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 For the fiscal year ended December 31, 2000
--------------------2001
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 - -------------------------------------------------------------------
(Exact name of registrant as specified in its charter)California 94-0743670
1-1402 SOUTHERN CALIFORNIA 1-40 94-0743670
- -------------------------------------------------------------------
(State of incorporation (Commission (I.R.S. Employer
or organization) File Number) Identification No.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 ]
Exhibit Index on page 56.76. Glossary on page 58.79.
Aggregate market value of the voting preferred stock held by non-
affiliatesnon-affiliates of the
registrant as of February 28,2001 was
$42 million.
Registrant's common stock28, 2002:
Pacific Enterprises $51.1 Million
Southern California Gas Company $15.8 Million
Common Stock outstanding without par value as of February 29, 2000 was
wholly28, 2002:
Pacific Enterprises Wholly owned by Sempra Energy.Energy
Southern California Gas Company Wholly owned by Pacific Enterprises
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Information Statement prepared for the May 20012002 annual
meeting of shareholders are incorporated by reference into Part
III.
TABLE OF CONTENTS
PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . 3
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . 11.10
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . 11.10
Item 4. Submission of Matters to a Vote of Security Holders. . 11.10
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . 11.11
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . 12.11
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . 12.12
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk . . . . . . . . . . . . . . . . . 24.24
Item 8. Financial Statements and Supplementary Data. . . . . . 25.24
Item 9. Changes In and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . 50.67
PART III
Item 10. Directors and Executive Officers of the Registrant . . 50.68
Item 11. Executive Compensation . . . . . . . . . . . . . . . . 50.69
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . . 50.69
Item 13. Certain Relationships and Related Transactions . . . . 51.69
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . 51.69
Independent Auditors' ConsentConsents and Report on Schedule.Schedule . . . . . 52.71
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 55.74
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 56.76
Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . . 58
2
.79
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," "would" and "should" or similar expressions, or
discussions of strategy or of plans are intended to identify
forward-
lookingforward-looking statements. Forward-looking statements are not
guarantees of performance. They involve risks, uncertainties and
assumptions. Future results may differ materially from those
expressed in these forward-looking statements.
Forward-looking statements are necessarily based upon various
assumptions involving judgments with respect to the future and other
risks, including, among others, local, regional, national and
international economic, competitive, political, legislative and
regulatory conditions;conditions and developments; actions by the California Public Utilities
Commission,CPUC, the
California Legislature and the Federal Energy
Regulatory Commission;FERC; the financial condition of
other investor-
ownedinvestor-owned utilities; capital market conditions, inflation
rates, interest rates and interestexchange rates; energy and trading
markets, including the timing and extent of changes in commodity
prices; weather conditions;conditions and conservation efforts; business,
regulatory and legal decisions; the pace of deregulation of retail
natural gas and electricity delivery; the timing and success of
business-developmentbusiness development efforts; and other uncertainties, all of which
are difficult to predict and many of which are beyond the control of
the Company.company. Readers are cautioned not to rely unduly on any
forward-looking statements and are urged to review and consider
carefully the risks, uncertainties and other factors which affect
the Company'scompany's business described in this Annual
Reportannual report and other
reports filed by the Companycompany from time to time with the Securities
and Exchange Commission.
PART I
ITEM 1. BUSINESS
Description of Business
Pacific Enterprises (PE or the Company)company) is an energy services company
whose only direct subsidiary is Southern California Gas Company
(SoCalGas), the nation's largest natural gas distribution utility. A
description of PE and SoCalGas ownsis given in "Management's Discussion
and operatesAnalysis of Financial Condition and Results of Operations" herein.
SoCalGas is PE's only subsidiary and PE itself has no operations.
PE's financial position and operations consist of those of SoCalGas and
some additional items attributable to PE's position as a natural gas distribution,
transmissionholding
company (e.g. cash, intercompany accounts, debt and storage system supplying natural gas throughout a
23,000-square mile service territory comprising most of southern
California and part of central California. SoCalGas provides
natural gas service to residential, commercial, industrial, utility
electric generation and wholesale customers through 5.0 million
meters in a service area with a population of 18.4 million.equity.)
GOVERNMENT REGULATION
SoCalGas is regulated by local, state and federal agencies, as
described below.
3
Local Regulation
SoCalGas has gas franchises with the 238239 legal jurisdictions in its
service territory. These franchises allow SoCalGas to locate
facilities for the transmission and distribution of natural gas in the
streets and other public places. Some franchises have fixed terms,
such as that for the city 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.
StateCalifornia 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.
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, rate of return, rates of depreciation,
uniform systems of accounts, examination 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.
FederalUnited 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.
Licenses and Permits
SoCalGas obtains a number of 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
Industry segment informationInformation on this topic is contained in "Management's
Discussion and Analysis of Financial Condition and Results of
Operations," andprovided in Note 132 of the notes to
Consolidated Financial Statements herein.
NATURAL GAS OPERATIONS
Utility Services
SoCalGas purchases, sells, distributes, stores and transports natural
gas. It owns and operates a natural gas distribution, transmission and
storage system that supplies natural gas to 5.1 million end-use
customers throughout a 23,000-square-mile service territory with a population of approximately 18.4 million
people. Itsfrom
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 includes most of southern California
and part of central California.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 systems of the City
of Long Beach, Southwest Gas Corporation and SDG&E,San Diego Gas & Electric
Company (SDG&E), an affiliated company.
4
Supplies of Natural Gas
SoCalGas buys natural gas under several short-term and long-term
contracts. Short-term purchases under these contracts are primarily 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.
SoCalGas recovers such fixed 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 delivered 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
19961997 through 2000.2001:
YearYears Ended December 31
--------------------------------------------------------------------------------------------------------------------
2001 2000 1999 1998 1997
1996
- ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Purchases in billions of cubic feet
Spot market 343 315 270 229 226
Long-term contracts 16 74 101 95 96
California producers 1 2 3 5 12
------- ------- ------- ------- -------
TotalGas Purchases - Commodity Portion 367 360 391 374 329
334
Customer-OwnedCustomer-owned and Exchange Receiptsexchange receipts 837 755 637 637 614
518
Storage withdrawal
(injection)Withdrawal
(Injection) - net (27) 39 (6) (28) (3)
42
Company use and
unaccounted forFor (24) (21) (16) (21) (10) (10)
------- ------- ------- ------- -------
Net Deliveries 1,153 1,133 1,006 962 930 884
======= ======= ======= ======= =======
Purchases in millions of dollars
Commodity costs $1,997 $1,243 $ 916 $ 774 $ 849
$ 627
Fixed charges* 128 128 147 174 250 276
------- ------- ------- ------- -------
Total Purchases $2,125 $1,371 $1,063 $ 948 $1,099 $ 903
======= ======= ======= ======= =======
Average Commodity Cost of Purchases
(dollars per thousand cubic feet)** $5.44 $3.45 $2.34 $ 2.072.34 $2.07 $2.58 $1.88
======= ======= ======= ======= =======
* Fixed charges primarily include pipeline demand charges, take or pay settlement
costs and other direct billeddirect-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 tentwo years, based on spot prices) accountedaccount for 95100 percent of total
natural gas volumes purchased by SoCalGas during 2000, as
compared with 81 percent and 72 percent during 1999 and 1998,
respectively. Supply/demand imbalances are affecting the price of
natural gas in California more than in the rest of the country
5
because of California's dependence on natural gas fired electric
generation due to air-quality considerations.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, compared withand $2.33/mmbtu in 1999.
OnSupply/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
11, 2000,31, 2001, the average spot cash gas price at the CA/AZCalifornia/Arizona border
reached a record
high of $56.91/was $2.63/mmbtu.
During 2000,2001, SoCalGas delivered 1,1331,153 bcf of natural gas through
its system. Approximately 7069 percent of these deliveries were
customer-owned natural gas for which SoCalGas provided transportation
services. The balance ofremaining natural gas deliveries was gaswere purchased by
SoCalGas and resold to customers. SoCalGasThe company estimates that
sufficient natural gas supplies will be available to meet the
requirements of its customers for the next several years.
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
capability. There are approximately 5 million core customers (4.8
million residential and 0.2 million small commercial and industrial).
Noncore customers consist primarily of utility electric
generation (UEG), wholesale, large commercial, industrial and off-systemoff-
system (outside SoCalGas'the company's normal service territory) customers, and total
approximately 1,500.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 its core customers. SoCalGas
and SDG&E recently filed an application with the CPUC to combine the
two companies' core procurement portfolios. On March 6, 2002, a
proposed decision was issued which, if approved, will allow 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
noncore customers will be phased out. Noncore customers will have the
option of purchasingto either become core customers, and continue to receive
utility procurement services, or remain noncore customers and purchase
their natural gas either
from SoCalGas or from other sources, such as brokers or producers,producers.
Noncore customers will also have to make arrangements to deliver their
purchases to SoCalGas' receipt points for delivery through SoCalGas'the
company's transmission and distribution system.
The only natural gas supplies that SoCalGas may offer for sale to
noncore customers are the same supplies that it purchases for its
core customers. Most noncore customers procure their own natural gas
supply.
In 2000,2001, 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 revenuerevenues from transportation throughput is less than for
natural gas sales, SoCalGas generally earns the same margin whether
the CompanySoCalGas buys the gas and sells it to the customer or transports
natural gas already owned by the customer.
SoCalGas also provides natural gas storage services for noncore
and off-
systemoff-system customers 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.
As of December 31, 2000,2001, SoCalGas was storing approximately 235 bcf of
customer-owned gas.
6
Demand for Natural Gas
Natural gas is a principal energy source for residential, commercial,
industrial and UEG customers. Natural gas competes with electricity
for residential and commercial cooking, water heating, space heating
and clothes drying, and with other fuels for large industrial,
commercial and UEG uses. Growth in these natural gasthe natural-gas markets dependsis largely
ondependent upon the health and expansion of the southern California
economy. SoCalGas added approximately 69,00058,000 new customer meters in
20002001 and 74,00069,000 in 1999,2000, representing growth rates of approximately
1.41.2 percent and 1.51.4 percent, respectively. SoCalGas expects its growth
rate for 2001 to be at the
2000 level.2002 will approximate that of 2001.
During 2000,2001, 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.
Demand for natural gas by noncore customers is very sensitive to
the price of competing fuels. Although the number of noncore customers
in 20002001 was only 1,500,1,300, it accounted for 12approximately 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. The demand for natural
gas by large UEG customers is also greatly affected by the price and
availability of electric power generated in other areas.
The increase in UEG demand in 2000 was due to
higher demand for electricity and increased use of natural gas for
electric generation, a colder 2000 - 2001 winter and population growth
in California. Natural gas demand in 1999 for UEG customer use increased
primarily due to higher electric energy usage in the summer, as a result
of warmer weather.
Effective March 31, 1998, electric industry restructuring gave
California consumers the option of selecting their electric energy
provider from a variety of local and out-of-state producers. As a
result, natural gas demand for electric generation within southern
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 UEGelectric generating plant customers may be
adverselysignificantly affected to the extent that regulatory changes divert
electricity productiongeneration from SoCalGas' service area and as noted in the following
paragraph.
On January 18, 2001, Pacific Gas & Electric Company (PG&E) filed an
emergency application with the CPUC requesting that SoCalGas be ordered
to purchase natural gas or supply available natural gas to meet PG&E's
core procurement needs. Some of PG&E's suppliers are declining to sell
natural gas to PG&E due to its poor credit rating. Although SoCalGas has
agreed to supply a limited amount of natural gas to PG&E through March
31, 2001 (secured by PG&E customer receivables), it is still urging
rejection of the request which, if approved, could severely jeopardize
SoCalGas' ability to serve its own customers because of cash flow
considerations.
7
area.
Other
Additional information concerning customer demand and other aspects of
natural gas operations is provided under "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and in
Notes 11 and 12 of the notes to Consolidated Financial Statements
herein.
RATES AND REGULATION
SoCalGas is regulated by the CPUC, which consists of five commissioners
appointed by the Governor of California for staggered six-year terms. It
is the responsibility of the CPUC to determine that utilities operate
within the best interests of their customers. The regulatory structure is
complex and has a substantial impact on the profitability of the Company.
Both the electric and natural gas industries are currently undergoing
transitions to competition and are being impacted by abnormally high
commodity prices resulting from supply/demand imbalances.
Natural Gas Industry Restructuring
The natural gas industry in California experienced an initial phase of
restructuring during the 1980s by deregulating1980s. In December 2001 the CPUC issued a
decision adopting provisions affecting the structure of the natural
gas sales to noncore customers.
The CPUC is currently assessing the current market and regulatory
framework for California's natural gas industry. As a result of
California's dependence on natural gas fired electric generation due to
air-quality considerations, supply/demand imbalances are affecting the
price of natural gasindustry in California, more than insome of which could introduce additional
volatility into the restearnings of the country.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
gas 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.
Performance-Based Regulation (PBR)
In recent years, the CPUC has directed utilities to use PBR. To promote
efficient operations and improved productivity and to move away from
reasonableness reviews and disallowances, PBR has replaced the general
rate case and certain other regulatory proceedings for SoCalGas.
Additional information on PBR 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.
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.
8
The BCAP will continue under PBR. 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
Under PBR, annual CostThe authorized cost of Capital proceedings have been replacedcapital is determined by an automatic
adjustment mechanism ifbased on changes in certain indices exceed
established tolerances.capital market
indices. Additional information on SoCalGas'the company's cost of capital 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.
ENVIRONMENTAL MATTERS
Discussions about environmental issues affecting SoCalGas are included
in "Management's Discussion and Analysis of Financial Condition and
Results of Operations" 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 SoCalGas to recover in
rates the costs associated with the cleanup of sites contaminated with
hazardous waste. In general, SoCalGas is allowed to recover 90 percent
of its cleanup costs and any related costs of litigation.
During the early 1900s, SoCalGas and its predecessors
manufactured gas from coal or oil. The manufacturing sites often have
become contaminated with the hazardous residual by-products of the
process. SoCalGas has identified 42 former manufactured-gas plant
sites at which it (together with other users as to 21 of these sites)
may have cleanup obligations. As of December 31, 2001, 18 of these
sites have been remediated, of which 14 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, SoCalGas' estimated remaining investigation and
remediation liability for all of these sites is $54.5 million.
SoCalGas lawfully disposed 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 two landfill sites and five industrial waste disposal sites, from
which releases have occurred as described below.
Remedial actions and negotiations with other PRPs and the United
States Environmental Protection Agency (EPA) have been in progress since
1986 and 1993 for the two landfill sites. The Company'scompany's share of costs
to remediate these sites is estimated to be $3.7$10.4 million of which $410,000
was incurred during 2000.($0.7
million for the first site and $9.7 million for the second site). Of
this, $5.0 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 Companycompany was notified of hazards at two
industrial waste treatment facilities in the California communities of
Fresno and Carson, where the Companycompany had disposed of wastes. During
2000, the Companycompany settled with the other PRPs at these sites for $425,000$0.4
million and has no additional liability.
9
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. It is too earlySoCalGas has reserved
$0.8 million in contingent environmental liability for its share of
site cleanup. Amounts expended to determine the existence or
extent of any prior releases or SoCalGas' potential total liability.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
liability is estimated at less than $10,000.$5,900. Settlement and payment to the State
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 for $200,000.
In addition, the Company has identified and reported to California
environmental authorities 42 former manufactured-gas plant sites for
which it (together with other users as to 21 of these sites) may have
cleanup obligations. As of December 31, 2000, 18 of these sites have been
remediated, of which 14 have received certification from the California
Environmental Protection Agency. Preliminary investigations, at a
minimum, have been completed on 40 of the gas plant sites.$0.2 million.
At December 31, 2000,2001, SoCalGas' estimated remaining investigation
and remediation liability related to hazardous waste sites, including
the manufactured-gas plantmanufactured gas sites, detailed above, was $57.6$54.5 million, of which 90 percent is
authorized to be recovered through the Hazardous Waste Collaborative
mechanism. SoCalGas believes that any costs not ultimately recovered
through rates, insurance or other means, will not have a material
adverse effect on SoCalGas' 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 utility operating costs. The CPUC
has authorized SoCalGas to recover its operating costs associated with
RD&D. An annual average of $7.9$7.5 million has been spent forover the last
three years.
10
Employees of Registrant
As of December 31, 2000,2001, SoCalGas had 5,8536,063 employees, compared to
6,0795,853 at December 31, 1999.2000.
Wages
Field, technical and most clerical employees ofat SoCalGas are
represented by the Utility Workers' Union of America or the
International Chemical Workers' Council. The collective bargaining
agreement on wages, hours and working conditions remains in effect
through March 31, 2002. Negotiations for a new agreement are currently
in progress.
ITEM 2. PROPERTIES
Natural Gas Properties
At December 31, 2000,2001, SoCalGas owned 2,846approximately 2,845 miles of
transmission and storage pipeline, 45,15045,620 miles of distribution
pipeline and 44,54744,868 miles of service piping. It also owned 10
transmission compressor stations and 6 underground storage reservoirs,
(withwith a combined working capacity of 117.8 Bcf).121.1 billion cubic feet.
Other Properties
SoCalGas has a 15-percent limited partnership interest in a 52-story
office building in downtown Los Angeles. SoCalGas leases approximately
half of the building through the year 2011. The lease has six separate
five-year renewal options.
The Companycompany owns or leases other offices, operating and
maintenance centers, shops, service facilities, and equipment
necessary in the conduct of business.
ITEM 3. LEGAL PROCEEDINGS
Except for the matters described in Note 11 of the notes to
Consolidated Financial Statements or referred to elsewhere in this
Annual Report, neither the Companycompany nor its subsidiaries are party to,
nor is their property the subject of, any material pending legal
proceedings other than routine litigation incidental to their
businesses.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
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, all 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.
11
ITEM 6. SELECTED FINANCIAL DATA
(Dollars in millions)
At December 31, or for the years then ended
------------------------------------------------
Pacific Enterprises: 2001 2000 1999 1998 1997 1996
-------- ------- ------- ------- -------
Income Statement Data:
Operating revenues $3,716 $2,854 $2,569 $2,472 $2,738
$2,563
Operating income $ 269 $ 263 $ 271 $ 218 $ 259 $ 286
Dividends on preferred stock $ 4 $ 4 $ 4 $ 4 $ 54
Earnings applicable to
common shares $ 202 $ 207 $ 180 $ 143 $ 180
$ 196
Balance Sheet Data:
Total assets $4,828$4,191 $4,756 $4,110 $4,571 $4,977
$5,186
Long-term debt $ 579 $ 821 $ 939 $ 985 $1,118
$1,225
Short-term debt (a) $ 150 $ 120 $ 30 $ 249 $ 502
$ 411
Shareholders' equity $1,574 $1,526 $1,426 $1,547 $1,469 $1,440
(a) Includes long-term debt due within one year.
Since PEPacific Enterprises is a wholly owned subsidiary of Sempra
Energy, per share data has been omitted.
At December 31, or for the years then ended
------------------------------------------------
SoCalGas: 2001 2000 1999 1998 1997
-------- ------- ------- ------- -------
Income Statement Data:
Operating revenues $3,716 $2,854 $2,569 $2,427 $2,641
Operating income $ 273 $ 266 $ 268 $ 238 $ 318
Dividends on preferred Stock $ 1 $ 1 $ 1 $ 1 $ 7
Earnings applicable to
Common shares $ 207 $ 206 $ 200 $ 158 $ 231
Balance Sheet Data:
Total assets $3,762 $4,128 $3,452 $3,834 $4,205
Long-term debt $ 579 $ 821 $ 939 $ 967 $ 968
Short-term debt (a) $ 150 $ 120 $ 30 $ 75 $ 498
Shareholders' equity $1,327 $1,309 $1,310 $1,382 $1,467
(a) Includes long-term debt due within one year.
Since SoCalGas is a wholly owned subsidiary of Pacific Enterprises, per
share data has been omitted.
This data should be read in conjunction with the Consolidated
Financial Statements and 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
Introduction
This section includes management's discussion and analysis of
operating results from 19981999 through 2000,2001, and provides information
about the capital resources, liquidity and financial performance of
PE. This sectionPacific Enterprises (PE) and Southern California Gas Company
(SoCalGas). SoCalGas, PE or the two together are referred to as the
company herein, the distinction being indicated by the context. It
also focuses on the major factors expected to influence future
operating results and discusses investment and financing plans. It
should be read in conjunction with the consolidated financial statementsConsolidated Financial
Statements included in this Annual Report.
PE is an energy servicesa holding company whose only direct subsidiary is 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 mile service
territory comprising most of southern California and part of central
California. SoCalGas provides natural gas service to residential,
commercial, industrial, utility electric generation and wholesale customers
through 5.05 million meters in a service area with a population of 18.418
million.
12
Supply/demand imbalances are affecting the price of natural gas
in California more than in the rest of the country because of
California's dependence on natural gas fired electric generation due
to air-quality considerations.
The uncertainties shaping California's electric industry and
business environment also affect the Company's operations.
These recent developments are continuing to change. Information
as of March 7, 2001, the date this report was prepared, is found
herein, primarily under "Results of Operations" and "Factors
Influencing Future Performance" and in Note 11 of the notes to
Consolidated Financial Statements.
Business CombinationsCombination
Sempra Energy (the Parent) was formed to serve as a holding company for PE and Enova
Corporation (Enova), the parent corporation of San Diego Gas &
Electric Company (SDG&E), in connection with a business combination
that became effectivewas completed on June 26, 1998 (the PE/Enova business combination). In
connection with the PE/Enova business combination, the holders of common stock
of PE and Enova became the holders of Sempra Energy's common stock.
The preferred stock of PE
remained outstanding. The combination was a tax-free transaction.
Expenses incurred by PE in connection with this event were $35
million, aftertax, for the year ended December 31, 1998. No
significant expenses were incurred subsequently.
In January 1998, PE and Enova jointly acquired CES/Way
International Inc., which was subsequently renamed Sempra Energy
Services, as described under "Investments" herein. Expenses incurred
by PE in connection with the CES/Way acquisition were $7 million,
aftertax, all in the year ended December 31, 1998.
The costs of the transactions discussed above consist primarily
of employee-related costs, and investment banking, legal, regulatory
and consulting fees.
As a result of the PE/Enova business combination, PE dividended its
nonutility subsidiaries to Sempra Energy during 1998 and early 1999. SoCalGas is now the sole direct subsidiary of PE.
See Note 1 of the notes to the Consolidated Financial Statements for
additional information.
Capital Resources And Liquidity
The Company'sSoCalGas' operations have historically been a major source of
liquidity. In addition, working capital requirements arecan be met primarily
through the issuance of short-term and long-term debt. Cash
requirements primarily consist of capital expenditures for utility
plant.
At December 31, 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 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.
The decrease in cash flows from operating activities in 1999 was
primarily due torates on a return to ratepayers of the previously
overcollected regulatory balancing accounts. This decrease was
partially offset by the absence of business combination expenses and
lower income tax payments in 1999. See Note 1 of the notes to the
Consolidated Financial Statements for additional information.
13
current
basis.
Cash Flows From Investing Activities
Cash flows fromflow used in investing activities primarily representdecreased 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 at SoCalGas.plant. Capital
expenditures were $294 million in 2001, compared to $198 million and
$146 million in 2000 compared to $146
million and $150 million spent in 1999, and in 1998, respectively. The
increaseIncreases in capital
expenditures in 2001 and 2000 iswere 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.
The decrease inOver the next five years, the company expects to make capital
expenditures in 1999 is primarily due to shifting of certain functions
to Sempra Energy following the PE/Enova business combination.approximately $2.0 billion. Capital expenditures in
20012002 are expected to be comparable to those of 2000.2001. They will be
financed primarily by operations and debt issuances.
Investments
In December 1997, PEConstruction, investment and Enova jointly acquired Sempra Energy
Trading for $225 million. In July 1998, Sempra Energy Trading
purchased a subsidiaryfinancing 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 Consolidated Natural Gas, a wholesale
tradingcapital, and commercial marketing operation, for $36 million to expand
its operation in the eastern United States.
Sempra Energy Solutions, at the time jointly owned by Enovaenvironmental and PE, acquired CES/Way International, Inc. (CES/Way) in 1998. CES/Way
provides energy-efficiency services, including energy audits,
engineering design, project management, construction, financing and
contract maintenance. In the latter half of 1999, CES/Way's name was
changed to Sempra Energy Services.
Sempra Energy Trading and Sempra Energy Solutions were
transferred to Sempra Energy Holdings, a wholly owned subsidiary of
Sempra Energy and now named Sempra Energy Global Enterprises, in early
1999.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 and short-term debt repayments. Net cash used in financing activities decreased in 1999 primarily
dueFor
SoCalGas, the decrease was also attributable to lower short-term debt repayments and the repurchase of
preferred stockdividends paid
in 1998.2000.
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 andnotes. PE also repaid $43 million of short-term debt.
In 1998, cash was used for the repayment of $100 million of
first-mortgage bonds and $47 million of Swiss Franc bonds, partially
offset by the issuance of $75 million of medium-term notes. Short-term
debt repayments included $94 million of debt issued to finance the
Comprehensive Settlement as discussed in Note 12 of the notes to
Consolidated Financial Statements.
14
Stock Redemptions
On February 2, 1998, SoCalGas redeemed all outstanding shares of its
7.75% Series Preferred Stock at a cost of $25.09 per share, or $75
million including accrued dividends.
Dividends
Dividends paid to the ParentSempra Energy amounted to $190 million in 2001 and
$100 million both 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, and $97 million in 1998.respectively.
The payment of future dividends and the amount thereof are within
the discretion of the Company's boardcompanies' 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 including the current portion of long-term debt
was $2.5 billion at December 31, 2000.2001, was $2.3 billion of which
$2.1 billion applied to SoCalGas. The debt to capitalization
ratio was 38debt-to-capitalization ratios
were 32 percent and 35 percent at December 31, 2000.2001 for PE and
SoCalGas, respectively. Significant changes in capitalization during
20002001 included dividends declared to the Parent and repayment of long-term debt.
Cash and Cash Equivalents
Cash and cash equivalents were $205 million at December 31, 2000. This
cash isare available for investment in projects
consistent with the Company'scompany's strategic direction, capital expenditures, the retirement of debt, the repurchase of common stock, the
payment of dividends and other corporate purposes. The Company anticipates that operating cash
required in 2001 for capital expenditures, dividends and debt payments
will be provided by cash generated from operating activities and from
long-term and short-term debt issuances.
In addition to cash generated from ongoing operations, SoCalGasPE has a
credit agreement thatwhich permits short-term borrowings of up to $170 million.$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. For additionalThese 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
see Noteconcerning these commitments is provided above and in Notes 3, 4 and
11 of the notes to Consolidated Financial Statements.
In December 2000, PE and Sempra Energy jointly filed a shelf
registration for the public offering of up to $500 million of debt
securities of PE, guaranteed by Sempra Energy. As yet, no debt
securities have been issued under this registration statement. For
additional information, see Notes 4 and 12 of the notes to
Consolidated Financial Statements.
Management believes that the sources of funding described above
are sufficient to meet short-term and long-term liquidity needs.
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
To understand the operations and financial results of the Company,company, it
is important to understand the ratemaking procedures that SoCalGas
follows.
SoCalGas is regulated by the CPUC. It is the responsibility of
the CPUC to determine that utilities operate in the best interests of
their customers and have the opportunity to earn a reasonable return
on investment.
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 tailored to the desires of
customers. The CPUC currently is studyingstill considering the issueschedule for
implementation of restructuring for sales to core customers and, as mentioned above,
supply/demand imbalances are affecting the price of natural gas in
California more than in the restthese regulatory changes, but it is expected that
most of the country because of
California's dependence on natural gas fired electric generation due
to air-quality considerations.
15
See additional discussions of natural gas-industry restructuring
below under "Factors Influencing Future Performance" and in Note 12 of
the notes to Consolidated Financial Statements.changes will be implemented during 2002.
In connection with restructuring of the natural gas industry,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 (seeinfrastructure.
See additional discussions of natural gas-industry restructuring
below under "Factors Influencing Future Performance" and in Note 12 of
the notes to Consolidated Financial Statements).Statements.
The table below summarizes the components ofSoCalGas' natural gas volumes and revenues
by customer class for 2000, 1999 and 1998.class:
SoCalGas
GAS SALES, TRANSPORTATION &AND EXCHANGE
(Dollars in millions, volumes in billion cubic feet)
For the years ended December 31
Gas Sales Transportation & Exchange Total
-----------------------------------------------------------------------
ThroughputVolumes Revenue ThroughputVolumes Revenue ThroughputVolumes Revenue
-----------------------------------------------------------------------
2001:
Residential 263 $2,336 2 $ 6 265 $2,342
Commercial and industrial 95 670 258 157 353 827
Electric generation plants -- -- 361 86 361 86
Wholesale -- -- 174 36 174 36
-----------------------------------------------------------------------
358 $3,006 795 $285 1,153 3,291
Balancing accounts and other 425
---------
Total $3,716
- ---------------------------------------------------------------------------------------------
2000:
Residential 251 $2,167 3 $ 12 254 $2,179
Commercial and Industrialindustrial 86 621 317 209 403 830
Utility Electric Generationgeneration plants -- -- 310 106 310 106
Wholesale -- -- 166 54 166 54
-----------------------------------------------------------------------
337 $2,788 796 $381 1,133 3,169
Balancing accounts and other (315)
---------
Total $2,854
- ---------------------------------------------------------------------------------------------
1999:
Residential 275 $1,821 3 $ 10 278 $1,831
Commercial and Industrialindustrial 84 452 306 229 390 681
Utility Electric Generationgeneration plants -- -- 188 77 188 77
Wholesale -- -- 150 57 150 57
-----------------------------------------------------------------------
359 $2,273 647 $373 1,006 2,646
Balancing accounts and other (77)
---------
Total $2,569
- ---------------------------------------------------------------------------------------------
1998:
Residential 269 $1,976 3 $ 11 272 $1,987
Commercial and Industrial 81 466 315 261 396 727
Utility Electric Generation -- -- 139 66 139 66
Wholesale -- -- 155 66 155 66
-----------------------------------------------------------------------
350 $2,442 612 $404 962 2,846
Balancing accounts and other (419)(77)
---------
Total $2,427$2,569
- ---------------------------------------------------------------------------------------------
16
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 increased in 2001 compared to 2000 due
to higher costs for company-use fuel (as a result of higher gas
prices), higher employee benefit expenses and operation costs covered
by balancing accounts.
2000 Compared to 1999
Net income for 2000 increased to $211 million compared to net income of $184 million in 1999. The
increase iswas primarily due to higher non-
corenon-core gas throughput, the gain
on sale of SoCalGas' investment in Plug Power noted above, and lower
operating and maintenance expenses. Net income forFor the fourth quarter of 2000,
increased to $58 millionnet income for SoCalGas decreased compared to $51
million for the fourth quarter of
1999. The increase isdecrease was primarily due to the favorable resolution of
income tax issues in 1999, partially offset by higher non-core gas
throughput and the sale of the SoCalGas'
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 (see discussion of balancing accounts and gas revenues in Note 2
of the notes to Consolidated Financial Statements) and higher UEG
revenues.revenues from electric-generation customers. The
increase in UEGthese revenues was due to higher demand for electricity in
2000. In addition, the generating plants receiving gas
transportation from SoCalGas are operating at higher capacities than
previously, as discussed below.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
due to the increased use of natural gas to fuel electric generation,
colder winter weather and population growth in California.
Under the
current regulatory framework, changes in core-market natural gas
prices do not affect net income, since the actual commodity cost of
natural gas for core customers is included in customer rates on a
substantially current basis.
OperatingOther operating expenses decreased from $748 million in 19992000 compared to $696
million in 2000. The decrease was1999
primarily due to lower pension expense in 2000.
1999 Compared to 1998
Net income for 1999 increased to $184 million compared to net income
of $147 million in 1998. The increase is primarily due to the
business-combination expenses of $35 million, after-tax, in 1998 (none
in 1999). Net income for the fourth quarter of 1999 was consistent
with the fourth quarter of 1998.
Natural gas revenues increased from $2.5 billion in 1998 to $2.6
billion in 1999. The increase was primarily due to higher UEG
revenues, partially offset by a decrease in residential, commercial
and industrial revenues. The increase in UEG revenues was primarily
due to higher electric energy usage in the summer, as a result of
warmer weather. The decrease in residential and commercial and
industrial revenues is due to lower gas prices.
The Company's cost of natural gas distributed increased from $0.8
billion in 1998 to $1.0 billion in 1999. The increase was largely due
to an increase in the average price of natural gas purchased.
Operating expenses decreased from $930 million in 1998 to $748
million in 1999. The decrease was primarily due to the $60 million of
business-combination costs in 1998.
Other Income and Deductions, Interest Expense and Income Taxes
Other Income and Deductions
Other income and deductions whichconsist primarily consists of interest income and/or expense from
short-term investments and interest income or expense from regulatory
balancing accounts, was $47 million, $1 million and ($1) million for
the years ended December 31,accounts. This decreased in 2001 as compared to 2000 1999 and 1998, respectively. The
increase in 2000 is due to
higherlower interest earned on loansfrom affiliates, and due to Sempra
Energy, lower quasi-reorganization expenses, and athe 2000 gain recognized on the sale
of SoCalGas' investment in Plug Power. 17
Other income increased in 2000
compared to 1999 primarily due to higher interest earned on loans to
affiliates, and also due to the gain recognized on the sale of Plug
Power.
Interest Expense
Interest expense increaseddecreased in 2001 as compared to $992000 due to
SoCalGas' repayments of $270 million in long-term debt during the
fourth quarter of 2001, and also due to lower interest expense to
affiliates. Interest expense increased in 2000 from $88 million inas compared to 1999
primarily due to aSoCalGas' 1999 reversal of previously accrued
interest expense related to income-tax issues in 1999 as a result of favorable income-tax rulings,
partially offset by lower interest expense on long-term debt due to
lower long-term debt balances during 2000. Interest expense was $70
million for 1998. The increase in interest expense in 1999 compared to
1998 is primarily due to higher interest expense on loans to
affiliates, partially offset by the reversal of interest expense noted
above.income-
tax rulings.
Income Taxes
Income tax expense was $185 million, $166 milliondecreased in 2001 as compared to 2000 due to lower
income before taxes, and $127 million for
the years ended December 31, 2000, 1999 and 1998, respectively. The
increase in incomehigher deductions related to capitalized
costs. Income tax expense forat PE increased in 2000 as compared to 1999
is primarily due to thean increase in income before taxes as a result of lower Quasi-
Reorganization expenses in 2000. The increase in income tax expense
for 1999 compared to 1998 is due to the increase in income before
taxes as a result of lower business combination costs. The effective
income tax rates were 46.7 percent, 47.4 percent and 46.4 percent for
the same years. See Note 5 of the notes to the Consolidated Financial
Statements for additional information.taxes.
Factors Influencing Future Performance
Performance of the CompanyPE in the near future will depend on the results of
SoCalGas. The factors influencing financialSoCalGas' future performance are
summarized below.
Natural Gas Restructuring and Gas Rates
TheOn December 11, 2001, the CPUC issued a decision adopting the
following provisions affecting the structure of the natural gas
industry experienced an initial phasein California, some of restructuring
duringwhich could introduce additional
volatility into the 1980s by deregulating naturalearnings of SoCalGas and other market
participants: a system for shippers to hold firm, tradable rights to
capacity on SoCalGas' major gas sales totransmission 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 customers. In January 1998, the CPUC releasedbalancing
provisions; a staff report
initiating a proceeding to assess the current market and regulatory
framework for California's natural gas industry. The general goalsreallocation among customer classes of the plan arecost 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 consider reforms toobtain gas supply service
from SoCalGas. The CPUC is still considering the currentschedule for
implementation of these regulatory framework,
emphasizing market-oriented policies benefiting California's natural
gas consumers. A CPUC decisionchanges, but it is expected in 2001.
In October 1999, the state of California enacted a law that
requires natural gas utilities to provide "bundled basic gas service"
(including transmission, storage, distribution, purchasing, revenue-
cycle services and after-meter services) to all core customers, unless
the customer chooses to purchase gas from a nonutility provider. The
law prohibits the CPUC from unbundling distribution-related gas
services (including meter reading and billing) and after-meter
services (including leak investigation, inspecting customer piping and
appliances, pilot relighting and carbon monoxide investigation) for
most customers. The objective is to preserve both customer safety and
customer choice.
18
Supply/demand imbalances are affecting the price of
natural gas in California more than in the rest of the country
because of California's dependence on natural gas fired
electric generation due to air-quality considerations. The
average price of natural gas at the California/Arizona (CA/AZ)
border was $6.25/mmbtu in 2000, compared with $2.33/mmbtu in
1999. On December 11, 2000, the average spot-market price at
the CA/AZ border reached a record high of $56.91/mmbtu.
Underlying the high natural gas prices are several factors,
including the increase in natural gas usage for electric
generation, cold winter weather and reduced natural gas supply
resulting from historically low storage levels, lower gas
production and a major pipeline rupture. In December 2000,
SoCalGas filed with the Federal Energy Regulatory Commission
(FERC) for a reinstitution of price caps on short-term
interstate capacity to the CA/AZ border and between the
interstate pipelines and California's local distribution
companies, effective until March 31, 2001. The FERC responded
by issuing extensive data requests, but has not otherwise acted
on SoCalGas' request.
A recent lawsuit, which seeks class-action certification, alleges
that SoCalGas, Sempra Energy, 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 cheaper natural gas
supplies into California. SoCalGas believes the allegations are
without merit.
Performance-Based Regulation (PBR)
To promote efficient operations and improved productivity and to move
away from reasonableness reviews and potential 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 tochanges will be tied to
achieving or exceeding specific performance and productivity goals, as
well as cost reductions, rather than by relying solely on expanding
utility plant in a market where a utility already has a highly
developed infrastructure. See additional discussion of PBR in "Results
of Operations" above and in Note 12 of the notes to Consolidated
Financial Statements.implemented during 2002.
Allowed Rate of Return
For 2001,
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 20002001 and 1999.2000. These rates will continue to be
effective until the next periodic review by the CPUC unless interest-
rate changes 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 SoCalGas' core sales.
Management ControlUtility Integration
On September 20, 2001 the CPUC approved Sempra Energy's request to
integrate the management teams of ExpensesSoCalGas and Investment
InSDG&E. The decision
retains the past,separate identities of each utility and is not a merger.
Instead, utility integration is a reorganization that consolidates
senior management has been able to control operating expenses
and investment within the amounts authorized to be collected in rates.
It is the intent of management to control operating expenses and
investments within the amounts authorized to be collected in rates in
the PBR decision. SoCalGas intends to make the efficiency
improvements, changes in operations and cost reductions necessary to
achieve this objective and earn at least its authorized rates of
19
return. However, in viewfunctions of the earnings-sharing mechanismtwo utilities and other
elements of the PBR, it is more difficult to exceed authorized returns to the
degree experienced priorutilities 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 the inception of PBR. See
additional discussion of PBR aboveresult in
more efficient and in Note 12 of the noteseffective operations.
In a related development, a CPUC draft decision would allow
SoCalGas and SDG&E to Consolidated Financial Statements.
Noncore Bypass
SoCalGas is at risk for 25-percent of the revenue related reductions
in noncore volumes due to bypass. However, significant bypass would
require construction of additional facilities by competing pipelines.
SoCalGas has not had a material reduction in earnings from bypass and
it is continuing to reduce its costs to remain competitive and to
retain its transportation customers.
Noncore Pricing
To respond to bypass, SoCalGas received authorization from the CPUC
for expedited review of long-termcombine their natural gas transportation service
contracts with some noncore customersprocurement
activities. The CPUC is scheduled to act on the draft decision at fixed transportation rates,
some of which are at lower than the otherwise-applicable tariff rates.
In addition, the CPUC approved changes in the methodology that reduced
the subsidization of core customer rates by noncore customers. This
allocation modification, together with negotiating authority, has
enabled SoCalGas to better compete with new interstate pipelines for
noncore customers.
Noncore Throughput
SoCalGas' earnings will be adversely impacted if natural gas
throughput to its
noncore customers varies from estimates adopted by
the CPUC in establishing rates. There is a continuing risk that an
unfavorable variance in noncore volumes may result from external
factors such as weather, electric deregulation, the increased use of
hydroelectric power, competing pipeline bypass of SoCalGas' system and
a downturn in general economic conditions. In addition, many noncore
customers are especially sensitive to the price relationship between
natural gas and alternate fuels, as they are capable of readily
switching from one fuel to another, subject to air-quality
regulations. SoCalGas is at risk for 25-percent of the lost revenue.
Through July 31, 1999, some of the favorable earnings effect of
higher revenues resulting from higher throughput to noncore customers
was limited as a result of the Comprehensive Settlement. The
settlement addressed a number of regulatory issues and was approved by
the CPUC in July 1994. This treatment has been replaced by the PBR
mechanism as adopted in the 1999 BCAP whereby revenue fluctuations
will impact earnings (positively or negatively). See Note 12 of the
notes to Consolidated Financial Statements for further discussion.
Excess Interstate Pipeline Capacity
SoCalGas has exercised its step-down option on both the El Paso and
Transwestern systems, thereby reducing its firm interstate capacity
obligation from 2.25 Bcf per day to 1.45 Bcf per day.
20
FERC-approved settlements have resulted in a reduction in the
costs that SoCalGas possibly may have been required to pay for the
capacity released back to El Paso and Transwestern. Of the remaining
1.45 Bcf per day of capacity, SoCalGas' core customers
use 1.05 Bcf per day at the full FERC tariff rate. The remaining 0.40
Bcf per day of capacity is sold in the secondary market. Under
existing California regulation, unsubscribed capacity costs associated
with the remaining 0.40 Bcf per day are recoverable in customer rates.
While including the unsubscribed pipeline cost in rates may impact
SoCalGas' ability to compete in competitive markets, SoCalGas does not
believe its inclusion will have a significant impact on volumes
transported or sold.April 4, 2002 meeting.
Environmental Matters
The Company'scompany'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 wastesolid-waste disposal and the
protection of wildlife.
Because the environmental issues faced by the Company are in
connection with SoCalGas' operations,Utility capital costs to comply with environmental requirements
are generally recovered through the
depreciation components of customer rates. SoCalGas' customers
generally are responsible for 90-percent of the non-capital costs
associated with hazardous substances and the normal operating costs
associated with safeguarding air and water quality, disposing properly
of solid waste, and protecting endangered species and other wildlife. Therefore, the
likelihood of the Company'scompany'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 Companycompany or resolved
during the latest three-year period include investigation and
remediation of SoCalGas'its manufactured-gas sites (18 completed as of
December 31, 2000 and 24 to be completed) and cleanup of third-party
waste disposalwaste-disposal sites used by the Company, which has been identified as
a Potentially Responsible Party (investigations and remediations are
continuing).company. See additional discussions
of environmental issues in Note 11 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, and in interest rates.
The Company'scompany's policy is to use derivative financial instruments
to reduce its exposure to fluctuations in interest rates foreign-
currency exchange rates and energynatural
gas prices. Transactions involving these financial instruments are
with firms believed to be credit-worthy firms and major exchanges. The use
of these instruments exposes the Companycompany 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, with maturities ranging from 30 days to
12 months.contracts. In the case of both price-risk management
and trading activities, the use of derivative financial instruments by
the Companycompany is subject to certain limitations imposed by established Companycompany
policy and regulatory requirements. See Note 8 of the notes to
Consolidated Financial Statements and the "Market Risk Management
Activities" section below for further information regarding
the use of energy derivatives by the Company.
21
Market-Risk Management Activities
Market risk is the risk of erosion of the Company's cash flows, net
income and asset values due to adverse changes in interest and
foreign-currency rates, and in prices for equity and energy.company.
Sempra Energy has adopted corporate-wide policies governing its
market-risk management and trading activities. An Energy Risk
Management Oversight Committee, consisting of senior officers,
oversees company-wide energy-price risk-management and tradingenergy risk management activities to ensure
compliance with Sempra Energy's stated energy-risk-energy-risk management and
trading policies. In addition, all affiliates have groups that
monitorSoCalGas' risk-management committee
monitors and controlcontrols energy-price risk management and trading
activities independently from the groupsemployees responsible for creating
or actively managing these risks.
Along with other tools, the Companycompany 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 level.interval. The Companycompany has adopted the
variance/covariance methodology in its calculation of VaR, and uses
aboth the 95-percent and 99-percent confidence level.interval. Holding
periods are specific to the types of positions being measured, and are
determined based on the size of the position or portfolios, market
liquidity, purpose and other factors. Historical volatilities and
correlations between instruments and positions are used in the
calculation. As of December 31, 2001, the VaR of SoCalGas' natural gas
positions was not material.
The following discussion of the Company'scompany's primary market-risk
exposures as of December 31, 2000,2001, includes afurther discussion of how
these exposures are managed.
Commodity-Price Risk
Market risk related to physical commodities is based upon potential
fluctuations 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 gas or related financial instruments are
traded. The company is exposed, in varying degrees, to price risk 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' market risk exposure is limited due to CPUC-authorized
rate recovery of natural gas purchase, sale and storage activity.
However, at times it may be exposed to limited market risk as a result
of activities under the Gas Cost Incentive Mechanism (GCIM), which is
discussed in Note 12 of the notes to Consolidated Financial
Statements. SoCalGas manages this risk within the parameters of the
company's market-risk management and trading framework.
Interest-Rate Risk
The Companycompany is exposed to fluctuations in interest rates primarily as
a result of its fixed-rate long-term debt. The Companycompany has
historically funded utility operations through long-term bonddebt 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 has been permitted within the debt-
managementdebt-management
process. As a result, 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.
The VaRAt December 31, 2001, SoCalGas had $508 million of fixed-rate debt
and $175 million of variable-rate debt. Interest on the Company's fixed-rate long-termutility
debt is estimated
at approximately $107 million as offully 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, 2000, assuming2001, SoCalGas' fixed-rate debt had a one-
year holding period.
Energy-Price Risk
Market risk related to physical commodities is based upon potential
fluctuations in natural gas pricesone-year
VaR of $96 million and basis. The Company's market
risk is impacted by changes in volatilitySoCalGas variable-rate debt had a one-year VaR
of $1 million.
At December 31, 2001, the notional amount of interest-rate swap
transactions totaled $175 million. See Notes 4 and liquidity in the markets
in which these instruments are traded. The Company is exposed, in
varying degrees, to price risk in the natural gas markets. The
Company's policy is to manage this risk within a framework that
considers the unique markets, operating and regulatory environment.
22
Market Risk
SoCalGas may, at times, be exposed to limited market risk in its
natural gas purchase, sale and storage activities as a result of
activities under the Gas Cost Incentive Mechanism. SoCalGas manages
this risk within the parameters8 of the Company's market-risk
management and trading framework. As of December 31, 2000, the total
VaR of SoCalGas' natural gas positions was not material.notes to
Consolidated Financial Statements for further information regarding
these swap transactions.
Credit Risk
Credit risk relates to the risk of loss that would be incurred as a
result of nonperformance by counterparties pursuant to the terms of
their contractual obligations. The Companycompany avoids concentration of
counterparties and maintains credit policies with regard to
counterparties that management believes significantly minimize 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.
The Companycompany monitors credit risk through a credit-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.
Almost allThe company periodically enters into interest-rate swap agreements
to moderate exposure to interest-rate changes and to lower the overall
cost of SoCalGas' accounts receivableborrowing. The company would be exposed to interest-rate
fluctuations on the underlying debt should other parties to the
agreement not perform.
Critical Accounting Policies
The company's most significant accounting policies are with customers
located in California and, therefore, potentially affected by the high
costs of electricity and natural gas in California, as described in
"Factors Influencing Future Performance" and in Note 122 of the notes to Consolidated Financial Statements. The most
critical policies are Statement 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 policies
are mandatory under generally accepted accounting principles and the
regulations of the Securities and Exchange Commission. Each of these
policies has a material effect on the timing of revenue and expense
recognition for significant company operations.
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 the calculation of fair
values, and the collectibility of regulatory and other assets. 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. 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 other parties and other factors.
New Accounting Standards
Effective January 1, 2001, the Companycompany adopted Statement of Financial
Accounting Standards (SFAS)SFAS No. 133
"Accounting for Derivative Instruments and Hedging Activities," 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 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 exposures.exposure.
The company utilizes derivative financial instruments to reduce
its exposure to unfavorable changes in energy 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 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 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 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 January 1, 2001, did not
impact the Company'scompany'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 SheetSheets 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 Sheet.Sheets. See Note 8 of the notes to Consolidated
Financial Statements for additional information on the effects of SFAS
133 on the financial statements at December 31, 2001. The ongoing
effects will depend on future market conditions and the Company'scompany's
hedging activities.
23
In December 1999,July 2001, the SecuritiesFinancial Accounting Standards Board (FASB)
issued three statements, SFAS 141 "Business Combinations," SFAS 142
"Goodwill and Exchange Commission (SEC)
issued Staff Accounting Bulletin (SAB) 101 - Revenue Recognition. SABsOther Intangible Assets" and SFAS 143 "Accounting for
Asset Retirement Obligations." The first two are not rules issued bypresently
relevant to the SEC. Rather, they represent
interpretationscompany.
SFAS 143 addresses financial accounting and practices followed byreporting for
obligations associated with the SEC's staffretirement 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 liability for an asset retirement obligation in
administering the disclosure requirementsperiod in which it is incurred. When the liability is initially
recorded, the entity increases the carrying amount of the federal securities
laws. SAB 101 provides guidance onrelated
long-lived asset to reflect the recognition, presentationfuture retirement cost. Over time, the
liability is accreted to its present value and disclosure of revenue in financial statements; it does not changepaid, and the
existing rules on revenue recognition. SAB 101 sets forthcapitalized cost is depreciated over the basic
criteria that must be met before revenue should be recorded.
Implementation of SAB 101 was required by the fourth quarter of 2000
and had no effect on the Company's consolidated financial statements.
Information Regarding Forward-Looking Statements
This Annual Report contains statements that are not historical fact
and constitute forward-looking statements within the meaninguseful life of the Private Securities Litigation Reform Actrelated
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 1995. The words
"estimates,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." "believes," "expects," "anticipates," "plans," "intends,"
"may," "would" and "should"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 similar expressions,fair value less cost to sell. Discontinued
operations will no longer be measured at net realizable value or
discussionsinclude amounts for operating losses that have not yet occurred. SFAS
144 also broadens the reporting of strategy ordiscontinued operations to include
all components 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 materiallyan entity with operations that can be distinguished
from those expressed in these forward-
looking statements.
Forward-looking statements are necessarily based upon various
assumptions involving judgments with respect to the future and other
risks, including, among others, local, regional, national and
international economic, competitive, political, legislative and
regulatory conditions; actions by the CPUC, the California Legislature
and the FERC; the financial condition of other investor-owned
utilities; inflation rates and interest rates; energy markets,
including the timing and extent of changes in commodity prices;
weather conditions; business, regulatory and legal decisions; the pace
of deregulation of retail natural gas and electricity delivery; the
timing and success of business-development efforts; and other
uncertainties, all of which are difficult to predict and many of which
are beyond the controlrest of the Company. Readersentity and that will be eliminated from the
ongoing operations of the entity in a disposal transaction. The
provisions of SFAS 144 are cautionedeffective for fiscal years beginning after
December 15, 2001. The company has not to
rely undulyyet determined the effect of
SFAS 144 on any forward-looking statements and are urged to review
and consider carefully the risks, uncertainties and other factors
which affect the Company's business described in this Annual Report
and other reports filed by the Company from time to time with the SEC.its financial statements.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKRISK.
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 Management Activities.Risk."
24
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - Pacific
Enterprises
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders of Pacific Enterprises:
We have audited the accompanying consolidated balance sheets of
Pacific Enterprises and subsidiaries as of December 31, 20002001 and 1999,2000,
and the related statements of consolidated income, cash flows and
changes in shareholders' equity and cash flows for each of the three years in the
period ended December 31, 2000.2001. 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 auditing standards
generally accepted in the United States of America. 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 subsidiaries as of December 31, 20002001 and 1999,2000, and the
results of their operations and their cash flows for each of the three
years in the period ended December 31, 20002001, in conformity with
accounting principles generally accepted in the United States of
America.
/s//S/ DELOITTE & TOUCHE LLP
San Diego, California
January 26, 2001 (February 27, 2001,February 4, 2002 (March 5, 2002 as to Note 3)
25
12)
PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
Dollars in millions
For the yearsYears ended December 31 2001 2000 1999 1998
------ ------ ------
Operating Revenues $3,716 $2,854 $2,569 $2,472
------ ------ ------
Operating Expenses
Cost of natural gas distributed 2,117 1,361 1,033
840
Operation & maintenanceOther operating expenses 794 696 748
930
Depreciation 268 263 261
259
Income taxes 167 175 163 125
Other taxes and franchise payments 101 96 93 100
------ ------ ------
Total operating expenses 3,447 2,591 2,298 2,254
------ ------ ------
Operating Income 269 263 271 218
------ ------ ------
Other Income and (Deductions)
Interest income 40 64 40
19
Regulatory interest (19) (12) (14) --
Allowance for equity funds used during construction 6 3 -- 3
Taxes on non-operating income (4) (10) (3) (2)
Preferred dividends of subsidiaries (1) (1) (1)
Other - net 1 3 (21) (20)
------ ------ ------
Total 23 47 1 (1)
------ ------ ------
Income Before Interest Charges 310 272 217
------ ------ ------
Interest Charges
Long-term debt 63 68 82
84
Other 25 33 8 (13)
Allowance for borrowed funds used during construction (2) (2) (1)(2)
------ ------ ------
Total 86 99 88 70
------ ------ ------
Net Income 206 211 184 147
Preferred Dividend Requirements 4 4 4
------ ------ ------
Earnings Applicable to Common Shares $ 202 $ 207 $ 180 $ 143
====== ====== ======
See notes to Consolidated Financial Statements.
26
PACIFIC ENTERPRISES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Dollars in millions
Balance at December 31 2001 2000 1999
-------- --------
ASSETS
Property, plant and equipment $6,590 $6,337 $6,190
Accumulated depreciation (3,793) (3,571)
(3,352)
-------- -------------- ------
Property, plant and equipment - net 2,797 2,766
2,838
-------- -------------- ------
Current assetsassets:
Cash and cash equivalents 13 205 11
Accounts receivable - trade (less allowance for doubtful
receivables of $19 in 2000 and $16 in 1999)415 589
281
Accounts and notes receivable - other 14 83 14
Due from unconsolidated affiliates -- 214 73
Income taxes receivable 20 -- 34
Deferred income taxes 33 43
Regulatory assets arising from fixed-price
contracts and other derivatives 103 --
Other regulatory assets -- 24
Fixed-price contracts and other derivatives 59 --
Inventories 42 67
78
Other 4 84
9
----- ----------- ------
Total current assets 1,285 500
----- -----703 1,309
------ ------
Other assets:
Due from unconsolidated affiliates 409 617
Regulatory assets 108 201
Notes receivable - affiliate 617 482
Investmentsarising from fixed-price
contracts and other derivatives 157 --
Other regulatory assets -- 12
Sundry 125 52 89
------ ------
777 772
------ ------
Total $4,828 $4,110other assets 691 681
------ ------
Total assets $4,191 $4,756
====== ======
See notes to Consolidated Financial Statements.
27
PACIFIC ENTERPRISES AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Dollars in millions
Balance at December 31 2001 2000 1999
-------- --------
CAPITALIZATION AND LIABILITIES
CapitalizationCapitalization:
Common Stock $1,282(600,000,000 shares authorized;
83,917,664 shares outstanding) $1,317 $1,282
Retained earnings 177 165 58
Accumulated other comprehensive income (loss) -- (1)
6
-------- -------------- ------
Total common equity 1,494 1,446 1,346
Preferred stock 80 80
------ ------
Total shareholder's equity 1,574 1,526
Long-term debt 579 821
939
-------- -------------- ------
Total capitalization 2,153 2,347
2,365
-------- -------------- ------
Current liabilitiesliabilities:
Short-term debt 50 --
Current portion of long-term debt 100 120
Accounts payable - trade 160 368 160
Accounts payable - other 81 43
60Due to unconsolidated affiliates 168 365
Regulatory balancing accounts - net 463 15485 465
Income taxes payable 50 -- Deferred income taxes -- 850
Dividends and interest payable 31 28
29
Current portion of long-term debt 120 30
Due to affiliates 365 327Regulatory liabilities 18 --
Fixed-price contracts and other derivatives 103 --
Other 300 206
-------- --------390 321
------ ------
Total current liabilities 1,737 974
-------- --------1,186 1,760
------ ------
Deferred credits and other liabilities:
Customer advances for construction 24 16
Post-retirement benefits other than pensions 88 97
Deferred income taxes 110 150
Deferred investment tax credits 50 53
Regulatory liabilities 86 --
Fixed-price contracts and other derivatives 162 --
Deferred credits and other liabilities Customer advances for construction 16 27
Post-retirement benefits other than pensions 97 101
Deferred income taxes 224 223
Deferred investment tax credits 53 56
Deferred credits and other liabilities 334 344312 313
Preferred stock of subsidiary 20 20
-------- -------------- ------
Total deferred credits and other liabilities 744 771
-------- --------852 649
------ ------
Contingencies and commitments (Note 11)
Total $4,828 $4,110
======== ========liabilities and shareholder's equity $4,191 $4,756
====== ======
See notes to Consolidated Financial Statements.
28
PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
Dollars in millions
For the yearsYears ended December 31 2001 2000 1999 1998
------ ------ ------
Cash Flows from Operating Activities
Net Income $211$ 206 $ 211 $ 184 $ 147
Adjustments to reconcile net income to net
cash provided by operating activitiesactivities:
Depreciation 268 263 261 259
Deferred income taxes and investment
tax credits 24 5 135
(180)
Other 22(Increase) decrease in other assets (12) 40 11
Increase (decrease) in other liabilities 32 (16) 33 (71)
Changes in working capital componentscomponents:
Accounts and notes receivable 244 (377) 158
68Income taxes receivable/payable (71) 84 (59)
Fixed-price contracts and other derivatives 16 -- --
Inventories 25 11 (18)
Other current assets 4 (75) (2)
Accounts payable (171) 191 (19)
Due to/from affiliates 5 35 (39) (92)
Income taxes receivable/payable 84 (59) (19)
Inventories 11 (18) (24)
Other current assets (75) (2) 2
Accounts payable 191 (19) (29)
Regulatory balancing accounts (380) 309 36
484
Other taxes payable -- (3) 2Regulatory assets and liabilities 39 (2) (2)
Other current liabilities 71 93 13 5110
------ ------ ------
Net cash provided by operating activities 300 772 680 598689
------ ------ ------
Cash Flows from Investing Activities
Capital expenditures (294) (198) (146)
(150)
Loans torepaid by (paid to) affiliates 220 (267) (336) --
Other - net -- 21 8 (39)(1)
------ ------ ------
Net cash used in investing activities (74) (444) (474) (189)(483)
------ ------ ------
Cash Flows from Financing Activities
Common dividends paid (190) (100) (100) (97)
Preferred dividends paid (4) (4) (4)
Issuance ofPayments on long-term debt -- -- 75
Payment of long-term debt(270) (30) (75) (150)
Increase (decrease) in short-term debt 50 -- (43)
(311)
Sale of common stockOther (4) -- -- 27
Redemption of preferred stock of a subsidiary -- -- (75)
------ ------ ------
Net cash used in financing activities (418) (134) (222) (535)
------ ------ ------
Increase (decrease) in cash and cash equivalents (192) 194 (16) (126)
Cash and cash equivalents, January 1 205 11 27 153
------ ------ ------
Cash and cash equivalents, December 31 $ 13 $ 205 $ 11 $ 27
====== ====== ======
Supplemental Disclosure of Cash Flow Information:
Interest payments, net of amounts capitalized $ 83 $ 127 $ 90
====== ====== ======
Income tax payments, net of refunds $ 209 $ 99 $ 92
$ 263
====== ====== ======
Interest payments, net of amount capitalized $ 127 $ 90 $ 72
====== ====== ======See notes to Consolidated Financial Statements
PACIFIC ENTERPRISES 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 to Sempra Energy $ -- $ 417-- $ 23417
====== ====== ======
Capital contribution from Sempra Energy $ -- $ 85-- $ 2685
====== ====== ======
See notes to Consolidated Financial Statements.
29
PACIFIC ENTERPRISES AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
For the yearsYears ended December 31, 2001, 2000 and 1999 1998
Dollars in millions
| Deferred Accumulated
|
Compensation Other Total
Comprehensive | Preferred Common Retained Relating Comprehensive Shareholders'
Income | Stock Stock Earnings to ESOP Income (Loss)Income(Loss) Equity
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 |1998 $ 80 $1,064 $372 $(47) $1,469
Net income/comprehensive income $147 | 147 147
Preferred stock dividends |
declared | (4) (4)
Common stock dividends |
declared | (120) (120)
Capital contribution | 26 26
Sale of common stock | 27 27
Common stock released |
from ESOP | 2 2
- ----------------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 | 80 1,117 395 (45) 1,547$1,117 $395 $(45) $1,547
Net income 184 |$184 184 184
Other 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 |$211 211 211
Other comprehensive income (loss):
|
Available-for-sale |
securities (10)| (10) (10)
Pension 3 | 3 3
------ |-----
Comprehensive income $204
|=====
Preferred stock dividends
|
declared | (4) (4)
Common stock dividends
|
declared | (100) (100)
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 80 1,282 165 -- (1) 1,526
Net income $206 206 206
Other comprehensive income (loss):
Other 1 1 1
-----
Comprehensive income $207
=====
Quasi-reorganization
adjustment (Note 2) 35 35
Preferred stock dividends
declared (4) (4)
Common stock dividends
declared (190) (190)
----------------------------------------------------------------------
Balance at December 31, 2001 $ 80 $1,282$1,317 $ 165177 $ -- $ (1) $1,526
================================================================================================================-- $1,574
============================================================================================================
See notes to Consolidated Financial Statements.
30
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1:1. BUSINESS COMBINATION
On June 26, 1998,Sempra Energy was formed as a holding company for Pacific Enterprises
(PE) the parent company of Southern California Gas Company (SoCalGas)
and Enova Corporation (Enova), the parent company of San Diego Gas &
Electric (SDG&E), and Pacific Enterprises (PE or the
Company), parent company of Southern California Gas Company
(SoCalGas), combined intoin connection with a new company named Sempra Energy (Parent).business combination that was
completed on June 26, 1998. As a result of the combination, (i) each
outstanding share of common stock of Enova was converted into one
share of common stock of Sempra Energy, (ii)and each outstanding share of
common stock of PE was converted into 1.5038 shares of common stock of
Sempra Energy and
(iii) the preferred stock and preference stock of the combining
companies and their subsidiaries remained outstanding.Energy.
As a result of the business combination, PE dividended its
nonutility subsidiaries to Sempra Energy during 1998 and early 1999.
SoCalGas is now the sole direct subsidiary of PE.
NOTE 2:2. SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The Consolidated Financial Statements include the accounts of PE and
its wholly owned subsidiaries. The Company's policy is to consolidate
all subsidiaries that are more than 50 percent owned and controlled.
All material intercompany accounts and transactions have been
eliminated.
As a subsidiary of Sempra Energy, the Companycompany receives certain
services therefrom. Although it is charged its allocable share of the
cost of such services, that cost is believed to be less than if the
Companycompany had to provide those services itself.
Effects of Regulation
The accounting policies of SoCalGas,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).
SoCalGasThe 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 werecease to be no longer subject to SFAS
No. 71, or recovery was to beis 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 the effects of regulation on the
Companyregulatory matters is providedincluded in Note 12.
31
RevenuesRegulatory 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 Balancing Accounts
Revenues from utility customersassets (liabilities) as of December 31 consist of deliveries to customersthe
following (dollars in millions):
2001 2000
------ ------
SoCalGas
----------
Environmental remediation $ 55 $ 58
Fixed-price contracts and the changes in regulatory balancing accounts. Balancing accounts
eliminate from earnings most of the fluctuations in prices and volumes
of natural gas by adjusting future rates to recover shortfalls from
customers or to return excess collections to customers.
Regulatory Assets
Regulatory assets include unrecovered premiumsother
derivatives 257 --
Unamortized loss on early 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 other expendituresthe
assets are offset by liabilities that the Company expects to recoverdo 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 future rates. See Note 12 for additional information.2001, 2000 and 1999, respectively.
Inventories
Included in inventoriesAt 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, of
materialsrespectively.
Natural gas is valued by the last-in first-out (LIFO) method. When the
inventory is consumed, differences between this LIFO valuation and
supplies ($11 millionreplacement cost will be reflected in 1999), and $56 million of
natural gas ($67 million in 1999).customer rates. Materials and
supplies are generally valued at the lower of average cost or market; natural gas
is valued by the last-in first-out method.
Loans to Affiliatemarket.
Due to/from Unconsolidated Affiliates
PE has promissory notes receivabledue from Sempra Energy. The notesEnergy and from Sempra Energy
Global Enterprises (Global) which bear variable interest rates based
on short-term commercial paper rates, and are due on
demand. Therates. These notes receivable were $702$268 million
and $448$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 1999, respectively.$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
ThisUtility plant primarily represents the buildings, equipment and other
facilities used by SoCalGas to provide natural gas utility service.
The cost of utility plant includes labor, materials, contract
services and related items, and an allowance for funds used during
construction.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
provisionsprovision for depreciation as a percentage of average depreciable
utility plant was 4.33, 4.36 and 4.39 4.36
in 2001, 2000 and 1999,
and 1998, respectively. AllowanceSee Note 12 for Funds Used During Construction (AFUDC)
The allowancediscussion of industry restructuring.
Maintenance costs are expensed as incurred.
AFUDC, which represents the cost of funds used to finance the
construction of utility plant, and 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.
32
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, and unrealized gains and losses on marketable
securities that are classified as available-
for-sale. At December 31, 1999, the Company had one such investment,
which increased in value during 1999. In October 2000, this investment
was sold. These changesavailable-for-sale, and certain
hedging activities. The components of other comprehensive income are
reflectedshown in the StatementStatements of Consolidated Changes in Shareholders'
Equity.
Quasi ReorganizationQuasi-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 effectiveas of December 31, 1992. Certain of the liabilities
established in connection with the quasi-reorganization, wereincluding
various income-tax issues, have been favorably resolved in November 1999, including unitary tax
issues.resolved. Excess
reservesliabilities of $35 million and $80 million resulting from the
favorable resolution of these issues were addedrestored to shareholders'
equity at that
time. Otherin December 2001 and November 1999, respectively, but did not
affect the calculation of net income. The remaining liabilities established in connection with discontinued
operations and the quasi-reorganization will
be resolved in future years. Management believes the provisions
established for these matters are adequate.
Use of Estimates in the Preparation of the Financial Statements
The preparation of the consolidated financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of assets and
liabilities, and the disclosure of contingent assets and liabilities
at the date of the financial statements, and the reported amounts of
revenues and expenses during the reporting period. Actual results couldcan
differ significantly from those estimates.
Cash and Cash Equivalents
Cash equivalents are highly liquid investments with original maturities of
three months or less at the date of purchase.
Basis of Presentation
Certain prior-year amounts have been reclassified to conform to the
current year's presentation.
New Accounting Standards
Effective January 1, 2001, the Companycompany adopted Statement of
Financial Accounting Standards (SFAS)SFAS No. 133
"Accounting for Derivative Instruments and Hedging Activities," 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 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.
33
The company utilizes derivative financial instruments to reduce
its exposure to unfavorable changes in energy prices, which are
subject to significant 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 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, but not reflected in the
Statements of Consolidated 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
recorded in the Statements of Consolidated Income.
The adoption of this new standard on January 1, 2001, did not
impact the Company'scompany'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 SheetSheets 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 in the Consolidated Balance Sheets as
of January 1, 2001, in2001. See Note 8 for additional information on the
Consolidated Balance Sheet.effects of SFAS 133 on the financial statements at December 31, 2001.
The ongoing effects will depend on future market conditions and the
Company'scompany's hedging activities.
In December 1999,July 2001, the SecuritiesFinancial Accounting Standards Board (FASB)
issued three statements, SFAS 141 "Business Combinations," SFAS 142
"Goodwill and Exchange Commission
(SEC) issued Staff Accounting Bulletin (SAB) 101 - Revenue
Recognition. SABsOther Intangible Assets" and SFAS 143 "Accounting for
Asset Retirement Obligations." The first two are not rules issued bypresently
relevant to the SEC. Rather, they
represent interpretationscompany.
SFAS 143 addresses financial accounting and practices followed byreporting for
obligations associated with the SEC's
staffretirement 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 liability for an asset retirement obligation in
administering the disclosure requirementsperiod in which it is incurred. When the liability is initially
recorded, the entity increases the carrying amount of the federal
securities laws. SAB 101 provides guidancerelated
long-lived asset to reflect the future 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. 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 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 recognition,
presentation and disclosure of revenue in financial statements; it
does not change the existing rules on revenue recognition. SAB 101
sets forth the basic criteria that must be met before revenue
should be recorded. Implementation of SAB 101 was required by the
fourth quarter of 2000 and had no effect on the Company's
consolidatedcompany's financial
statements.
NOTE 3:3. SHORT-TERM BORROWINGS
At December 31, 2000,2001, PE had a $500 million two-year revolving line of
credit, 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.
Borrowings 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, should Sempra Energy's or
SoCalGas' debt-to-total capitalization ratios (as defined in the
agreement) exceed 65 percent, or should there be a change in law
materially and adversely affecting the ability of SoCalGas to pay
dividends or make distributions to PE. Borrowings would bear interest
at rates varying with market rates and the amount of the outstanding
borrowings. PE's line of credit was unused at December 31, 2001.
At December 31, 2001, SoCalGas had a $200$170 million syndicated
revolving line of credit, agreement, which wasis available to support commercial
paper. At
December 31, 2000, and 1999, SoCalGas' lines of credit were
unused. On February 9, 2001,Borrowings under the agreement, expired and was
replacedwhich expires on February 27, 2001, with a $170 million one-year
agreement. This agreement bearsMay 26, 2002,
would bear interest at various rates based on market rates and
SoCalGas' credit rating. 34
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.
The company's weighted average interest rate for short-term
borrowings outstanding at December 31, 2001 was 2.04%.
NOTE 4:4. LONG-TERM DEBT
- --------------------------------------------------------------
December 31,
(Dollars in millions) 2001 2000 1999
- --------------------------------------------------------------
First-Mortgage BondsFirst-mortgage bonds
6.875% August 15, 2002 $ 100 $ 100
5.750%5.75% November 15, 2003 100 100
8.750% October 1, 2021 150 150
7.375% March 1, 2023 100 100
7.500%7.5% June 15, 2023 125 125
6.875%Variable rates November 1, 2025
(1.95% at December 31, 2001) 175 175
8.75% October 1, 2021 -- 150
-----------------------
750600 750
-----------------------
Unsecured Long-Term Debtlong-term debt
5.67% January 18, 2028 75 75
6.375% Notes,May 14, 2006 8 8
6.375% October 29, 2001 -- 120
120
5.670% Notes, January 15, 2028 75 75
SFr. 15,695,000 6.375% Foreign
Interest Payment Securities 8 8
8.750% Notes, July 6, 2000 - 30
-----------------------
83 203 233
-----------------------
Total 683 953 983
Less:
Current portion of long-term debt 100 120 30
Unamortized discount on
long-term debt - 12
14Market value adjustment on
Interest-rate swap 4 -
-----------------------
Total $ 821579 $ 939821
- --------------------------------------------------------------
Maturities of long-term debt are $120 million in 2001, $100 million in 2002, $175 million in
2003 and $558$408 million after 2005. SoCalGas has
CPUC authorization to issue an additional $455 million in long-term
debt.
First-Mortgage2006.
First-mortgage Bonds
First-mortgage bonds are secured by a lien on substantially all utility plant. SoCalGas
may issue additional first-mortgage bonds upon compliance with the
provisions of its bond indenture,indentures, which permit,require, among other things,
the satisfaction of pro forma earnings-coverage tests on first-
mortgage bond interest and the availability of sufficient mortgaged
property to support the additional bonds. The most restrictive of
these tests (the property test) would permit the issuance, subject to
CPUC authorization, of an additional $585$753 million of first-mortgage
bonds as of December 31, 2000, subject to CPUC
authorization.2001.
In November 2001, 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-mortgage bonds for a floating rate. Additional
information is provided under "Interest-Rate Swaps" below.
Unsecured Long-TermLong-term Debt
Various long-term obligations totaling $83 million are unsecured at
December 31, 2001. In July 2000,October 2001, SoCalGas repaid $30$120 million of
8.756.38 percent medium-term notes upon maturity.
In May 1996, SoCalGas issued SFr. 15,695,000 ($8 million) of
6.375% Foreign Interest Payment Securities. The securities are
renewable at ten-year intervals at reset interest rates. The next put
date for the securities is May 14, 2006.
35
Callable Bonds
At SoCalGas' option, certain fixed-rate bonds may be called at a
premium. $150premium, including $400 million that are callable in 2003 and $8
million in 2006.
Interest-Rate Swaps
SoCalGas periodically enters into interest-rate swap agreements to
moderate its exposure to interest-rate changes and to lower its
overall cost of borrowing. At December 31, 2001, the company had one
such swap agreement. On December 11, 2001, SoCalGas executed a
cancelable-call interest-rate swap, exchanging its fixed rate
obligation of 6.875 percent on its $175 million first-mortgage bonds
for a floating rate of LIBOR plus 4 basis points. 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
effective in 2001its purpose of converting the fixed rate stated in the
debt to a floating rate and $400 millionthe swap meets the criteria for accounting
under the short-cut method defined in 2003.
Recent Shelf Registration
In December 2000, PE and Sempra Energy jointly filed a shelf
registrationSFAS no. 133 for the public offering of up to $500 millionfair value
hedges of debt securitiesinstruments. Accordingly, a market value adjustment to
long-term debt of PE, guaranteed by Sempra Energy. Any securities under
this shelf registration are offered on a delayed or continuous basis
pursuant to Rule 415 under the Securities Act of 1933. At$4 million was recorded at December 31, 2000, no debt securities have been issued under this registration
statement.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.
NOTE 5:5. 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 1999 1998
- -----------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 5.4 5.2 7.4 9.9
State income taxes - net of
federal income tax benefit 6.9 6.9 7.3 4.7
Tax credits (0.8) (0.7) (0.9) (1.0)
Other - net (1.1) 0.3 (1.4) (2.2)
-----------------------------
Effective income tax rate 45.4% 46.7% 47.4% 46.4%
- -----------------------------------------------------------------------
The components of income tax expense are as follows:
- -----------------------------------------------------------------------
(Dollars in millions) 2001 2000 1999 1998
- -----------------------------------------------------------------------
Current:
Federal $139$ 116 $ 139 $ 22
$242
State 30 41 9
65
---------------------------------------------------------
Total current taxes146 180 31
307
---------------------------------------------------------
Deferred:
Federal 20 7 113
(139)
State -8 -- 25
(38)
---------------------------------------------------------
Total deferred taxes28 7 138
(177)
---------------------------------------------------------
Deferred investment tax credits - net (3) (2) (3)
(3)
---------------------------------------------------------
Total income tax expense $185 $166 $127$ 171 $ 185 $ 166
- ---------------------------------------------------------------------------------------------------------------------------------------------
Federal and state income taxes are allocated between operating income
and other income. 36
PE is included in the consolidated tax return of
Sempra Energy and is allocated income tax expense from Sempra Energy
in an amount equal to that which would result from filing a separate
return.
Accumulated deferred income taxes at December 31 result from the
following:
- ----------------------------------------------------------------
(Dollars in millions) 2001 2000
1999
- --------------------------------------------------------------------------------------------------------------------------------------
Deferred Tax Liabilities:
Differences in financial and
tax bases of utility plant $ 447295 $ 471373
Regulatory balancing accounts 56 11 16
Regulatory assets 36 39
69
Other 49 11 18
--------------------
Total deferred tax liabilities 508 574436 434
--------------------
Deferred Tax Assets:
Investment tax credits 34 38 39
Comprehensive Settlement (see Note 12) 26 42
Postretirement benefits 36 39 69
Other deferred liabilities 174 143 98
Restructuring costs 4342 43
Other 38 5273 64
--------------------
Total deferred tax assets 359 327 343
--------------------
Net deferred income tax liability $ 18177 $ 231107
- ------------------------------------------------------------------------------------------------------------------------------------
The net deferred income tax liability is recorded on the
Consolidated Balance Sheets at December 31 as follows:
Dollars(Dollars in millionsmillions) 2001 2000
1999
- ------------------------------------------------------------------------------------------------------------------------------------
Current liability (asset)asset $ (33) $ (43)
$ 8
Noncurrent liability 224 223110 150
--------------------
Total $ 18177 $ 231107
- ------------------------------------------------------------------------------------------------------------------------------------
NOTE 6:6. EMPLOYEE BENEFIT PLANS
The information presented below describes the plans of the Company. In
connection with the PE/Enova business combination described in Note 1,
numerous participants have been transferred from the Company's plans
to plans of related entities. In connection with voluntary separations
related to the business combination, the Company recorded a $51
million special termination benefit and a $30 million settlement gain
in 1998.
During 2000, the Company participated in another voluntary
separation program. As a result, the Company recorded a $40 million
special termination benefit in 2000.
Pension and Other Postretirement Benefits
The Companycompany sponsors qualified and nonqualified pension plans and
other postretirement benefit plans for 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 obligations and fair value of assets over the two
years, and a statement of the funded status as of each year end:
37
- ---------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
-----------------------------------------------
(Dollars in millions) 2001 2000 19992001 2000 1999
- ---------------------------------------------------------------------------------
Weighted-Average Assumptions
as of December 31:
Discount rate 7.25% 7.25%(1) 7.75% 7.75% 7.75%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) 7.75%(2)
Change in Benefit Obligation:
Net benefit obligation at
January 1 $1,125 $1,057 $1,156$ 415 $ 408
$ 446
Service cost 25 23 289 8 11
Interest cost 78 84 7732 28 30
Plan participants' contributions - - - 1
Actuarial (gain)loss (46) 79 (120)23 (17)
(62)
Curtailments -- (4) --- 4 -
Transfer of liability (3) - (6) - -
Special termination benefits -- 34 --- 2
-
Gross benefitsBenefits paid (71) (148) (78) (18)(22) (18)
-----------------------------------------------
Net benefit obligation at
December 31 1,111 1,125 1,057457 415 408
-----------------------------------------------
Change in Plan Assets:
Fair value of plan assets
at January 1 1,682 1,971 1,595434 463 379
Actual return on plan assets (162) (141) 453(33) (23) 77
Employer contributions - 1-- -- 13 10 24
Plan participants' contributions - - - 1
Transfer of assets (3) - -3 -- -- 2
-
Gross benefitsBenefits paid (71) (148) (78) (18)(22) (18)
-----------------------------------------------
Fair value of plan assets
at December 31 1,452 1,682 1,971392 434
463
-----------------------------------------------
Funded statusPlan assets net of benefit
obligation at December 31 341 557 914(65) 19 55
Unrecognized net actuarial gain (322) (591) (969)(23) (116) (156)
Unrecognized prior service cost 35 38 45 - --- --
Unrecognized net transition
obligation 2 3 - -2 -- --
-----------------------------------------------
Net recorded asset (liability)
at December 31 $ 56 $ 6 $ (7)(88) $ (97) $(101)
- ---------------------------------------------------------------------------------
(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.
38
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 19992001 2000 1999
- ------------------------------------------------------------------------------------
Prepaid benefit cost $ 67 $ 15 - - --- --
Accrued benefit cost (11) (9) $ (7)$(88) $(97) $(101)
Additional minimum liability (2) (4) (2) - --- --
Intangible asset 1 2 - -1 -- --
Accumulated other
comprehensive income, pretaxpre-tax 1 3 - - --- --
- ------------------------------------------------------------------------------------
Net recorded asset(liability) $ 56 $ 6 $ (7)$(88) $(97) $(101)
- ------------------------------------------------------------------------------------
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 19982001 2000 1999
1998
(Dollars in millions)
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------
Service cost $ 25 $ 23 $ 28 $ 339 $ 8 $ 11
$ 12
Interest cost 78 84 77 9532 28 30 31
Expected return on assets (129) (131) (112) (128)(34) (32) (27) (24)
Amortization of:
Transition obligation 1 1 1 98 9 9
Prior service cost 3 4 4 3 - - --- -- --
Actuarial gain (28) (29) (14) (12)(3) (8) - ---
Special termination benefits -- 33 - 48-- -- 7 - 3
Settlement credit - - (30) - - ---
Regulatory adjustment 51 18 17 -29 28 24
9
-------------------------------------------------------------------------------------------------
Total net periodic benefit cost $ 1 $ 3 $ 1 $ 1041 $ 40 $ 47
$ 40
- ---------------------------------------------------------------------------------------------------------------------------------------------------------------------
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 $ 68 $ (6)
Effect on the health care component of the
accumulated other postretirement benefit $61 $(58)$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, and $12 million and $9 million, respectively, as of
December 31, 1999.
39
2000.
Other postretirement benefits include retiree life insurance,
medical benefits for retirees and their spouses, and Medicare Part B
reimbursement for certain retirees.
Savings Plan
SoCalGas offers a 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 15 percent of their regular
earnings. Employer contributions, afterAfter one year of completed service, are usedthe company begins to
purchase shares of Sempra Energy common stock.make matching contributions. Employer contributions are equal to 50
percent of the first 6 percent of eligible base salary contributed by
employees. The employee'sEmployer contributions atare invested in Sempra Energy common
stock (new issuances or market purchases) and must remain so invested
until termination of employment. At the direction of the employees,
the employee's contributions are primarily invested in Sempra Energy stock,
mutual funds, or institutional trusts. Employer contributions for the
SoCalGas plan are partially funded by the Sempra Energy Employee Stock
Ownership Plan and Trust (formerly the Pacific Enterprises Employee
Stock Ownership Plan and Trust). SoCalGas'Company contributions to the savings
plan were $7 million in 2001, $5 million in 2000 and $6 million in
1999 and $7 million in 1998.1999.
NOTE 7:7. STOCK-BASED COMPENSATION
Sempra Energy has stock-based compensation plans thatintended to align
employee and shareholder objectives related to Sempra Energy's long-termlong-
term growth. The long-term incentive stock compensation plan provides for
aggregateplans permit a wide variety of stock-based awards,
ofincluding Sempra Energy non-qualified stock options, incentive stock
options, restricted stock, stock appreciation rights, performance
awards, stock payments orand dividend equivalents.
In 1995, SFAS No. 123, "Accounting 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
continuescontinue to account for stock-based compensation in accordance with
the provisions of Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees."
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 million, $2 million ($4) million and
$8 million($4 million) in 2001, 2000 1999 and 1998,1999, respectively.
NOTE 8:8. FINANCIAL INSTRUMENTS
Fair Value
The fair values of certain of the Company'scompany's financial instruments
(cash, temporary investments, notes receivable, dividends payable,
short-term debt and long-term debt, customer deposits, and preferred stock) are not
materially different fromdeposits) approximate the carrying
amounts, except for long-term
debt and preferred stock.amounts. The carrying amounts and fair values of
long-term debt were $1.0 billion and $0.9 billion, respectively, at
both December 31, 2000 and December 31, 1999. Thefollowing table provides the carrying amounts and fair
values of the combined preferred stock and preferred stock of
subsidiaries were $100 million and $56 million, respectively,remaining financial instruments at December 31, 2000, and $100 million and $71 million, respectively, at
December 31, 1999.31:
Carrying Fair Carrying Fair
Amount Value Amount Value
(Dollars in millions) 2001 2000
- --------------------------------------------------------------------------
Long-term debt $683 $682 $953 $936
- --------------------------------------------------------------------------
PE:
Preferred stock $ 80 $ 47 $ 80 $ 42
Preferred stock of subsidiary 20 17 20 14
------ ------ ------ ------
$100 $ 64 $100 $ 56
- --------------------------------------------------------------------------
SoCalGas:
Preferred stock $ 22 $ 18 $ 22 $ 15
- --------------------------------------------------------------------------
The fair values of the long-term debt and preferred stock were estimated based on
quoted market prices for them or for similar issues.
40
Off-Balance-Sheet Financial
Accounting for Derivative Activities
Effective January 1, 2001, the company adopted SFAS 133, as amended by
SFAS 138 "Accounting for Certain Derivative Instruments and Certain
Hedging Activities." As amended, SFAS 133 requires that an entity
recognize all derivative instruments 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 instruments
qualifies as an effective hedge that offsets certain exposures.
At December 31, 2001, $59 million in current assets, $1 million
in other noncurrent assets, $103 million in current liabilities and
$162 million in noncurrent liabilities were recorded in the
Consolidated Balance Sheets for fixed-priced contracts and other
derivatives. Regulatory assets and liabilities were established to the
extent that derivative gains and losses are recoverable or payable
through future rates. As such, $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. For the year ended December 31, 2001, $3 million in other
operating income was recorded in the Statements of Consolidated
Income. The Company'sremaining $4 million was a market value adjustment to
long-term debt related to a fixed-to-floating interest rate swap
agreement discussed below.
Changes in the fair value of derivative instruments of $53
million and $72 million for 2001 and 2000, respectively, have
been recognized in the Statements of Consolidated Income under
"cost of natural gas distributed").
Market Risk
The company's policy is to use derivative financial instruments to
manage its exposure to fluctuations in interest rates, foreign-
currencyforeign-currency
exchange rates and energy prices. Transactions involving these
financial instruments exposeare with firms believed to be credit worthy and
major exchanges. The use of these instruments exposes the Companycompany to
market and credit risksrisk, which may at times be concentrated with
certain counterparties, although counterparty nonperformance is not
anticipated.
Energy DerivativesInterest-Rate Risk Management
The Company's regulated operations use energy derivatives for price-
risk management purposes within certain limitations imposed by Company
policies and regulatory requirements.
SoCalGas is subject to price risk on its natural gas purchases if
its cost exceeds a 2 percent tolerance band above the benchmark price.
This is discussed further in Note 12. SoCalGas becomes subject to
price risk when positions are incurred during the buying, selling and
storing of natural gas. As a result of the Gas Cost Incentive
Mechanism (GCIM), SoCalGascompany periodically enters into a certain amountinterest-rate swap agreements to
moderate exposure to interest-rate changes and to lower the overall
cost of natural gas
futures contracts in the open market with the intent of reducing
natural gas costs within the GCIM tolerance band. The Company's policy
is to use natural gas futures contracts to mitigate risk and better
manage natural gas costs. The CPUC has approved the use of natural gas
futures for managing risk associated with the GCIM.borrowing. At December 31, 2000, unrealized2001, 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,
maturing 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 associatedor 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 activities totaled $72
million. These savings will be passed onderivatives are classified under SFAS 133.
Energy Contracts
SoCalGas records natural gas contracts in "Cost of gas distributed" in
the Statements of Consolidated Income. For open contracts not expected
to customersresult in physical delivery, changes in market value of the
contracts are recorded in these accounts during the first quarterperiod the
contracts are open, with an offsetting entry to a regulatory asset or
liability. The majority of 2001. At December 31, 1999, gains and/or losses from
natural gas futuresSoCalGas' contracts were not material to the Company's
financial statements.result in physical
delivery.
NOTE 9:9. PREFERRED STOCK OF SUBSIDIARYSOUTHERN CALIFORNIA GAS COMPANY
- -----------------------------------------------------------------
SoCalGas
December 31,
(Dollars in millions) 2001 2000 1999
- -----------------------------------------------------------------
Not subject to mandatory redemption:
$25 par value, authorized 1,000,000 shares
6% Series, 28,13428,049 shares outstanding $ 1 $ 1
6% Series A, 783,032 shares outstanding 19 19
Without par value, authorized 10,000,000 shares - -
--------------
$20 $20
- ---------------------------------------------------------------------------------------------------------------------------------
None of SoCalGas' series of preferred stock areis callable. All series have one
vote per share and cumulative preferences as to dividends. On
February 2, 1998, SoCalGas redeemed all outstanding sharesdividends, and have a
liquidation value of its
7.75% Series Preferred Stock at a price$25 per share of $25 plus accruedany unpaid dividends. The total cost to SoCalGas was $75 million.
41
NOTE 10: SHAREHOLDERS' EQUITY
The Company is authorized to issue 600 million shares ofIn
addition, the 6% Series preferred stock would also share pro rata with
common stock 10 million shares of Preferred Stock and 5 million shares of Class A
Preferred Stock. All shares of PE common stock are owned by Sempra
Energy.
COMMON EQUITY
- -------------------------------------------------------------------
December 31,
(Dollars in millions) 2000 1999
- -------------------------------------------------------------------
Common stock $ 1,282 $ 1,282
Retained earnings 165 58
Accumulated other comprehensive income (1) 6
-------------------------
Total common equity $ 1,446 $ 1,346
- -------------------------------------------------------------------the remaining assets.
NOTE 10. PREFERRED STOCK OF PACIFIC ENTERPRISES
- -------------------------------------------------------------------
Call December 31,
(Dollars in millions except call price)millions) Price 2001 2000 1999
- -------------------------------------------------------------------
Cumulative preferred
without par value:
$4.75 Dividend,
200,000 shares
authorized and outstanding $100.00 $ 20 $ 20
$4.50 Dividend,
300,000 shares authorized and outstanding $100.00 30 30
$4.40 Dividend,
100,000 shares authorized and outstanding $101.50 10 10
$4.36 Dividend,
200,000 shares authorized and outstanding $101.00 20 20
$4.75 Dividend,
253 shares authorized and outstanding $101.00 - -
-------------------------------------
Total preferred stock $ 80 $ 80
- -------------------------------------------------------------------
All or any partPE is authorized to issue 15,000,000 shares of every series of presently outstandingpreferred stock
without par value. The preferred stock is subject to redemption
at PE's option at any time upon not less than 30 daysdays' notice, at
the applicable redemption prices,price for each series, together with
the accrued and accumulated dividends to the date of
redemption.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 11:11. COMMITMENTS AND CONTINGENCIES
Natural Gas Contracts
SoCalGas buys natural gas under short-term and long-term
contracts. Short-term purchases under these contracts are primarily from various Southwest U.S.
and Canadian gas suppliers and are primarily based on monthly spot-marketspot-
market prices. SoCalGas transports gas under long-term firm
pipeline capacity agreements that provide for annual reservation
charges. SoCalGas recovers such fixed charges, which are recovered in rates. SoCalGas has
42
commitments
for firm pipeline capacity under contracts with pipeline
companies that expire at various dates through 2006.
In 1998, SoCalGas
restructured its long-term commodity contracts with suppliers of
California offshore and Canadian Gas. These contracts expire at the
end of 2003.
At December 31, 2000,2001, the future minimum payments under
natural gas contracts were:
- -----------------------------------------------------------------
Storage and
(Dollars in millions) Transportation Natural Gas
- -----------------------------------------------------------------
20012002 $ 182 $1,268
2002 178 360170 $ 444
2003 180 262172 158
2004 182 -174 --
2005 177 -
Thereafter170 --
2006 92 ---
----------------------------------
Total minimum payments $ 991778 $ 1,890602
- -----------------------------------------------------------------
Total payments under thenatural gas contracts were $2.1 billion in
2001, $1.4 billion in 2000, and $1.1 billion in 1999, and $0.9 billion in 1998.1999.
Leases
PE and SoCalGas have operating leases on real and personal
property expiring at various dates from 20012002 to 2030. Certain
leases on office facilities contain escalation clauses requiring
annual increases in rent ranging from 4 percent to 57 percent. The
rentals payable under these leases are determined on both fixed
and percentage bases, and most leases contain extension options to extend,
which are exercisable by PE or SoCalGas.
At December 31, 2000,2001, the minimum rental commitments payable
in future years under all noncancellable leases were:
- -----------------------------------------------------------------
(Dollars in millions) PE SoCalGas
- -----------------------------------------------------------------
20012002 $ 39
2002 4142 $ 30
2003 4142 30
2004 4043 31
2005 4043 30
2006 44 31
Thereafter 249217 172
- -----------------------------------------------------------------
Total future rental commitment $ 450431 $ 324
- -----------------------------------------------------------------
Rent expense totaled $55 million in 2000, $52 million in 1999 and $55
million in 1998.
43
In connection with the quasi-reorganization described in Note 2,
PE established reservesrecorded liabilities of $102 million to adjust to fair value
the operating leases related to its headquarters and other
leasesfacilities at December 31, 1992. The remaining amount of these
reservesliabilities was $56$49 million at December 31, 2000.2001. These leases
are included in the above table.
Other CommitmentsPE's rent expense totaled $51 million in 2001, $55 million
in 2000 and Contingencies
At December 31, 2000, commitments$52 million in 1999, which included rent expense for
capital expenditures were
approximately $12 million.SoCalGas of $39 million, $41 million, and $39 million,
respectively.
Environmental Issues
The Company'scompany'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. Significant costs areAs 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 under the
federal Superfund laws and comparable state laws. Costs incurred to
operate itsthe facilities in compliance with these laws and regulations
and these costs generally have been recovered in customer rates.
Costs that mitigate or prevent future environmental 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 $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. 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-
litigationinsurance-litigation expenses is
permitted. In addition, the Companycompany has the opportunity to retain a
percentage of any insurance recoveries to offset the 10 percent of
costs not recovered in rates.
Environmental
liabilities that may arise are recorded when remedial efforts are
probable and the costs can be estimated.
The Company's capital expenditures to comply with environmental
laws and regulations were $1 million in each of 2000, 1999 and 1998,
and are not expected to be significant over the next five years. The
Company has been associated with various sites which may require
remediation under federal, state or local environmental laws. The
Company is unable to determine fully the extent of its responsibility
for remediation of these sites until assessments are completed.
Furthermore, the number of others that also may be responsible, and
their ability to share in the cost of the cleanup, is not known.
The environmental issues currently facing the Companycompany or resolved
during the latest three-year period include investigation and
remediation of its manufactured-gas sites (18 completed as of December
31, 20002001 and 24 to be completed) and cleanup of third-party wastewaste-
disposal sites used by the Company,company, which has been identified as a
Potentially Responsible Party (investigation(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
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. At December 31, 2001, the company's
accrued liability for environmental matters was $55 million, of which
approximately $53 million was related to manufactured-gas sites and $2
million to waste-disposal sites used by the company (which has been
identified as a Potentially Responsible Party). The accruals for the
manufactured-gas and waste-disposal sites are expected to be paid
ratably over the next five years. There are no circumstances currently
known to management that would require adjustment to this accrual.
Litigation
A recent lawsuit, which seeksLawsuits filed in 2000 and currently consolidated in San Diego
Superior Court seek class-action certification allegesand 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 cheaperless
expensive natural gas supplies into California. The CompanyManagement believes
the allegations are without merit.
Except for the matter referred to above, neither the Companycompany
nor its subsidiarysubsidiaries are party to, nor is their property the subject
of, any material pending legal proceedings other than routine
litigation incidental to their businesses. Management believes that
these matters will not have a material adverse effect on the
Company's results of
operations,company's financial condition or liquidity.
44
results of operations.
Concentration of Credit Risk
The Companycompany maintains credit policies and systems to minimize overall
credit risk. These policies include when applicable, 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, substantially all of
whom are located in its service territory, which covers most of
Southern California and a portion of centralCentral California.
NOTE 12:12. REGULATORY MATTERS
Gas Industry Restructuring
The natural gas industry in California experienced an initial phase
of restructuring during the 1980s, by deregulating natural gas sales to noncore
customers.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. The general goals of
the plan are to consider reforms to the current regulatory framework
emphasizing market-oriented policies benefiting California's natural
gas consumers. 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.
In October 1999, the state of California enacted a law (AB 1421)
which requires that natural gas utilities provide "bundled basic gas
service" (including transmission, storage, distribution, purchasing,
revenue-cycle services and after-meter services) to all core
customers, unless the customer chooses to purchase natural gas from a
nonutility provider. The law prohibitsOn December 11, 2001, the CPUC from unbundling most
distribution-related naturalissued 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
services (including meter reading)
and after-meter services (including leak investigation, inspecting
customer piping and appliances, pilot relighting and carbon monoxide
investigation)industry in Southern California, but which was opposed by other
parties. The CPUC decision adopts the following provisions: a system
for core customers. The objective isshippers to preserve both
customer safety and customer choice.
Between late 1999 and April 2000, several conflicting settlement
proposals were filed by various groups of parties that addressed the
changes the CPUC found promising in July 1999. The principal issues in
dispute included: whetherhold firm, tradable rights to capacity on SoCalGas'
major gas transmission lines should be created, with SoCalGasSoCalGas' shareholders at risk for
whether market demand for the recovery ofthese rights will cover the cost of these
facilities; the extent to whicha further unbundling of SoCalGas' storage services
should be further unbundled andgiving SoCalGas be put at greater upward pricing flexibility (except for
storage service for core customers) but with increased shareholder
risk for recovery ofwhether market demand will cover storage costs; new
balancing services including separate core and noncore balancing
provisions; a reallocation among customer classes of the manner in whichcost of
interstate pipeline capacity held by SoCalGas to serveand an unbundling of
interstate capacity for gas marketers serving core markets should be allocated to
core customers who purchase gas from energy service providers other
than SoCalGas;customers; and
the recoveryelimination 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 utilities' costs to implement
whateversettlement 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, are adopted. Additional proposals included
improving the access of energy service providers to sell natural gas
supply to core customers of SoCalGas.
45
Certain parties contendbut it is expected that the restructuring process is an
appropriate venue for addressing whether SoCalGas should refund
retroactively to September 1999 the cost in rates of ownership and
operation of one of SoCalGas' storage fields. SoCalGas actively
opposes this proposal and the propriety of this venue for its
resolution. In November 2000, these parties entered into a settlement
with SoCalGas in a related CPUC proceeding that provides for no
retroactive refund of the cost in rates of this field. This settlement
is pending CPUC approval.
Hearings in the restructuring case were held in mid-2000 and a
Proposed Decision (PD) was released in November 2000. The PD does not
recommend adoption of shareholder absorption of stranded interstate
pipeline costs or retroactive refund of any amount related to the
storage field. The PD recommends some, but not all,most of the
changes proposed by SoCalGas. If adopted,will be implemented during 2002.
SoCalGas believes the PDdecision will make gas service more
reliable, efficient and better tailored to the desires of customers.
The decision is not expected to have a
negative earningsnegatively impact on SoCalGas. A CPUC decision is expected in
2001.
Supply/demand imbalances are affecting the price of natural
gas in California more than in the rest of the country because of
California's dependence on natural gas fired electric generation
due to air-quality considerations. The average price of natural
gas at the California/Arizona (CA/AZ) border was $6.25/mmbtu in
2000, compared with $2.33/mmbtu in 1999. On December 11, 2000, the
average spot-market price at the CA/AZ border reached a record
high of $56.91/mmbtu. Underlying the high natural gas prices are
several factors, including the increase in natural gas usage for
electric generation, cold winter weather and reduced natural gas
supply resulting from historically low storage levels, lower gas
production and a major pipeline rupture. In December 2000,
SoCalGas filed with the FERC for a reinstitution of price caps on
short-term interstate capacity to the CA/AZ border and between the
interstate pipelines and California's local distribution
companies, effective until March 31, 2001. SoCalGas requested that
if the price of natural gas sold into California exceeds 150
percent of the national average, the price should be capped at
that level, plus FERC-imposed transportation costs. The FERC
responded by issuing extensive data requests, but has not
otherwise acted on SoCalGas'
request.
Electric Industry Restructuring
As a result of electric industry restructuring, natural gas demand
for electric generation within southern California competes with
electric power generated throughout the western United States.
Although electric industry restructuring has no significant direct
impact on SoCalGas' natural gas operations, future volumes of
natural gas transported for UEG customers may be adversely
affected to the extent that regulatory changes divert electricity
generation from SoCalGas' service area and as noted in the
following paragraph.
On January 18, 2001, Pacific Gas and Electric Company (PG&E)
filed an emergency application with the CPUC requesting that SoCalGas
be ordered to purchase natural gas or supply available natural gas to
meet PG&E's core procurement needs. Some of PG&E's suppliers are
declining to sell natural gas to PG&E due to its poor credit rating.
Although SoCalGas has agreed to supply a limited amount of natural gas
to PG&E through March 31, 2001 (secured by PG&E customer receivables),
it is still urging rejection of the request which, if approved, could
severely jeopardize SoCalGas' ability to serve its own customers
because of cash flow considerations.
46
earnings.
Performance-Based Regulation (PBR)
In recent years, the CPUC has directed utilities to use 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 generally require future income potential to
be tied to achieving or exceeding specific performance and
productivity measures,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 iswas to have been in effect through
December 31, 2002, at which time the mechanism willwas to be updated.
That update willwas to include, among other things, a reexamination of
SoCalGas' reasonable costs of operation in 2003 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 mechanismmechanisms 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. AThe 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 this occurs,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.
Comprehensive Settlement of Natural Gas Regulatory Issues
In July 1994, the CPUC approved a comprehensive settlement for
SoCalGas (Comprehensive Settlement) of a number of regulatory issues,
including rate recovery of a significant portion of the restructuring
costs associated with certain long-term gas-supply contracts. In
addition to the supply issues, the Comprehensive Settlement addressed
the following other regulatory issues:
**Noncore revenues were governed by the Comprehensive Settlement
through July 31, 1999. This treatment was replaced by the 1999
Biennial Cost Allocation Proceeding (BCAP), which went into
effect on June 1, 2000. The CPUC's decision on the 1999 BCAP
allows balancing account treatment for 75 percent of noncore
revenues.
**Incentive Mechanism
The Gas Cost Incentive Mechanism (GCIM) for evaluatingevaluates SoCalGas' natural
gas purchases substantially replaced the previous
process of reasonableness reviews. GCIM compares SoCalGas'by comparing their cost of natural gas with a benchmark level, which is the average price of 30-day30-
day firm spot supplies in the basins in which SoCalGas purchases
natural gas. The mechanism permits full
47
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 equally 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 on a limited
basis 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 1998May
2001, the CPUC approved GCIM-relateda $10 million shareholder awards to SoCalGas
totaling $13 million. On June 8, 2000, the CPUC approved an $8 million award for the yearGCIM
Year Six ended March 31, 1999,2000, and deferred its decision
regarding extendingthe CPUC is addressing whether
the GCIM beyond March 31, 2000 until an evaluation
is performed by its staff. On January 4, 2001, theshould be extended and, if so, whether it should be with or
without modifications. The CPUC's Energy Division had previously
issued itsan 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 September
2001.the third quarter of 2002.
In June 2000,2001, SoCalGas filed its annual GCIM application with
the CPUC requesting ana shareholder award of $10$106 million for the yearGCIM
Year Seven ended March 31, 2000. On October 30, 2000,2001. 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 Office of Ratepayer Advocates
recommended approvalreview of the
award and the extension of the GCIM beyond
March 31, 2000, with certain modifications to the tolerance band and
benchmark price. A CPUCprogram, a draft decision is expected by September 2001.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 On November 4, 1999,(BCAP)
Rates to recover the CPUC revised its previous decision on
SoCalGas' 1996 BCAP, shifting $88 million of pipeline surcharges from
the pipeline capacity relinquishments to noncore customers. The
noncore customer rate impact of the decision is mitigated by
overcollectionschanges in the regulatory accounts and is reflectedcost of natural gas
transportation services are determined in the BCAP. The BCAP adjusts
rates adoptedto reflect variances in customer demand from estimates
previously used in establishing customer natural gas transportation
rates. The mechanism substantially eliminates the final 1999effect on income
of variances in market demand and natural gas transportation costs.
SoCalGas filed its 2003 BCAP decision.on September 21, 2001.
On April 20, 2000, the CPUC issued a decision on SoCalGas'the 1999 BCAP,
adopting an overall decreasedecreases 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 decrease reflectsdecreases reflect
anticipated changes in corresponding costs, it hasthey have no effect on
net income.
Cost ofOf Capital
For 2001,
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 20002001 and 1999,2000. 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 Core Gas Purchase FunctionsSoCalGas 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, 2001, SoCalGas2002, 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 SDG&E filed an applicationworking 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 integrate their natural gas purchasing departments.create the
holding company system and, therefore, retains jurisdiction to
enforce conditions to which the holding companies had agreed. The
filing
calls for a single natural gas acquisition groupcompany has filed to purchase natural
gas forrequest rehearing on the two utilities' core gas customers by using their pooled
gas portfolio assets. These assets include storage, interstate
48
capacity and natural gas supply contracts. The two utilities would
charge their core customers the same natural gas commodity rate from
the diversified portfolio. The change would bring increased efficiency
to the utilities' core gas purchase functions. The filing requests
that this change be effective November 1, 2001. A CPUC decision is not
expected until October 2001.issues.
NOTE 13: SEGMENT INFORMATION
The Company previously had two separately managed reportable segments:
SoCalGas and Sempra Energy Trading (SET). However, PE dividended its
SET holdings to Sempra Energy during the second quarter of 1999. As a
result, the Company no longer operates in multiple business segments.
NOTE 14:13. QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarter ended
------------------------------------------------------------------------------------------------------------
Dollars in millions March 31 June 30 September 30 December 31
- ----------------------------------------------------------------------------------------------------------------------------------------
2001
Operating revenues $ 1,548 $ 927 $ 561 $ 684
Operating expenses 1,480 864 489 613
----------------------------------------------------
Operating income $ 68 $ 63 $ 72 $ 71
----------------------------------------------------
Net income $ 50 $ 49 $ 57 $ 50
Dividends on preferred stock 1 1 1 1
----------------------------------------------------
Earnings applicable
to common shares $ 49 $ 48 $ 56 $ 49
====================================================
2000
Operating revenues $ 698 $ 630 $ 722 $ 804
Operating expenses 632 565 652 742
---------------------------------------------------------------------------------------------------------
Operating income $ 66 $ 65 $ 70 $ 62
---------------------------------------------------------------------------------------------------------
Net income $ 52 $ 49 $ 52 $ 58
Dividends on preferred stock 1 1 1 1
---------------------------------------------------------------------------------------------------------
Earnings applicable
to common shares $ 51 $ 48 $ 51 $ 57
=========================================================================================================
The sum of the quarterly amounts does not necessarily equal the annual totals due to
rounding.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA --
Southern California Gas Company
INDEPENDENT AUDITORS' REPORT
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 as of December 31,
2001 and 2000, and the related statements of consolidated income, cash
flows and changes in shareholders' equity for each of the three years
in the period ended December 31, 2001. 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 auditing standards
generally accepted in the United States of America. 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 Gas Company and subsidiaries as of December 31, 2001 and
2000, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 2001, in
conformity with accounting principles generally accepted in the United
States of America.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
February 4, 2002 (March 5, 2002 as to Note 12)
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
Dollars in millions
Years ended December 31 2001 2000 1999
------ ------- -------
Operating Revenues $3,716 $2,854 $2,569
------ ------ ------
Operating Expenses
Cost of natural gas distributed 2,117 1,361 1,032
Other operating expenses 792 695 738
Depreciation 268 263 260
Income taxes 165 173 179
Other taxes and franchise payments 101 96 92
------ ------ ------
Total operating expenses 3,443 2,588 2,301
------ ------ ------
Operating Income 273 266 268
------ ------ ------
Other Income and (Deductions)
Interest income 22 27 16
Regulatory interest (19) (12) (14)
Allowance for equity funds used during construction 6 3 --
Taxes on non-operating income (4) (10) (3)
Other - net (2) 7 (6)
------ ------ ------
Total 3 15 (7)
------ ------ ------
Interest Charges
Long-term debt 63 68 74
Other 7 8 (12)
Allowance for borrowed funds used during
construction (2) (2) (2)
------- ------ ------
Total 68 74 60
------ ------ ------
Net Income 208 207 201
Preferred Dividend Requirements 1 1 1
------ ------ ------
Earnings Applicable to Common Shares $ 207 $ 206 $ 200
====== ====== ======
See notes to Consolidated Financial Statements.
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Dollars in millions
Balance at December 31 2001 2000
-------- --------
ASSETS
Utility plant - at original cost $6,467 $6,314
Accumulated depreciation (3,710) (3,557)
------ ------
Utility plant - net 2,757 2,757
------ ------
Current assets:
Cash and cash equivalents 13 205
Accounts receivable - trade 415 589
Accounts and receivable - other 14 83
Due from unconsolidated affiliates -- 214
Deferred income taxes 62 74
Regulatory assets arising from fixed-priced contracts
and other derivatives 103 --
Other regulatory assets -- 24
Fixed-price contracts and other derivatives 59 --
Inventories 42 67
Other 4 80
------ ------
Total current assets 712 1,336
------ ------
Other assets:
Regulatory assets arising from fixed-priced contracts
and other derivatives 157 --
Sundry 136 35
------ ------
Total other assets 293 35
------ ------
Total assets $3,762 $4,128
====== ======
See notes to Consolidated Financial Statements.
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Dollars in millions
Balance at December 31 2001 2000
-------- --------
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock (100,000,000 shares authorized;
91,300,000 shares outstanding) $ 835 $ 835
Retained earnings 470 453
Accumulated other comprehensive income (loss) -- (1)
------ ------
Total common equity 1,305 1,287
Preferred stock 22 22
------ ------
Total shareholders' equity 1,327 1,309
Long term debt 579 821
------ ------
Total capitalization 1,906 2,130
------ ------
Current liabilities:
Short-term debt 50 --
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 --
Other 390 321
------ ------
Total current liabilities 1,072 1,434
------ ------
Deferred credits and other liabilities:
Customer advances for construction 24 16
Deferred income taxes 183 240
Deferred investment tax credits 50 53
Regulatory liabilities 174 84
Fixed-price contracts and other derivatives 162 --
Deferred credits and other liabilities 191 171
------ ------
Total deferred credits and other liabilities 784 564
------ ------
Contingencies and commitments (Note 11)
Total liabilities and shareholders' equity $3,762 $4,128
====== ======
See notes to Consolidated Financial Statements.
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
Dollars in millions
Years ended December 31 2001 2000 1999
------ ------ ------
Cash Flows From Operating Activities
Net Income $ 208 $ 207 $ 201
Adjustments to reconcile net income to net
cash provided by operating activities:
Depreciation 268 263 260
Deferred income taxes and investment tax credits 9 (4) 133
(Increase) decrease in other assets (12) 13 22
Increase (decrease) in other liabilities 12 12 (64)
Changes in working capital components:
Accounts receivable 244 (378) 154
Fixed-price contracts and other derivatives 16 -- --
Inventories 25 11 (18)
Other current assets 4 (75) 1
Accounts payable (171) 203 (18)
Income taxes payable (58) 86 (26)
Due to/from affiliates 5 (3) (83)
Regulatory balancing accounts (380) 309 36
Regulatory assets and liabilities 39 (2) (2)
Other current liabilities 71 92 6
------ ------ ------
Net cash provided by operating activities 280 734 602
------ ------ ------
Cash Flows from Investing Activities
Capital expenditures (294) (198) (146)
Loan repaid by (paid to) affiliate 233 (132) (101)
Other - net -- 21 (1)
------ ------ ------
Net cash used in investing activities (61) (309) (248)
------ ------ ------
Cash Flows from Financing Activities
Dividends paid (191) (201) (279)
Payments on long-term debt (270) (30) (75)
Increase in short-term debt 50 -- --
------ ------ ------
Net cash used in financing activities (411) (231) (354)
------ ------ ------
Increase (decrease) in cash and cash equivalents (192) 194 --
Cash and cash equivalents, January 1 205 11 11
------ ------ ------
Cash and cash equivalents, December 31 $ 13 $ 205 $ 11
====== ====== ======
Supplemental Disclosure of Cash Flow Information:
Interest payments, net of amounts capitalized $ 65 $ 77 $ 77
====== ====== ======
Income tax payments, net of refunds $ 216 $ 101 $ 100
====== ====== ======
See notes to Consolidated Financial Statements.
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
Years ended December 31, 2001, 2000 and 1999
Dollars in millions
Accumulated
Other Total
Comprehensive Preferred Common Retained Comprehensive Shareholders'
Income Stock Stock Earnings Income(Loss) Equity
- --------------------------------------------------------------------------------------------------
Balance at December 31, 1998 $ 22 $ 835 $ 525 $ 1,382
Net 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 $ 200
=====
Preferred stock dividends declared (1) (1)
Common stock dividends declared (200) (200)
--------------------------------------------------------
Balance at December 31, 2000 22 835 453 (1) 1,309
Net income $ 208 208 208
Other comprehensive income (loss):
Other 1 1 1
-----
Comprehensive income $ 209
=====
Preferred stock dividends declared (1) (1)
Common stock dividends declared (190) (190)
--------------------------------------------------------
Balance at December 31, 2001 $ 22 $ 835 $ 470 $ -- $1,327
==================================================================================================
See notes to Consolidated Financial Statements.
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 3 - Short-term Borrowings
Note 4 - Long-term Debt
Note 7 - Stock-based Compensation
Note 8 - Financial Instruments
Note 11 - Commitments and Contingencies
Note 12 - Regulatory Matters
The following additional notes apply only to Southern California Gas
Company:
NOTE 5. 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 1999
- ------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 5.3 5.6 6.8
State income taxes - net of
federal income tax benefit 6.7 6.8 7.3
Tax credits (0.8) (0.7) (0.6)
Other - net (1.4) 0.2 (1.0)
------------------------------
Effective income tax rate 44.8% 46.9% 47.5%
- ------------------------------------------------------------------
The components of income tax expense are as follows:
(Dollars in millions) 2001 2000 1999
- ------------------------------------------------------------------
Current:
Federal $ 126 $ 144 $ 36
State 34 42 13
------------------------------
Total 160 186 49
------------------------------
Deferred:
Federal 8 - 112
State 4 (1) 24
------------------------------
Total 12 (1) 136
------------------------------
Deferred investment tax credits - net (3) (2) (3)
------------------------------
Total income tax expense $ 169 $ 183 $ 182
- ------------------------------------------------------------------
Federal and state income taxes are allocated between operating
income and other income. SoCalGas is included in the consolidated
tax return of Sempra Energy and is allocated income tax expense from
Sempra Energy in an amount equal to that which would result from
filing a separate return.
Accumulated deferred income taxes at December 31 result from the
following:
(Dollars in millions) 2001 2000
- ------------------------------------------------------------------
Deferred Tax Liabilities:
Differences in financial and
tax bases of utility plant $ 263 $ 342
Regulatory balancing accounts 56 11
Other 20 19
------------------------------
Total deferred tax liabilities 339 372
------------------------------
Deferred Tax Assets:
Investment tax credits 35 38
Other deferred liabilities 174 142
Other 9 26
------------------------------
Total deferred tax assets 218 206
------------------------------
Net deferred income tax liability $ 121 $ 166
- ------------------------------------------------------------------
The net deferred income tax liability is recorded on the
Consolidated Balance Sheets at December 31 as follows:
(Dollars in millions) 2001 2000
- ------------------------------------------------------------------
Current asset $ (62) $ (74)
Noncurrent liability 183 240
- ------------------------------------------------------------------
Total $ 121 $ 166
- ------------------------------------------------------------------
NOTE 6. EMPLOYEE BENEFIT PLANS
Pension and Other Postretirement Benefits
The following tables provide a reconciliation of the changes in the
plans' benefit obligations and fair value of assets over the two
years, 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 88 96
-----------------------------------------------
Net recorded asset (liability)
at December 31 $ 56 $ 6 $ - $ (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.
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) - $ (1)
Additional minimum liability (2) (4) - -
Intangible asset 1 1 - -
Accumulated other
comprehensive income, pre-tax 1 3 - -
- ------------------------------------------------------------------------------------
Net recorded asset(liability) $ 56 $ 6 - $ (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
of 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 RESTRICTIONS
- -----------------------------------------------------------------
December 31,
(Dollars 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. QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarter ended
----------------------------------------------------
Dollars in millions March 31 June 30 September 30 December 31
- ------------------------------------------------------------------------------------
2001
Operating revenues $ 6141,548 $ 621927 $ 561 $ 773681
Operating expenses 547 557 484 710
-----------------------------------------------------1,480 862 488 614
--------------------------------------------------
Operating income $ 68 $ 65 $ 73 $ 67
$ 64 $ 77 $ 63
-------------------------------------------------------------------------------------------------------
Net income $ 51 $ 48 $ 4057 $ 45 $ 5152
Dividends on preferred stock -- 1 1 1 1
------------------------------------------------------- --
--------------------------------------------------
Earnings applicable
to common shares $ 51 $ 47 $ 3957 $ 4452
==================================================
2000
Operating revenues $ 698 $ 630 $ 722 $ 804
Operating expenses 632 563 653 740
--------------------------------------------------
Operating income $ 66 $ 67 $ 69 $ 64
--------------------------------------------------
Net income $ 50 =====================================================
Reclassifications have been made$ 48 $ 53 $ 56
Dividends on preferred stock -- 1 -- --
--------------------------------------------------
Earnings applicable
to certaincommon shares $ 50 $ 47 $ 53 $ 56
==================================================
The sum of the quarterly amounts since they were presented indoes not necessarily equal the Quarterly Reports on Form 10-Q.annual totals due to
rounding.
49
ItemITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
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 20012002 annual meeting of
shareholders. The information required on the Company'scompany's executive
officers is providedset forth below.
EXECUTIVE OFFICERS OF THE REGISTRANT
Name Age* Positions
- -------------------------------------------------------------------
Pacific Enterprises --
Stephen L. Baum 5960 Chairman, Chief Executive
Officer and President
John R. Light 5960 Executive Vice President and
General Counsel
Neal E. Schmale 5455 Executive Vice President and
Chief Financial Officer
Frank H. Ault 5657 Senior Vice President and
Controller
Charles A. McMonagle 5051 Vice President and Treasurer
Thomas C. Sanger 5758 Corporate Secretary
Southern California Gas Company --
Edwin A. Guiles 52 Chairman and Chief Executive Officer
Debra L. Reed 45 President 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 48 Senior Vice President, Corporate
Business Solutions
Roy M. Rawlings 57 Senior Vice President,
Distribution Operations
William L. Reed 49 Senior Vice President, Regulatory
Affairs
Lee M. Stewart 56 Senior Vice President, Gas
Transmission
* As of December 31, 2000.2001.
Each Executive Officer has been an officer or employee of Pacific EnterprisesSempra
Energy or one of its affiliatessubsidiaries for more than five years, with the
exception of Mssrs. Light and Schmale. Prior to joining the Companycompany in
1998, Mr. Light was a partner in the law firm of Latham & Watkins.
Prior to joining the Companycompany in 1997, Mr. Schmale was Chief Financial
Officer of Unocal Corporation. Each executive officer at 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 20012002 annual meeting of
shareholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
The information required by Item 12 is incorporated by reference from
"Election of Directors" in the Information Statement prepared for the
May 20012002 annual meeting of shareholders.
50
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.TRANSACTIONS
None.
PART IV
ITEM 14. 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
Independent Auditors' Report 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. . . . . . . . . . . . . . . 25. . . 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 19982000. . . . . . . . . 26. . . . . . . . . . . 58
Southern California Gas Company Statements of Consolidated Balance Sheets atCash
Flows for the years ended December 31, 2001, 2000 and 1999 . . . . 60
Southern California Gas Company Statements of Consolidated
Changes in Shareholders' Equity for the years ended
December 31, 2001, 2000 and 1999. . . . . . . . . . . . . . . . . .61
Southern California Gas Company Notes to Consolidated Financial
Statements . . . . . . . . . . . . . . . . . . . . 27
Statements of Consolidated Cash Flows for the
years ended December 31, 2000, 1999 and 1998 . . . . . 29
Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 2000, 1999 and 1998 . . . . . . . . . . . 30
Notes to Consolidated Financial Statements . . . . . . . 3162
2. Financial statement schedules
The following documents may be found in this report
at the indicated page numbers:
Page in
This Report
Independent Auditors' Consent and
Report on Schedule. . . . . . . . . . . . . . . . . . 52
Schedule I--Condensed Financial Information of Parent. . 53. . . . . 72
Any other schedules for which provision is made in Regulation S-X are
not required under the instructions contained therein, are
inapplicable or are
inapplicable.the information is included in the Consolidated
Financial Statements and the notes thereto.
3. Exhibits
See Exhibit Index on page 5676 of this report.
(b) Reports on Form 8-K
There were no reports on Form 8-K filed after September 30, 2000.
51
2001.
INDEPENDENT AUDITORS' CONSENTCONSENTS AND REPORT ON SCHEDULE
To the Board of Directors and Shareholders of Pacific Enterprises:
We consent to the incorporation by reference in Registration Statement
Nos.Numbers 2-96782, 33-26357, 2-66833, 2-96781, 33-21908, and 33-54055 of Pacific Enterprises on
FormsForm S-8 and Registration Statement Nos.Numbers 33-24830, 333-52926, and
33-44338 on Form S-3 of Pacific Enterprises on Forms S-3 of our report dated
January 26, 2001
(February 27, 2001,February 4, 2002 (March 5, 2002 as to Note 3)12), appearing in this
Annual Report on Form 10-K of Pacific Enterprises for the year ended
December 31, 2000.2001.
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. 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, presents fairly in all
material respects the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
March 9, 2001
52
15, 2002
To the Boards 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-
52663 on Form S-3 of our report dated February 4, 2002 (March 5, 2002
as to Note 12), appearing in the Annual Report on Form 10-K of Southern
California Gas Company for the year ended December 31, 2001.
San Diego, California
March 15, 2002
Schedule I -- CONDENSED FINANCIAL INFORMATION OF PARENT
PACIFIC ENTERPRISES
Schedule 1
Condensed Financial Information of Parent
Condensed Statements of Income
(Dollars in millions)
For the years ended December 31 2000 1999 1998
-------- ------- --------
Revenues and other income $ 33 $ -- $ 11
Expenses, interest and income taxes 32 20 20
-------- ------- --------
Income (loss) before subsidiary earnings 1 (20) (9)
Subsidiary earnings 206 200 152
-------- ------- --------
Earnings applicable to common shares $ 207 $ 180 $ 143
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 ended December 31 2001 2000 1999
------- ------- -------
Net cash provided by (used in)
operating activities $ 8 $ (96) $ (120)
------- ------- -------
Dividends received from subsidiaries 190 200 278
Increase in investments and other assets -- -- (14)
------- ------- -------
Cash flows provided by investing activities 190 200 264
------- ------- -------
Decrease in short-term debt -- -- (43)
Common dividends paid (190) (100) (100)
Preferred dividends paid (4) (4) (4)
Other (4) -- --
------- ------- -------
Cash flows used in financing activities (198) (104) (147)
------- ------- -------
Decrease in cash and cash equivalents -- -- (3)
Cash and cash equivalents, January 1 -- -- 3
------- ------- -------
Cash and cash equivalents, December 31 $ -- $ -- $ --
======= ========
Condensed Balance Sheets
(Dollars in millions)
Balance at December 31 2000 1999
---------- ----------
Assets:
Current assets $ 43 $ 41
Investment in subsidiary 1,287 1,288
Due from affiliates - long-term 617 487
Deferred charges and other assets 117 153
---------- ----------
Total Assets $ 2,064 $ 1,969
========== ==========
Liabilities and Shareholders' Equity:
Dividends payable $ 1 $ 1
Due to affiliates 364 294
Other current liabilities 31 34
---------- ----------
Total current liabilities 396 329
Other long-term liabilities 142 214
Common equity 1,446 1,346
Preferred stock 80 80
---------- ----------
Total Liabilities and Shareholders' Equity $ 2,064 $ 1,969
========== ==========
53
PACIFIC ENTERPRISES
Schedule 1 (continued)
Condensed Financial Information of Parent
Condensed Statements of Cash Flows
(Dollars in millions)
For the years ended December 31 2000 1999 1998
-------- ------- -------
Cash flows from operating activities $ (96) $ (120) $ (216)
-------- ------- -------
Expenditures for property, plant and equipment -- -- (12)
Dividends received from subsidiaries 200 278 164
Increase in investments and other assets -- (14) (53)
-------- ------- -------
Cash flows from investing activities 200 264 99
-------- ------- -------
Sale of common stock -- -- 27
Increase (decrease) in short-term debt -- (43) 43
Common dividends paid (100) (100) (97)
Preferred dividends paid (4) (4) (4)
-------- ------- -------
Cash flows from financing activities (104) (147) (31)
-------- ------- -------
Net decrease -- (3) (148)
Cash and Cash Equivalents, January 1 -- 3 151
-------- ------- -------
Cash and Cash Equivalents, December 31 $ -- $ -- $ 3
======== ======= =======
54
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, 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, Chief Executive
Officer and President /s/ Stephen L. Baum March 6, 20015, 2002
Principal Financial Officer:
Neal E. Schmale
Executive Vice President and
Chief Financial Officer /s/ Neal E. Schmale March 6, 20015, 2002
Principal Accounting Officer:
Frank H. Ault
Senior Vice President and
Controller /s/ Frank H. Ault March 6, 20015, 2002
Directors:
Stephen L. Baum, Chairman /s/ Stephen L. Baum March 6, 2001
Hyla H. Bertea,5, 2002
John R. Light, Director /s/ Hyla H. BerteaJohn R. Light March 6, 2001
Ann L. Burr,5, 2002
Neal E. Schmale, Director /s/ AnnNeal E. Schmale March 5, 2002
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, 2002
Principal Financial Officer:
Debra L. BurrReed
President and
Chief Financial Officer /s/ Debra L. Reed March 6, 2001
Herbert7, 2002
Principal Accounting Officer:
Terry M. Fleskes
Vice President and
Controller /s/ Terry M. Fleskes March 7, 2002
Directors:
Edwin A. Guiles
Chairman /s/ Edwin A. Guiles March 7, 2002
Debra L. Carter,Reed, Director /s/ HerbertDebra L. CarterReed March 6, 2001
Richard A. Collato,7, 2002
Frank H. Ault, Director /s/ Richard A. CollatoFrank H. Ault March 6, 2001
Daniel W. Derbes, Director /s/ Daniel W. Derbes March 6, 2001
Wilford D. Godbold, Jr., Director /s/ Wilford D. Godbold, Jr. March 6, 2001
William D. Jones, Director /s/ William D. Jones March 6, 2001
Ralph R. Ocampo, Director /s/ Ralph R. Ocampo March 6, 2001
William G. Ouchi, Director /s/ William G. Ouchi March 6, 2001
Richard J. Stegemeier, Director /s/ Richard J. Stegemeier March 6, 2001
Thomas C. Stickel, Director /s/ Thomas C. Stickel March 6, 2001
Diana L. Walker, Director /s/ Diana L. Walker March 6, 20017, 2002
55
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-
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; Exhibit 3.01).
3.02 Restated bylawsBylaws of Pacific Enterprises dated March 2, 1999
(Pacific Enterprises 1998November 6, 2001.
3.03 Restated Articles of Incorporation of Southern California Gas Company
(Southern California Gas Company 1996 Form 10-K; Exhibit 3.02)3.01).
3.04 Restated Bylaws of Southern California Gas Company dated November 6,
2001.
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; Exhibit 4.01).
4.02 Specimen Preferred Stock Certificates of Pacific Enterprises (Pacific
Lighting Corporation 1980 Form 10-K; Exhibit 4.02).
4.03 Specimen Preferred Stock Certificates of Southern California Gas
Company (Southern California Gas Company 1980 Form 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; Exhibit
B-4).
4.044.05 Supplemental Indenture of Southern California Gas Company to American
Trust Company dated as of July 1, 1947 (Registration Statement No. 2-
7072 filed by Southern California Gas Company on March 15, 1947;
Exhibit B-5).
4.054.06 Supplemental Indenture of Southern California Gas Company to American
Trust Company dated as of August 1, 1955 (Registration Statement No. 2-
11997 filed by Pacific Lighting Corporation on October 26, 1955;
Exhibit 4.07).
4.064.07 Supplemental Indenture of Southern California Gas Company to American
Trust Company dated as of June 1, 1956 (Registration Statement No. 2-
12456 filed by Southern California Gas Company on April 23, 1956;
Exhibit 2.08).
4.074.08 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; Exhibit 2.19).
4.084.09 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; Exhibit 2.20).
56
4.094.10 Supplemental Indenture of Southern California Gas Company to Wells
Fargo Bank, National Association dated as of September 15, 1981
(Pacific Lighting CorporationEnterprises 1981 Form 10-K; Exhibit 4.25).
4.104.11 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 (Pacific Lighting Corporation(Southern California Gas
Company 1984 Form 10-K; Exhibit 4.29).
4.114.12 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; Exhibit 4.11).
4.124.13 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; Exhibit 4.37).
4.14 Specimen 7 3/4% Series Preferred Stock Certificate (Southern California
Gas Company 1992 Form 10-K; Exhibit 4.15).
Exhibit 10 -- Material Contracts
Compensation
10.01 Sempra Energy Executive Security Bonus Plan effective January 1,
2001 Sempra Energy Form 10-K; Exhibit 10.08).
10.02 Form of Sempra Energy Severance Pay Agreement for Executives
(2001 Sempra Energy Form 10-K; Exhibit 10.07).
10.03 Sempra Energy Deferred Compensation and Excess Savings Plan
effective January 1, 2000 (2000 Sempra(Sempra Energy 2000 Form 10-K
Exhibit 10.07).
10.0210.04 Sempra Energy Supplemental Executive Retirement Plan as amended and
restated effective July 1, 1998 (1998 Sempra(Sempra Energy 1998 Form 10-K Exhibit
10.09).
10.0310.05 Sempra Energy Executive Incentive Plan effective June 1, 1998 (1998
Sempra(Sempra
Energy 1998 Form 10-K Exhibit 10.11).
10.0410.06 Sempra Energy Executive Deferred Compensation Agreement effective June
1, 1998 (1998 Sempra(Sempra Energy 1998 Form 10-K Exhibit 10.12).
10.0510.07 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; Exhibit 4.1).
10.0610.08 Pacific Enterprises Employee Stock Ownership Plan and Trust Agreement
as amended effective October 1, 1992. (Pacific Enterprises 1992 Form
10-K; Exhibit 10.18).
10.09 Amended and Restated Pacific Enterprises Employee Stock Option Plan
(Southern California Gas Company 1996 Form 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, 2001, 2000, 1999, 1998, 1997 and 1996.1997.
12.02 Southern California Gas Company Computation of Ratio of Earnings to
Fixed Charges for the years ended December 31, 2001, 2000, 1999, 1998,
1997.
Exhibit 21 -- Subsidiaries
21.01 Pacific Enterprises Schedule of Subsidiaries at December 31, 2000.2001.
21.02 Southern California Gas Company Schedule of Subsidiaries at
December 31, 2001.
Exhibit 23 --- Independent Auditors' Consent,Auditor's Consents, page 52.
57
71.
GLOSSARY
AFUDC Allowance for Funds Used During
Construction
BCAP Biennial Cost Allocation Proceeding
Bcf One Billion Cubic Feet (of natural gas)
CA/AZ California/Arizona
COS Cost of Service
CPUC California Public Utilities Commission
Enova Enova Corporation
EPA Environmental Protection Agency
ESOP Employee Stock Ownership Plan
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
GCIM Gas Cost Incentive Mechanism
IDBs Industrial Development Bonds
IOUs Investor-Owned Utilities
LIFO Last in first out inventory
mmbtu Million British Thermal Units (of natural
gas)
ORA Office of Ratepayer Advocates
PBR Performance-Based Ratemaking/Regulation
PD Proposed Decision
PE Pacific Enterprises
PG&E Pacific Gas and Electric Company
PRP PotentialPotentially Responsible Party
SAB Staff Accounting BulletinROE Return on Equity
ROR Rate of Return
SDG&E San Diego Gas & Electric Company
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
SoCalGas Southern California Gas Company
UEGTURN The Utility Electric GenerationReform Network
VaR Value at Risk
5855
2
70
49