------------------------------------------------------------
Balance at December 31, 2004 $ 22 $ 835866 $ 470523 $ -- $1,327
==================================================================================================(4) $ 1,407
=============================================================================================================
See notes to Consolidated Financial Statements.
77
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SOUTHERN CALIFORNIA GAS COMPANY
The following notes to Consolidated Financial Statements of
Pacific Enterprises are incorporated herein by reference insofar
as they relate to Southern California Gas Company:
Note 1 - Business Combination
Note 2 - Significant Accounting Policies
Note 32 - Short-term Borrowings
Note 43 - Long-term Debtdebt
Note 75 - Employee Benefit Plans
Note 6 - Stock-based Compensation
Note 87 - Financial Instruments
Note 119 - Regulatory Matters
Note 10 - Commitments and Contingencies
Note 12 - Regulatory Matters
The following additional notes apply only to Southern California Gas
Company:
NOTE 5.4. INCOME TAXES
The reconciliation of the statutory federal income tax rate to the
effective income tax rate is as follows:
Years ended December 31,
2001 2000 19992004 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 5.3 5.6 6.85.2 6.1 5.1
State income taxes - net of
federal income tax benefit 6.7 6.8 7.35.8 5.9 7.0
Tax credits (0.7) (0.8) (0.7) (0.6)(0.8)
Settlement of Internal Revenue Service audit -- (3.1) --
Equity AFUDC (3.7) (1.0) (1.0)
Other, - net (1.4)(1.8) (0.4) 0.2
(1.0)
----------------------------------------------------------
Effective income tax rate 44.8% 46.9% 47.5%39.8% 41.7% 45.5%
- -----------------------------------------------------------------------------------------------------------------------------------------
78
The components of income tax expense are as follows:
Years ended December 31,
(Dollars in millions) 2001 2000 19992004 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------------
Current:
Federal $ 126127 $ 14476 $ 36117
State 34 42 13
------------------------------44 30 38
------------------------
Total 160 186 49
------------------------------171 106 155
------------------------
Deferred:
Federal 8 - 112(3) 42 24
State 4 (1) 24
------------------------------(11) 5 2
------------------------
Total 12 (1) 136
------------------------------(14) 47 26
------------------------
Deferred investment tax credits - net (3) (2) (3) ------------------------------(3)
------------------------
Total income tax expense $ 169154 $ 183150 $ 182178
- ------------------------------------------------------------------
Federal---------------------------------------------------------------------
On the Statements of Consolidated Income, federal and state income
taxes are allocated between operating income and other income. SoCalGas
is included in the consolidated income tax return of Sempra Energy and
is allocated income tax expense from Sempra Energy in an amount equal
to that which would result from filingSoCalGas' having always filed a
separate return.79
Accumulated deferred income taxes at December 31 result fromrelate to the
following:
(Dollars in millions) 2001 20002004 2003
- ----------------------------------------------------------------------------------------------------------------------------------------
Deferred Tax Liabilities:tax liabilities:
Differences in financial and
tax bases of utility plant $ 263268 $ 342273
Regulatory balancing accounts 56 1150 76
Global settlement -- (1)
Loss on reacquired debt 18 17
Other 20 19
------------------------------4 1
--------------------
Total deferred tax liabilities 339 372
------------------------------340 366
--------------------
Deferred Tax Assets:tax assets:
Investment tax credits 35 3829 31
Postretirement benefits 40 45
Deferred compensation 15 14
State income taxes 23 19
Workers compensation 21 20
Contingent liabilities 79 82
Other deferred liabilities 174 142
Other 9 26
------------------------------3 4
--------------------
Total deferred tax assets 218 206
------------------------------210 215
--------------------
Net deferred income tax liability $ 121130 $ 166151
- ----------------------------------------------------------------------------------------------------------------------------------------
The net deferred income tax liability is recorded on the Consolidated
Balance Sheets at December 31 as follows:
(Dollars in millions) 2001 20002004 2003
- ----------------------------------------------------------------------------------------------------------------------------------------
Current asset(asset) liability $ (62)(17) $ (74)15
Noncurrent liability 183 240
- ------------------------------------------------------------------147 136
--------------------
Total $ 121130 $ 166151
- ----------------------------------------------------------------------------------------------------------------------------------------
NOTE 6.5. EMPLOYEE BENEFIT PLANS
Pension and Other Postretirement Benefits
The following tables providepresent separate data for SoCalGas related to
employee benefit plan information in PE's Note 5.
December 31 is the measurement date for the pension and other
postretirement benefit plans. The following table provides a
reconciliation of the changes in the plans' projected benefit obligations
andduring the latest two years, the fair value of assets over the two
years, and a statement of
the funded status as of eachthe latest two year end:ends:
80
- ---------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
--------------------------------------------------------------- -----------------------
(Dollars in millions) 2001 2000 2001 20002004 2003 2004 2003
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Weighted-Average Assumptions
as of December 31:
Discount rate 7.25% 7.25%(1) 7.25% 7.25%
Expected return on plan assets 8.00% 8.00% 8.00% 8.00%
Rate of compensation increase 5.00% 5.00% 5.00% 5.00%
Cost trend of covered
health care charges - - 7.25%(2) 7.50%(2)
Change in Benefit Obligation:CHANGE IN PROJECTED BENEFIT OBLIGATION:
Net benefit obligation at January 1 $1,125 $1,057 $ 4151,551 $ 4081,368 $ 820 $ 682
Service cost 25 23 9 830 27 17 15
Interest cost 7893 90 43 47
Actuarial loss (gain) 84 32 28
Actuarial (gain)loss (46) 79 23 (17)
Curtailments - (4) - 4
Special termination benefits - 34 -172 (74) 103
Transfer of liability from Sempra Energy 2 Benefits paid (71) (148) (22) (18)
-----------------------------------------------6 -- --
Benefit payments (135) (112) (34) (27)
---------------------------------------------
Net benefit obligation at December 31 1,111 1,125 457 415
-----------------------------------------------
Change in Plan Assets:1,625 1,551 772 820
---------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at January 1 1,682 1,971 434 4631,473 1,289 471 370
Actual return on plan assets (162) (141) (33) (23)176 294 53 83
Employer contributions - - 13 10-- 2 42 45
Transfer of assets (3) 3 - -from Sempra Energy 2 Benefits paid (71) (148) (22) (18)
------------------------------------------------- -- --
Benefit payments (135) (112) (34) (27)
---------------------------------------------
Fair value of plan assets at December 31 1,452 1,682 392 434
-----------------------------------------------
Plan assets1,516 1,473 532 471
---------------------------------------------
Benefit obligation, net of benefit
obligationplan assets
at December 31 341 557 (65) 19(109) (78) (240) (349)
Unrecognized net actuarial gain (322) (591) (23) (116)loss 74 71 176 277
Unrecognized prior service cost 35 38 - -65 71 -- --
Unrecognized net transition obligation 2 2 88 96
------------------------------------------------- 1 -- 72 *
---------------------------------------------
Net recorded asset (liability)
at December 31 $ 5630 $ 665 $ (64) $ --
- $ (1)
- ---------------------------------------------------------------------------------
(1) Discount rate decreased from 7.75% to 7.25%, effective March 1, 2000.
(2) Decreasing to ultimate trend of 6.50% in 2004.
(3) To reflect transfer of plan assets and liability to Sempra Energy.-----------------------------------------------------------------------------------------
* Prior to 2004, the company's net transition obligation was recorded
at the company's parent, Pacific Enterprises.
The following table provides the amounts recognized on the Consolidated
Balance Sheets (under "sundry" and under "postretirement benefits other
than pensions") at December 31:
- ------------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
------------------------------------------------------------- -----------------------
(Dollars in millions) 2001 2000 2001 20002004 2003 2004 2003
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Prepaid benefit cost $ 6746 $ 15 - -78 $ -- $ --
Accrued benefit cost (11) (9) - $ (1)(16) (13) (64) --
Additional minimum liability (2) (4) - -
Intangible asset 1 1 - -(7) (6) -- --
Accumulated other comprehensive
income pre-tax 1 3 - -
- ------------------------------------------------------------------------------------(pretax) 7 6 -- --
-------------------------------------------
Net recorded asset(liability)asset (liability) $ 5630 $ 665 $ (64) $ --
- $ (1)
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------
The following table provides the components of net periodic
benefit cost for the plans:
Other
Pension Benefits Postretirement Benefits
(Dollars in millions) -----------------------------------------------
For the years ended December 31 2001 2000 1999 2001 2000 1999
- ---------------------------------------------------------------------------------
Service cost $ 25 $ 23 $ 28 $ 9 $ 8 $ 11
Interest cost 78 84 77 32 28 30
Expected return on assets (129) (131) (112) (34) (32) (27)
Amortization of:
Transition obligation 1 1 1 8 9 9
Prior service cost 3 4 4 -- -- --
Actuarial gain (28) (29) (14) (3) (8) --
Special termination benefits -- 33 -- -- 7 --
Regulatory adjustment 51 18 17 29 28 24
-----------------------------------------------
Total net periodic benefit cost $ 1 $ 3 $ 1 $ 41 $ 40 $ 47
- ---------------------------------------------------------------------------------
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A one-percent change in
assumed health care cost trend rates would have the following effects:
- -----------------------------------------------------------------------
(Dollars in millions) 1% Increase 1% Decrease
- -----------------------------------------------------------------------
Effect on total of service and interest cost
components of net periodic postretirement
health care benefit cost $ 8 $ (6)
Effect on the health care component of the
accumulated other postretirement benefit $76 $(60)
obligation
- -----------------------------------------------------------------------
Except for one nonqualified, unfunded retirement plan, all pension
plans had plan assets in excess of accumulated benefit obligations.
For that one plan the projected benefit obligation and accumulated
benefit obligation were $13 million and $12 million, respectively, as
of81
NOTE 8. PREFERRED STOCK
December 31,
2001, and $16 million and $12 million, respectively,
as of December 31, 2000.
Other postretirement benefits include retiree life insurance,
medical benefits for retirees and their spouses, and Medicare Part B
reimbursement for certain retirees.
NOTE 10. PREFERRED STOCK AND DIVIDEND RESTRICTIONS2004 2003
- -----------------------------------------------------------------
December 31,
(Dollars in------------------------------------------------------------------
(in millions) 2001 2000
- -----------------------------------------------------------------
$25 par value, authorized 1,000,000 shares
6% Series, 79,011 shares outstanding $ 3 $ 3
6% Series A, 783,032 shares outstanding 19 19
Without par value, authorized 10,000,000 shares - --- --
---------------
Total preferred stock $ 22 $ 22
- -----------------------------------------------------------------
None of SoCalGas' preferred stock is subject to mandatory redemption
or callable. All series have one vote
per share and cumulative preferences as to dividends, and have a
liquidation value of $25 per share plus any unpaid dividends.
In addition, the 6% Series preferred
stock would also share pro rata with common stock in the remaining
assets.
Dividend Restrictions
CPUC regulation of SoCalGas' capital structure limits to $280
million the portion of the company's December 31, 2001 retained
earnings that is available for dividends.
NOTE 13.11. QUARTERLY FINANCIAL DATA (UNAUDITED)
QuarterQuarters ended
----------------------------------------------------
Dollars(Dollars in millionsmillions) March 31 June 30 September 30 December 31
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------
20012004
Operating revenues $ 1,5481,148 $ 927847 $ 561826 $ 6811,176
Operating expenses 1,480 862 488 614
--------------------------------------------------1,080 792 759 1,128
------------------------------------------------
Operating income $ 68 $ 65 $ 7355 $ 67 --------------------------------------------------$ 48
------------------------------------------------
Net income $ 56 $ 51 $ 4868 $ 57 $ 5258
Dividends on preferred stock -- 1 -- --
--------------------------------------------------------------------------------------------------
Earnings applicable
to common shares $ 5156 $ 4750 $ 5768 $ 52
==================================================
200058
- --------------------------------------------------------------------------------------
2003
Operating revenues $ 6981,008 $ 630820 $ 722794 $ 804922
Operating expenses 632 563 653 740
--------------------------------------------------938 772 736 875
-----------------------------------------------
Operating income $ 6670 $ 6748 $ 6958 $ 64
--------------------------------------------------47
------------------------------------------------
Net income $ 5058 $ 4838 $ 53 $ 5661
Dividends on preferred stock -- 1 -- --
--------------------------------------------------------------------------------------------------
Earnings applicable
to common shares $ 5058 $ 4737 $ 53 $ 56
==================================================
The sum of the quarterly amounts does not necessarily equal the annual totals due to
rounding.61
- --------------------------------------------------------------------------------------
Operating revenues and expenses in the fourth quarter of 2004 included
the favorable impact of the final cost of service decision and
operating expenses included litigation costs recorded in the fourth
quarter.
Operating revenues in the third quarter of 2003 included the
recognition of $48 million of natural gas procurement awards. The
82
after-tax impact to net income was $29 million. Additionally, operating
expenses in the third quarter of 2003 were impacted by a $55 million
before-tax charge for litigation and for losses associated with a
sublease of portions of the SoCalGas headquarters building. The after-
tax impact was $32 million.
Net income in the fourth quarter of 2003 included $29 million related
to the favorable resolution of income tax issues.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSUREDISCLOSURES
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures - Management has
established disclosure controls and procedures to ensure that material
information relating to the company and its consolidated subsidiaries
is made known to the officers who certify the company's financial
reports and to other members of senior management and the Board of
Directors. In designing and evaluating these controls and procedures,
management recognizes that any system of controls and procedures, no
matter how well designed and operated, can provide only reasonable
assurance of achieving the desired objectives and necessarily applies
judgment in evaluating the cost-benefit relationship of other possible
controls and procedures.
Based on their evaluation as of December 31, 2004, the principal
executive officer and principal financial officer of the company have
concluded that the company's disclosure controls and procedures (as
defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange
Act of 1934) are effective, at the reasonable assurance level, to
ensure that the information required to be disclosed by the company in
the reports that it files or submits under the Securities Exchange Act
of 1934 is recorded, processed, summarized and reported within the time
periods specified by Securities and Exchange Commission rules and
forms.
Management's Report on Internal Control Over Financial Reporting -
Company management is responsible for establishing and maintaining
adequate internal control over financial reporting, as defined in
Exchange Act Rule 13a-15(f). Under the supervision and with the
participation of company management, including the principal executive
officer and principal financial officer, the company conducted an
evaluation of the effectiveness of its internal control over financial
reporting based on the framework in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. Based on the company's evaluation under the
framework in Internal Control - Integrated Framework, management
concluded that the company's internal control over financial reporting
was effective as of December 31, 2004. Management's assessment of the
effectiveness of internal control over financial reporting as of
December 31, 2004 has been audited by Deloitte & Touche LLP, an
independent registered public accounting firm, as stated in its report,
which is included herein.
83
ITEM 9B. OTHER INFORMATION
In February 2005, Sempra Energy entered into a severance pay agreement
with each executive officer of Pacific Enterprises (other than Stephen
L. Baum and Neal E. Schmale whose continuing employment and employment-
related agreements have been previously filed with the Securities and
Exchange Commission) and each executive officer of SoCalGas to replace
the previously reported similar agreements. The agreements are for an
initial term of three years and are subject to automatic one year
extensions on each anniversary of the effective date (commencing with
the second anniversary) unless Sempra Energy or the executive elects not
to extend the term.
The agreements provide severance benefits to the executive in the event
that Sempra Energy or its subsidiaries terminates the executive's
employment (other than for cause, death or disability) or the executive
does so for good reason.
Severance benefits under the agreements vary with the executive's
position and include (i) a lump sum cash severance payment varying from
50% to 100% of the sum of the executive's annual base salary plus the
greater of the executive's average annual bonus or average annual target
bonus for the two years prior to termination; (ii) continuation of
health insurance benefits for a period varying from six months to one
year; and (iii) financial planning and outplacement services for a
period varying from 18 months to two years. If the termination were to
occur within two years after a change in control of the company, (i) the
lump sum cash severance payment would be multiplied by two; (ii) an
additional lump sum payment would be paid equal to the pro rata portion
for the year of termination of the target amount payable under any
annual incentive compensation award for that year or, if greater, the
average of the three highest gross annual bonus awards paid to the
executive in the five years preceding the year of termination; (iii) all
equity-based incentive compensation awards would immediately vest and
become exercisable or payable and any restrictions on the awards would
automatically lapse; (iv) a lump sum cash payment would be made equal to
the present value of the executive's benefits under supplemental
executive retirement plans calculated on the basis of the greater of
actual years of service or years of service that would have been
completed upon attaining age 62 and applying certain early retirement
factors; (v) life, disability, accident and health insurance benefits
would be continued for a period varying from one year to two years; and
(vi) financial planning and outplacement services would be provided for
a period varying from two years to three years.
The agreements also provide that if the terminated executive agrees to
provide consulting services for two years and abide by certain covenants
regarding non-solicitation of employees and information confidentiality,
the executive would receive (i) an additional lump sum payment equal to
the executive's annual base salary and the greater of the executive's
target bonus for the year of termination or the average of the two or
three highest gross annual bonus awards paid to the executive in the
five years prior to termination and (ii) health insurance benefits would
be continued for an additional one year.
84
The agreements also provide for a gross-up payment to offset the effects
of any excise tax imposed on the executive under Section 4999 of the
Internal Revenue Code.
Good reason is defined in the agreements to include the assignment to
the executive of duties materially inconsistent with those appropriate
to a senior executive of Sempra Energy and its subsidiaries; a material
reduction in the executive's overall standing and responsibilities
within Sempra Energy and its subsidiaries; and a material reduction in
the executive's annualized compensation and benefit opportunities other
than across-the-board reductions affecting all similarly situated
executives of comparable rank. Following a change in control, good
reason is defined to include an adverse change in the executive's title,
authority, duties, responsibilities or reporting lines; reduction in the
executive's annualized compensation opportunities other than across-the-
board reductions of less than 10% similarly affecting all similarly
situated executives of comparable rank; relocation of the executive's
principal place of employment by more than 30 miles; and a substantial
increase in business travel obligations. A change in control is defined
to include the acquisition by one person or group of 20% or more of the
voting power of Sempra Energy's shares; the election of a new majority
of the board of Sempra Energy comprised of individuals who are not
recommended for election by two-thirds of the current directors or
successors to the current directors who were so recommended for
election; certain mergers, consolidations or sales of assets that result
in the shareholders of Sempra Energy owning less than 60% of the voting
power of Sempra Energy or of the surviving entity or its parent; and
approval by shareholders of the liquidation or dissolution of the
company.
85
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required on Identification of Directors is incorporated
by reference from "Election of Directors" in the Information Statement
prepared for the May 20022005 annual meeting of shareholders. The
information required on the company'scompanies' executive officers is set forth
below.
EXECUTIVE OFFICERS OF THE REGISTRANT
Name Age* PositionsPosition
- -------------------------------------------------------------------
Pacific Enterprises --
Stephen L. Baum 6063 Chairman, Chief Executive
Officer and President
John R. Light 60M. Javade Chaudhri 52 Executive Vice President and
General Counsel
Neal E. Schmale 5558 Executive Vice President and
Chief Financial Officer
Frank H. Ault 5760 Senior Vice President and
Controller
Charles A. McMonagle 5154 Vice President and Treasurer
Thomas C. Sanger 5861 Corporate Secretary
Southern California Gas Company --
Edwin A. Guiles 5255 Chairman and Chief Executive
Officer
Debra L. Reed 4548 President and Chief Operating
Officer
Steven D. Davis 48 Senior Vice President, External
Relations and Chief Financial
Officer
Steven D. Davis 45 Senior Vice President, Customer
Service and External Relations
Terry M. Fleskes 45 Vice President and Controller
Margot A. Kyd 4851 Senior Vice President, Corporate
Business Solutions
Roy M. Rawlings 57 Senior Vice President,
Distribution Operations
William L. Reed 4952 Senior Vice President, Regulatory
Affairsand Strategic Planning
Anne S. Smith 51 Senior Vice President, Customer
Service
Lee M. Stewart 5659 Senior Vice President, Gas
Transmission
Terry M. Fleskes 48 Vice President and Controller
* As of December 31, 2001.2004.
86
Each Executive Officer has been an officer or employee of Sempra Energy
or one of its subsidiaries for more than five years, with the exception
of Mssrs. Light and Schmale.Mr. Chaudhri. Prior to joining the company in 1998,2003, Mr. LightChaudhri was
a partner in the law firmSenior Vice President and General Counsel of Latham & Watkins.
Prior to joining the company in 1997, Mr. Schmale was Chief Financial
Officer of Unocal Corporation.Gateway, Inc. Each
executive officer atof Southern California Gas Company holds the same
position at San Diego Gas & Electric Company.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated by reference from
"Election of Directors" and "Executive Compensation" in the Information
Statement prepared for the May 20022005 annual meeting of shareholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
The security ownership information required by Item 12 is incorporated
by reference from "Election of Directors""Share Ownership" in the Information Statement
prepared for the May 20022005 annual meeting of shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information regarding principal accountant fees and services as
required by Item 14 is incorporated by reference from "Proposal 3:
Ratification of Independent Auditors" in the Information Statement
prepared for the May 2005 annual meeting of shareholders.
87
PART IV
ITEM 14.15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial statements
Page in
This Report
Reports of Independent Auditors' ReportRegistered Public Accounting
Firm for Pacific Enterprises . . . . . . . 24
Pacific Enterprises Statements of Consolidated Income
for the years ended December 31, 2001, 2000 and 1999 . . . . . . 25
Pacific Enterprises Consolidated Balance Sheets
at December 31, 2001 and 2000. . . . . . . . . . . . . . . . . . 26
Pacific Enterprises Statements of Consolidated Cash Flows
for the years ended December 31, 2001, 2000 and 1999 . . . . . . 28
Pacific Enterprises Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 2001, 2000 and 1999 . . . . . . . . . . . . . . . . 30
Pacific Enterprises Notes to Consolidated Financial Statements . . 31
Independent Auditor's Report for Southern California Gas Company. .56
Southern California Gas Company Statements of Consolidated Income
for the years ended December 31, 2001, 2000 and 1999 . . . . . . . 57
Southern California Gas Company Consolidated Balance Sheets at
December 31, 2001 and 2000. . . . . . . . . . . . . . . . . . . . 58
Southern California Gas Company27
Pacific Enterprises Statements of Consolidated Cash
FlowsIncome
for the years ended December 31, 2001, 20002004, 2003 and 19992002 . . . . 60
Southern California Gas Company Statements of. . 30
Pacific Enterprises Consolidated Changes in Shareholders' Equity for the years endedBalance Sheets
at December 31, 2001, 20002004 and 1999.2003. . . . . . . . . . . . . . . . . .61
Southern California Gas Company. 31
Pacific Enterprises Statements of Consolidated Cash Flows
for the years ended December 31, 2004, 2003 and 2002 . . . . . . 33
Pacific Enterprises Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 2004, 2003 and 2002 . . . . . . . . . . . . . . . . 34
Pacific Enterprises Notes to Consolidated
Financial Statements . . . . . . . . . . . . . . . . . . . . . . 35
Reports of Independent Registered Public Accounting
Firm for Southern California Gas Company . . . . . . 62. . . . . . 69
SoCalGas Statements of Consolidated Income for the years
ended December 31, 2004, 2003 and 2002 . . . . . . . . . . . . . 72
SoCalGas Consolidated Balance Sheets at December 31,
2004 and 2003. . . . . . . . . . . . . . . . . . . . . . . . . . 73
SoCalGas Statements of Consolidated Cash Flows for the
years ended December 31, 2004, 2003 and 2002 . . . . . . . . . . 75
SoCalGas Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 2004, 2003 and 2002 . . . . . . . . . . . . . . . . 76
SoCalGas Notes to Consolidated Financial Statements. . . . . . . . 77
2. Financial statement schedules
The following documentsdocument may be found in this report at the indicated
page numbers:number.
Schedule I--Condensed Financial Information of Parent. . . . . . . 72
Any other90
88
Other schedules for which provision is made in Regulation S-X are not
required under the instructions contained therein, are inapplicable or
the information is included in the Consolidated Financial Statements
and the notes thereto.
3. Exhibits
See Exhibit Index on page 7694 of this report.
(b) Reports on Form 8-K
There were noThe following reports on Form 8-K were filed after September 30, 2001.2004:
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.
Current Report on Form 8-K filed November 5, 2004, discussing the
current status of the California Utilities' Cost of Service
Proceedings, including a proposed decision and an alternate proposed
decision issued by CPUC commissioners on November 4, 2004.
Current Report on Form 8-K filed November 17, 2004, discussing the
current status of the Border Price Investigation, including the
proposed decision issued by the CPUC Administrative Law Judge on
November 16, 2004.
Current Report on Form 8-K filed December 3, 2004, discussing the
current status of the California Utilities' Cost of Service
Proceedings, including the CPUC decision issued on December 2, 2004.
Current Report on Form 8-K filed December 7, 2004, discussing and
filing as an exhibit the 2005 Deferred Compensation Plan.
Current Report on Form 8-K filed December 10, 2004, reporting the
closing of SoCalGas' public offering and sale of $100,000,000 of bonds
and filing as exhibits the underwriting agreement and pricing agreement
dated December 7, 2004, the supplemental indenture dated December 10,
2004, and the form of the bond.
Current Report on Form 8-K filed December 17, 2004, discussing the
current status of the Border Price Investigation.
Current Report on Form 8-K filed January 11, 2005, discussing the
current status of energy crisis litigation.
Current Report on Form 8-K filed January 18, 2005, discussing the
current status of energy crisis litigation.
Current Report on Form 8-K filed February 23, 2005, filing as an
exhibit Sempra Energy's press release of February 23, 2005, giving the
financial results for the three months ended December 31, 2004.
89
CONSENTS OF INDEPENDENT AUDITORS' CONSENTSREGISTERED PUBLIC ACCOUNTING FIRM AND REPORT ON
SCHEDULESCHEDULES
To the Board of Directors and Shareholders of Pacific Enterprises:
We consent to the incorporation by reference in Registration Statement
Numbers 2-96782, 33-26357, 2-66833, 2-96781, 33-21908 and 33-54055 on
Form S-8 and Registration Statement Numbers 33-24830, 333-52926 and 33-4433833-
44338 on Form S-3 of our reports dated February 22, 2005 relating to
the financial statements of Pacific Enterprises and management's report
on the effectiveness of our report dated
February 4, 2002 (March 5, 2002 as to Note 12), appearinginternal control over financial reporting,
incorporated by reference in this Annual Report on Form 10-K of Pacific
Enterprises for the year ended December 31, 2001.2004.
Our audits of the financial statements referred to in our
aforementioned report also included the financial statement schedule of
Pacific Enterprises, listed in Item 14.15. This financial statement
schedule is the responsibility of the Company's management. Our
responsibility is to express an opinion based on our audits. In our
opinion, such financial statement schedule, when considered in relation
to the basic financial statements taken as a whole, presentspresent fairly in
all material respects, the information set forth therein.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
March 15, 2002February 22, 2005
To the BoardsBoard of Directors and Shareholders of Southern California Gas
Company:
We consent to the incorporation by reference in Registration Statement
Numbers 333-70654, 333-45537, 33-51322, 33-53258, 33-59404 and 33-
5266333-52663
on Form S-3 of our reportreports dated February 4, 2002 (March 5, 2002
as22, 2005 relating to Note 12), appearingthe
financial statements of Southern California Gas Company and
management's report on the effectiveness of internal control over
financial reporting, incorporated by reference in thethis Annual Report on
Form 10-K of Southern California Gas Company for the year ended
December 31, 2001.2004.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
March 15, 2002February 22, 2005
90
Schedule I -- CONDENSED FINANCIAL INFORMATION OF PARENT
PACIFIC ENTERPRISES
Condensed Statements of Income
(Dollars in millions)
For the years ended December 31 2004 2003 2002
------ ------ ------
Interest income $ 13 $ 4 $ 6
Expenses, interest and income taxes 13 (4) 9
------ ------ ------
Income (loss) before subsidiary earnings -- 8 (3)
Subsidiary earnings 232 209 212
------ ------ ------
Earnings applicable to common shares $ 232 $ 217 $ 209
====== ====== ======
Condensed Balance Sheets
(Dollars in millions)
Balance at December 31 2004 2003
-------- --------
Assets:
Current assets $ 103 $ 104
Investment in subsidiary 1,386 1,354
Due from affiliates - long-term 396 356
Deferred charges and other assets 48 111
-------- --------
Total assets $ 1,933 $ 1,925
======== ========
Liabilities and Shareholders' Equity:
Due to affiliates $ 72 $ 66
Other current liabilities 10 10
-------- --------
Total current liabilities 82 76
Other long-term liabilities 37 152
Common equity 1,734 1,617
Preferred stock 80 80
-------- --------
Total liabilities and shareholders' equity $ 1,933 $ 1,925
======== ========
91
Schedule I (continued)
PACIFIC ENTERPRISES
Schedule 1
Condensed Financial Information of Parent
Condensed Statements of Income
(Dollars in millions)
Years ended December 31 2001 2000 1999
-------- -------- --------
Other income $ 23 $ 33 $ --
Expenses, interest and income taxes 28 32 20
------- -------- --------
Income (loss) before subsidiary earnings (5) 1 (20)
Subsidiary earnings 207 206 200
-------- -------- --------
Earnings applicable to common shares $ 202 $ 207 $ 180
======== ======== ========
Condensed Balance Sheets
(Dollars in millions)
Balance at December 31 2001 2000
-------- --------
Assets:
Current assets $ 55 $ 43
Investment in subsidiary 1,305 1,287
Due from affiliates - long-term 409 617
Deferred charges and other assets 102 117
-------- --------
Total Assets $ 1,871 $ 2,064
======== ========
Liabilities and Shareholders' Equity:
Due to affiliates $ 147 $ 364
Other current liabilities 30 32
-------- --------
Total current liabilities 177 396
Long-term liabilities 120 142
Common equity 1,494 1,446
Preferred stock 80 80
-------- --------
Total Liabilities and Shareholders' Equity $ 1,871 $ 2,064
======== ========
PACIFIC ENTERPRISES
Schedule 1 (continued)
Condensed Financial Information of Parent
Condensed Statements of Cash Flows
(Dollars in millions)
Years
For the years ended December 31 2001 2000 1999
------- ------- -------2004 2003 2002
------ ------ ------
Net cash provided by (used in)
operating activities $ 843 $ (96)(9) $ (120)
------- ------- -------
Dividends received from subsidiaries 190 200 278
Increase in investments and other assets -- -- (14)
------- ------- -------(5)
------ ------ ------
Cash flows provided by investing activities 190-
dividends received from subsidiaries 200 264
------- ------- -------
Decrease in short-term debt -- -- (43)200 200
------ ------ ------
Common dividends paid (190) (100)(200) (250) (100)
Preferred dividends paid (4) (4) (4)
Due to/from affiliates - net (39) 63 (91)
Other (4) -- -- ------- ------- ---------
------ ------ ------
Cash flows used in financing activities (198) (104) (147)
------- ------- -------
Decrease(243) (191) (195)
------ ------ ------
Change in cash and cash equivalents -- -- (3)--
Cash and cash equivalents, January 1 -- -- 3
------- ------- ---------
------ ------ ------
Cash and cash equivalents, December 31 $ -- $ -- $ --
======= ======= ============= ====== ======
92
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be
signed on its behalf by the undersigned, hereunto duly authorized.
PACIFIC ENTERPRISES
By: /s/ Stephen L. Baum
.
Stephen L. Baum
Chairman, President
and Chief Executive Officer
and President
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report is signed below by the following persons on behalf of the
Registrant in the capacities and on the dates indicated.
Name/Title Signature Date
Principal Executive Officer:
Stephen L. Baum
Chairman, President
and Chief Executive Officer and President /s/ Stephen L. Baum March 5, 2002February 23, 2005
Principal Financial Officer:
Neal E. Schmale
Executive Vice President and
Chief Financial Officer /s/ Neal E. Schmale March 5, 2002February 23, 2005
Principal Accounting Officer:
Frank H. Ault
Senior Vice President and
Controller /s/ Frank H. Ault March 5, 2002February 23, 2005
Directors:
Stephen L. Baum, Chairman /s/ Stephen L. Baum March 5, 2002
John R. Light,February 23, 2005
Frank H. Ault, Director /s/ John R. Light March 5, 2002Frank H. Ault February 23, 2005
Neal E. Schmale, Director /s/ Neal E. Schmale March 5, 2002
February 23, 2005
93
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be
signed on its behalf by the undersigned, hereunto duly authorized.
SOUTHERN CALIFORNIA GAS COMPANY
By: /s/ Edwin A. Guiles
.
Edwin A. Guiles
Chairman and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report is signed below by the following persons on behalf of the
Registrant in the capacities and on the dates indicated.
Name/Title Signature Date?
Principal Executive Officer:
Edwin A. Guiles
Chairman and
Chief Executive Officer /s/ Edwin A. Guiles March 7, 2002February 23, 2005
Principal Financial Officer:
Debra L. ReedSteven D. Davis
Sr. Vice President,
External Relations and
Chief Financial Officer /s/ Debra L. Reed March 7, 2002Steven D. Davis February 23, 2005
Principal Accounting Officer:
Terry M. Fleskes
Vice President and
Controller /s/ Terry M. Fleskes March 7, 2002February 23, 2005
Directors:
Edwin A. Guiles, Chairman /s/ Edwin A. Guiles March 7, 2002February 23, 2005
Debra L. Reed, Director /s/ Debra L. Reed March 7, 2002February 23, 2005
Frank H. Ault, Director /s/ Frank H. Ault March 7, 2002February 23, 2005
94
EXHIBIT INDEX
The Forms 8-K, 10-K and 10-Q referred to herein were filed under
Commission File Number 1-14201 (Sempra Energy), Commission File Number
1-40 (Pacific Enterprises) and/or Commission File Number 1-
14021-1402
(Southern California Gas Company).
Exhibit 3 -- By-Laws and Articles Of Incorporation
3.01 Articles of Incorporation of Pacific Enterprises (Pacific
Enterprises 1996 Form 10-K;10-K, Exhibit 3.01).
3.02 Restated Bylaws of Pacific Enterprises dated November 6, 2001.
(2001 Form 10-K, Exhibit 3.02).
3.03 Restated Articles of Incorporation of Southern California Gas
Company (Southern California Gas Company 1996 Form 10-K;10-K, Exhibit
3.01).
3.04 Restated Bylaws of Southern California Gas Company dated November
6, 2001. (2001 Form 10-K, Exhibit 3.04).
Exhibit 4 -- Instruments Defining The Rights Of Security Holders
The Company agrees to furnish a copy of each such instrument
to the Commission upon request.
4.01 Specimen Common Stock Certificate of Pacific Enterprises (Pacific
Enterprises 1988 Form 10-K;10-K, Exhibit 4.01).
4.02 Specimen Preferred Stock Certificates of Pacific Enterprises
(Pacific Lighting Corporation 1980 Form 10-K;10-K, Exhibit 4.02).
4.03 Specimen Preferred Stock Certificates of Southern California Gas
Company (Southern California Gas Company 1980 Form 10-K;10-K, Exhibit
4.01).
4.04 First Mortgage Indenture of Southern California Gas Company to
American Trust Company dated October 1, 1940 (Registration
Statement No. 2-4504 filed by Southern California Gas Company on
September 16, 1940;1940, Exhibit B-4).
4.05 Supplemental Indenture of Southern California Gas Company to
American Trust Company dated as of July 1, 1947 (Registration
Statement No. 2-
70722-7072 filed by Southern California Gas Company on
March 15, 1947;1947, Exhibit B-5).
4.06 Supplemental Indenture of Southern California Gas Company to
American Trust Company dated as of August 1, 1955 (Registration
Statement No. 2-
119972-11997 filed by Pacific Lighting Corporation on
October 26, 1955;1955, Exhibit 4.07).
4.07 Supplemental Indenture of Southern California Gas Company to
American Trust Company dated as of June 1, 1956 (Registration
Statement No. 2-
124562-12456 filed by Southern California Gas Company on
April 23, 1956;1956, Exhibit 2.08).95
4.08 Supplemental Indenture of Southern California Gas Company to Wells
Fargo Bank, National Association dated as of August 1, 1972
(Registration Statement No. 2-59832 filed by Southern California
Gas Company on September 6, 1977;1977, Exhibit 2.19).
4.09 Supplemental Indenture of Southern California Gas Company to Wells
Fargo Bank, National Association dated as of May 1, 1976
(Registration Statement No. 2-56034 filed by Southern California
Gas Company on April 14, 1976;1976, Exhibit 2.20).
4.10 Supplemental Indenture of Southern California Gas Company to Wells
Fargo Bank, National Association dated as of September 15, 1981
(Pacific Enterprises 1981 Form 10-K;10-K, Exhibit 4.25).
4.11 Supplemental Indenture of Southern California Gas Company to
Manufacturers Hanover Trust Company of California, successor to
Wells Fargo Bank, National Association, and Crocker National Bank
as Successor Trustee dated as of May 18, 1984 (Southern California
Gas Company 1984 Form 10-K;10-K, Exhibit 4.29).
4.12 Supplemental Indenture of Southern California Gas Company to
Bankers Trust Company of California, N.A., successor to Wells
Fargo Bank, National Association dated as of January 15, 1988
(Pacific Enterprises 1987 Form 10-K;10-K, Exhibit 4.11).
4.13 Supplemental Indenture of Southern California Gas Company to First
Trust of California, National Association, successor to Bankers
Trust Company of California, N.A. dated as of August 15, 1992
(Registration Statement No. 33-50826 filed by Southern California
Gas Company on August 13, 1992;1992, Exhibit 4.37).
4.14 Supplemental Indenture of Southern California Gas Company to
U.S. Bank, N.A., successor to First Trust of California, N.A.
dated as of October 1, 2002 (2002 Sempra Energy Form 10-K,
Exhibit 4.17).
4.15 Supplemental Indenture of Southern California Gas Company to
U.S. Bank, N.A., successor to First Trust of California, N.A.,
Dated as of October 17, 2003 (2004 Sempra Energy Form 10-K,
Exhibit 4.19).
4.16 Supplemental Indenture of Southern California Gas Company to
U.S. Bank, N.A., successor to First Trust of California, N.A.,
Dated as of December 15, 2003 (2004 Sempra Energy Form 10-K,
Exhibit 4.20).
4.17 Supplemental Indenture of Southern California Gas Company to
U.S. Bank, N.A., successor to First Trust of California, N.A.,
Dated as of October December 10, 2004 (2004 Sempra Energy Form
10-K, Exhibit 4.21).
4.18 Specimen 7 3/4% Series Preferred Stock Certificate (Southern
California Gas Company 1992 Form 10-K;10-K, Exhibit 4.15).96
Exhibit 10 -- Material Contracts
Compensation
10.01 Form of Severance Pay Agreement (2004 Sempra Energy 10-K
Exhibit 10.10).
10.02 Sempra Energy 2005 Deferred Compensation Plan (Pacific
Enterprises Form 8-K filed on December 07, 2004, Exhibit 10.1).
10.03 Sempra Energy Employee Stock Incentive Plan (September 30, 2004
Sempra Energy Form 10-Q, Exhibit 10.1).
10.04 Sempra Energy Amended and Restated Executive Life
Insurance Plan (September 30, 2004 Sempra Energy Form 10-Q,
Exhibit 10.2).
10.05 Sempra Energy Excess Cash Balance Plan (September 30, 2004
Sempra Energy Form 10-Q, Exhibit 10.3).
10.06 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).
10.07 Form of Sempra Energy 1998 Long Term Incentive Plan
Nonqualified Stock Option Agreement (September 30, 2004
Sempra Energy Form 10-Q, Exhibit 10.5).
10.08 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).
10.09 Sempra Energy Supplemental Executive Retirement Plan (September
30, 2004 Sempra Energy Form 10-Q, Exhibit 10.7).
10.10 Neal Schmale Restricted Stock Award Agreement (September 30,
2004 Sempra Energy Form 10-Q, Exhibit 10.8).
10.11 Severance Pay Agreement between Sempra Energy and
Donald E. Felsinger (September 30, 2004 Sempra Energy Form 10-Q,
Exhibit 10.9).
10.12 Severance Pay Agreement between Sempra Energy and Neal Schmale
(September 30, 2004 Sempra Energy Form 10-Q, Exhibit 10.10).
10.13 Sempra Energy Executive Personal Financial Planning Program
Policy Document (September 30, 2004 Sempra Energy Form 10-Q,
Exhibit 10.11).
10.14 Sempra Energy 2003 Executive Incentive Plan B (2003 Sempra
Energy Form 10-K, Exhibit 10.10).
10.15 Sempra Energy 2003 Executive Incentive Plan (June 30, 2003
Sempra Energy Form 10-Q, Exhibit 10.1).
97
10.16 Amended 1998 Long-Term Incentive Plan (June 30, 2003 Sempra
Energy Form 10-Q, Exhibit 10.2).
10.17 Sempra Energy Executive Incentive Plan effective January 1, 2003
(2002 Sempra Energy Form 10-K, Exhibit 10.09).
10.18 Amended Sempra Energy Retirement Plan for Directors (2002 Sempra
Energy Form 10-K, Exhibit 10.10).
10.19 Amended and Restated Sempra Energy Deferred Compensation and
Excess Savings Plan (Sempra Energy September 30, 2002 Form 10-Q,
Exhibit 10.3).
10.20 Sempra Energy Executive Security Bonus Plan effective January 1,
2001 (2001 Sempra Energy Form 10-K;10-K, Exhibit 10.08).
10.0210.21 Form of Sempra Energy Severance Pay Agreement for Executives
(2001 Sempra Energy Form 10-K;10-K, Exhibit 10.07).
10.0310.22 Sempra Energy Deferred Compensation and Excess Savings Plan
effective January 1, 2000 (Sempra Energy 2000 Form 10-K,
Exhibit 10.07).
10.04 Sempra Energy Supplemental Executive Retirement Plan as amended and
restated effective July 1, 1998 (Sempra Energy 1998 Form 10-K Exhibit
10.09).
10.05 Sempra Energy Executive Incentive Plan effective June 1, 1998 (Sempra
Energy 1998 Form 10-K Exhibit 10.11).
10.06 Sempra Energy Executive Deferred Compensation Agreement effective June
1, 1998 (Sempra Energy 1998 Form 10-K Exhibit 10.12).
10.0710.23 Sempra Energy 1998 Long Term Incentive Plan (Incorporated by
reference from the Registration Statement on Form S-8 Sempra
Energy Registration No. 333-56161 dated June 5, 1998;1998, Exhibit
4.1).
10.0810.24 Pacific Enterprises Employee Stock Ownership Plan and Trust
Agreement as amended effective October 1, 1992. (Pacific
Enterprises 1992 Form 10-K;10-K, Exhibit 10.18).
10.0910.25 Amended and Restated Pacific Enterprises Employee Stock Option
Plan (Southern California Gas Company 1996 Form 10-K;10-K, Exhibit
10.10).
Exhibit 12 -- Statement Re: Computation of Ratios
12.01 Pacific Enterprises Computation of Ratio of Earnings to Fixed
Charges for the years ended December 31, 2004, 2003, 2002, 2001
2000, 1999, 1998, 1997.and 2000.
12.02 Southern California Gas Company Computation of Ratio of Earnings
to Fixed Charges for the years ended December 31, 2004, 2003,
2002, 2001 2000, 1999, 1998,
1997.and 2000.
Exhibit 21 -- Subsidiaries
21.01 Pacific Enterprises Schedule of Subsidiaries at December 31, 2001.2004.
21.02 Southern California Gas Company Schedule of Subsidiaries at
December 31, 2001.2004.
98
Exhibit 23 -- Consents of Independent Auditor's Consents,Registered Public
Accounting Firm, page 71.89.
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.
32.4 Statement of SoCalGas' Chief Financial Officer pursuant
to 18 U.S.C. Sec. 1350.
99
GLOSSARY
AFUDC Allowance for Funds Used During Construction
ALJ Administrative Law Judge
ARB Accounting Research Bulletin
BCAP Biennial Cost Allocation Proceeding
Bcf One Billion Cubic Feet (of natural gas)
CA/AZ California/Arizona
COS Cost of ServiceCalifornia
Utilities Southern California Gas Company and San Diego Gas
& Electric
CPUC California Public Utilities Commission
Enova Enova Corporation
EPA Environmental Protection Agency
ESOP Employee Stock Ownership PlanDSM Demand Side Management
El Paso El Paso Natural gas Company
ERMG Energy Risk Management Group
ERMOC Energy Risk Management Oversight Committee
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
FSP FASB Staff Position
GCIM Gas Cost Incentive Mechanism
GIR Gas Industry Restructuring
ICWUC International Chemical Workers' Union Counsel
IRS Internal Revenue Service
IOUs Investor-Owned Utilities
LIBOR London Interbank Offered Rate
LIFO Last in first out inventory costing method
LNG Liquefied Natural Gas
MGP Manufactured-Gas Plants
mmbtu Million British Thermal Units (of natural gas)
OIR Order Instituting Ratemaking
ORA Office of Ratepayer Advocates
PBR Performance-Based Ratemaking/Regulation
100
PE Pacific Enterprises
PRP Potentially Responsible Party
RD&D Research Development and Demonstration
ROE Return on Equity
ROR Rate of Return on Ratebase
SDG&E San Diego Gas & Electric Company
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
SoCalGas Southern California Gas Company
TURN TheUWUA Utility Reform NetworkWorkers' Union of America
VaR Value at Risk
55
2
70
49