SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K/A
AMENDMENT 1
(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, 1997
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
- ---------- -------------- -------------- --------------
1-3779 SAN DIEGO GAS &
ELECTRIC COMPANY California 95-1184800
1-11439 ENOVA CORPORATION California 33-0643023
101 ASH STREET, SAN DIEGO, CALIFORNIA 92101
- ----------------------------------------- ----------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (619)696-2000
--------------
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of each exchange
Title of each class on which registered
- ------------------- ---------------------
San Diego Gas & Electric Company
Preference Stock (Cumulative) Without Par Value
(except $1.70 and $1.7625 Series) American
Cumulative Preferred Stock, $20 Par Value (except 4.60% Series) American
Enova Corporation
Common Stock, Without Par Value New York and Pacific
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
San Diego Gas & Electric Company None
Enova Corporation 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. [ ]
Exhibit Index on page 90. Glossary on page 98.
Aggregate market value of the voting stock held by non-affiliates of the
registrant as of January 31, 1998:
Enova Corporation Common Stock $2.9 Billion
San Diego Gas & Electric Company Preferred Stock $22 Million
Common Stock outstanding without par value as of January 31, 1998:
Enova Corporation 113,606,162
San Diego Gas & Electric Company Wholly owned by Enova Corporation
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the March 1998 Proxy Statement prepared for the April 1998
annual meeting of shareholders are incorporated by reference into Part
III.
1
ENOVA CORPORATION
FORM 10-K/A
AMENDMENT 1
The undersigned registrant hereby amends Item 7, Management's Discussion
and Analysis of Financial Condition and Results of Operations, and Item
8, Financial Statements and Supplementary Data, of its Annual Report for
1997 on Form 10-K as set forth in the pages attached hereto. In these
items, the following modifications have been made: in the second
paragraph on page 26 and the second paragraph of Note 1 on page 58, in
both places, the word "shareholder" should be replaced by the word
"shareable."
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this amendment to be signed on its behalf by
the undersigned thereunto duly authorized.
Date: February 27, 1998 By: /s/ F. H. Ault
_____________________________
Vice President and Controller
2
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS -- Enova Corporation/San Diego Gas & Electric
Company
GENERAL
Enova Corporation (referred to herein as Enova, which includes the
parent and its wholly owned subsidiaries) was formed in January 1996 to
become the parent company of San Diego Gas & Electric (SDG&E). At that
time SDG&E's outstanding common stock was converted on a share-for-share
basis into Enova Corporation common stock. SDG&E's debt securities,
preferred stock and preference stock were unaffected and remained with
SDG&E.
SDG&E is an operating public utility engaged in the electric and
gas businesses. It generates and purchases electric energy and
distributes it to 1.2 million customers in San Diego County and an
adjacent portion of Orange County, California. It also purchases and
distributes natural gas to 721,000 customers in San Diego County and
transports electricity and gas for others. California has enacted an
electric-restructuring law that affects the operations of SDG&E and the
other California investor-owned electric utilities. This information is
discussed below under "Electric Industry Restructuring." Enova has
several other subsidiaries (referred to herein as nonutility
subsidiaries). Enova Financial invests in limited partnerships
representing approximately 1,200 affordable-housing properties located
throughout the United States. Califia leases computer equipment. These
two subsidiaries are expected to provide income tax benefits over the
next several years. Enova International is involved in energy projects
outside the United States. Pacific Diversified Capital is the parent
company of Phase One Development, which has been involved in real estate
development. Enova Energy is an energy management and consulting firm
offering services to utilities and large consumers. In December 1997,
subsidiaries of Enova Energy and Houston Industries formed a joint
venture, El Dorado Energy, to build, own and operate a natural gas-fired
power plant in Boulder City, Nevada. Enova Technologies is in the
business of developing new technologies generally related to utilities
and energy. In January 1997, Enova Energy, Enova Technologies and
certain subsidiaries of Pacific Enterprises (discussed below) formed
Energy Pacific, a joint venture to market integrated energy and energy-
related products and services. Energy Pacific has recently changed its
name to Sempra Energy Solutions. In January 1998, Sempra Energy
Solutions completed the acquisition of CES/Way International, a leading
national energy-service provider. In December 1997, Enova and Pacific
Enterprises completed the joint acquisition of AIG Trading Corporation
(AIG), a leading natural gas and power marketing firm based in
Greenwich, Connecticut. AIG has subsequently changed its name to Sempra
Energy Trading. Additional information regarding Enova's nonutility
subsidiaries is described herein under "Electric Generation" and
"Liquidity and Capital Resources - Investing Activities," and in Notes
1, 2 and 3 of the notes to consolidated financial statements.
BUSINESS COMBINATION
In October 1996, Enova and Pacific Enterprises (PE), parent company of
Southern California Gas Company (SoCalGas), announced that they have
agreed to combine the two companies. Enova and PE have selected Sempra
Energy as the name of the new company formed by the business
combination. As a result of the combination, which was unanimously
approved by the boards of directors of both companies, (i) each
outstanding share of common stock of Enova will be converted into one
share of common stock of Sempra Energy, (ii) each outstanding share of
common stock of PE will be converted into 1.5038 shares of Sempra
Energy's common stock and (iii) the preferred stock and preference stock
25
of SDG&E, PE and SoCalGas will remain outstanding. In March 1997, the
shareholders of Enova and PE approved the combination. Consummation of
the combination is conditional upon the approvals of the California
Public Utilities Commission (CPUC) and various other regulatory bodies
(see below).
In June 1997, the CPUC revised its procedural schedule for the
business combination after delaying until July 1997 its final decision
on the Performance-Based Ratemaking (PBR) proceeding for SoCalGas. (The
CPUC's decision on SoCalGas' PBR proceeding adopted a rate-setting
mechanism for SoCalGas that provides incentives for cost control and
efficiency improvement, including comparisons of productivity and other
factors against benchmarks based on industry performance. SoCalGas had
been operating under traditional "cost of service" regulation. The
decision provides for, among other things, a net rate reduction of $160
million.) In accordance with the CPUC's revised schedule, the
administrative law judge handling the proceeding issued a draft decision
on February 23, 1998. That draft decision proposed approval of the
combination. Among other things, the draft decision proposed 50/50
sharing of the net cost savings resulting from the combination between
shareholders and customers, but only for five years rather than the 10
years sought. The draft decision would reduce the net shareable
savings from $1.1 billion to $340 million. The CPUC decision is
scheduled for the end of March 1998.
In November 1997, the California attorney general issued an
advisory opinion concluding that the business combination would not
adversely affect competition within either the wholesale electricity or
interstate gas markets. The opinion included a recommendation that the
CPUC consider requiring SoCalGas to auction offsetting volumes of
natural gas transportation rights equal to the load with SDG&E that will
be withdrawn if the CPUC concludes that SDG&E would be eliminated as a
potential competitor in the partially regulated intrastate gas
transmission market.
In September 1997, the CPUC staff issued a final Negative
Declaration, concluding that the business combination will not result in
any activities or operational changes that may cause a significant
adverse effect on the environment.
In June 1997, the Federal Energy Regulatory Commission (FERC)
approved the business combination, subject to the conditions that the
combined company will not unfairly use any potential market power
regarding natural gas transportation to gas-fired electric-generation
plants. The FERC acknowledged that this issue is clearly within the
jurisdiction of the CPUC and the conditions will be considered during
the CPUC review process. Therefore, the FERC's final decision is not
expected to be issued before the CPUC's approval.
In August 1997, the Nuclear Regulatory Commission approved the
business combination, ruling that the creation of the new company will
not affect SDG&E's qualifications to hold the license for its
20-percent interest in the San Onofre Nuclear Generating Station
(SONGS).
Remaining regulatory reviews, which are not expected to be
concluded prior to the CPUC decision, include clearance by the U.S.
Department of Justice, under the Hart-Scott-Rodino Antitrust Act, and
approval by the Securities and Exchange Commission. Both agencies will
review the business combination for its impacts on competition.
The commencement of combined operations is expected in the summer
of 1998. Earnings of the combined company could be negatively impacted
in 1998, and to a lesser extent in subsequent years, by delays in
achieving cost savings from the combination caused by the later-than-
expected effective combination date, CPUC limitations on transactions
between SDG&E and SoCalGas, which may be modified by the CPUC
combination proceedings (discussed below), the possibility that the CPUC
26
might not permit recovery of certain costs of the combination and might
reduce the period or percentage for shareholder participation in the
related cost savings, and slower-than-anticipated growth in revenues
from Sempra Energy Solutions. Additional information regarding the
proposed business combination is described in Note 1 of the notes to
consolidated financial statements.
RESULTS OF OPERATIONS
Operating Results Electric revenues increased 11 percent in 1997,
primarily due to an increase in sales for resale to other utilities and
increased retail sales volume due to weather. Electric revenues
increased 6 percent in 1996, primarily due to the accelerated recovery
of SONGS Units 2 and 3 which commenced in April 1996. Gas revenues
increased 14 percent in 1997, primarily due to weather-related higher
sales volume and higher purchased-gas prices, offset by an increase in
customer purchases of gas directly from other suppliers (for whom SDG&E
provides transportation). Gas revenues increased 12 percent in 1996,
reflecting higher purchased-gas prices.
Operating Expenses Electric fuel expense increased 22 percent in 1997,
primarily due to increased natural gas prices and increased natural gas-
fired generation resulting from SONGS Units 2 and 3 refuelings. Electric
fuel expense increased 34 percent in 1996, primarily due to increased
generation and increases in natural gas prices.
Purchased-power expenses increased 42 percent in 1997, primarily due
to increased volume, which resulted from lower nuclear-generation
availability from the SONGS refuelings and increased use of purchased
power due to decreased purchased-power prices. Purchased-power expenses
decreased 9 percent in 1996, reflecting the availability of lower-cost
nuclear generation and decreases in purchased-power capacity charges.
Gas purchased for resale increased 20 percent in 1997 and 34 percent
in 1996, primarily due to increases in sales volume and in natural gas
prices.
The changes in maintenance expenses reflect the nuclear refuelings
in 1997 and 1995.
General and administrative expenses decreased 15 percent in 1997,
primarily due to higher 1996 costs for customer service, partially
offset by the expenses relating to the proposed business combination
with Pacific Enterprises.
Earnings 1997 earnings per common share were $2.20 compared to $1.98
in 1996 and $1.94 in 1995. The increase in earnings in 1997 is primarily
due to incentive rewards for Performance-Based Ratemaking (PBR) and
Demand-Side Management (DSM) programs, retirements of debt and common
shares, and improved earnings of Enova Financial, partially offset by
expenses relating to the proposed business combination with Pacific
Enterprises. Other events that improved 1997 earnings included income
tax benefits from the 1995 sale of Wahlco Environmental Systems and
capital gains from the sale of property held by Pacific Diversified
Capital. The increase in earnings in 1996 is primarily due to DSM
rewards, partially offset by SDG&E's lower authorized return on equity.
Earnings per share for the quarter ended December 31, 1997, were
$0.72, compared to $0.47 for the same period in 1996. The increase in
earnings for the quarter was due to numerous offsetting factors,
including PBR and DSM rewards, retirement of common shares, higher off-
system electric sales, previously announced seasonal variability related
to the elimination of electric balancing accounts, and expenses relating
to the proposed business combination with Pacific Enterprises. Although
the elimination of the balancing accounts did not have any effect on
1997 full-year earnings, quarterly earnings now fluctuate significantly,
depending on monthly or seasonal changes in electric sales and fuel
27
prices. In general, earnings are expected to be higher in high sales-
volume months and lower in others. In 1998 and future years, full-year
earnings also will be affected by sales volumes.
Some of the PBR rewards recorded in 1997 had been pending with the
CPUC for several years. During 1998, SDG&E will not have a multiple-year
backlog of these PBR rewards to record. In addition, because of the
elimination of the Generation and Dispatch PBR mechanism and the San
Onofre Nuclear Generating Station Target Capacity Factor mechanism, the
impact of performance rewards on future earnings will be reduced.
Califia and Enova Financial's contributions to earnings for the year
were $0.21 in 1997, $0.19 in 1996 and $0.17 in 1995. Contributions to
earnings by Enova Energy and Enova Technologies were negatively impacted
in 1997 by the slower-than-anticipated growth in revenues from Sempra
Energy Solutions.
LIQUIDITY AND CAPITAL RESOURCES
SDG&E's operations continue to be a major source of liquidity. In
addition, financing needs are met primarily through issuances of short-
term and long-term debt. These capital resources are expected to remain
available. Cash requirements include utility capital expenditures,
nonutility subsidiaries' investments, and repayments and retirements of
long-term debt. Nonutility cash requirements include capital
expenditures associated with subsidiary activities related to the plans
to distribute natural gas in Mexico and the eastern United States; new
products; investments in Sempra Energy Trading, CES/Way International
and El Dorado Energy; and affordable-housing, leasing and other
investments. Additional information on these activities is discussed
under "Cash Flows from Investing Activities" below. In addition to
changes described elsewhere, major changes in cash flows are described
below.
Cash Flows from Operating Activities The major changes in cash flows
from operations among the three years result from changes in income
taxes, accounts receivable, other current assets, accounts payable, and
regulatory balancing accounts. The changes in cash flows related to
income taxes were primarily due to the timing of certain deductions in
1997 and higher 1996 income tax payments in connection with settlements
with the Internal Revenue Service. The changes in cash flows related to
accounts and notes receivable were primarily due to increases in sales
in December 1997. The changes in cash flows related to other current
assets were primarily due to advances made to unconsolidated
subsidiaries during late 1997. The changes in cash flows related to
accounts payable were primarily due to fluctuations in natural gas
purchases and prices from year to year. The changes in cash flows
related to regulatory balancing accounts were primarily due to
overcollections in the Electric Revenue Adjustment Mechanism (ERAM)
account as a result of higher-than-authorized sales volumes in 1997 and
changes in prices for natural gas in 1996.
Quarterly cash dividends of $0.39 per share were declared for the
year ended December 31, 1997. The dividend payout ratios for the years
ended December 31, 1997, 1996, 1995, 1994 and 1993 were 71 percent, 79
percent, 80 percent, 130 percent, and 82 percent, respectively. The
increase in the payout ratio for the year ended December 31, 1994, was
due to writedowns recorded during 1994. For additional information
regarding the writedowns, see Enova Corporation's 1996 Annual Report.
The payment of future dividends is within the discretion of the Enova
Board of Directors and is dependent upon future business conditions,
earnings and other factors. Net cash flows provided by operating
activities currently are sufficient to maintain the payment of dividends
at the present level.
28
Enova has initiated an enterprise-wide program to prepare the
company's computer systems and applications for the year 2000 and
beyond. A comprehensive review has been conducted to identify the
systems that could be affected by the year 2000 issue and an
implementation plan has been developed. The year 2000 issue results from
time-sensitive software applications that recognize a date using only
two digits. For example, "00" may be recognized as the year 1900 rather
than the year 2000. This could result in a system failure or
miscalculations. This year 2000 problem creates risk for the company
from unforeseen problems in its own computer systems and from third
parties with whom the company deals on financial transactions.
Management has not yet assessed whether the company's date-conversion
project will be completed on a timely basis nor the impact of third-
party computer system failures. The company expects to incur internal
staff costs as well as consulting and other expenses related to
infrastructure and facilities enhancements necessary to prepare the
systems for the year 2000. Expenditures for the testing and conversion
of system applications were $4 million in 1997 and are expected to be
between $20 million and $25 million over the next two years. These costs
are expensed as incurred.
Cash Flows from Financing Activities Enova did not issue additional
stock or long-term debt in 1997, except for SDG&E-related refinancings
and electric industry restructuring-related rate-reduction bonds.
Additional information concerning the rate-reduction bonds is discussed
below and under "Electric Industry Restructuring." Enova and SDG&E do
not plan any issuances in 1998.
In October 1997, SDG&E issued $25 million of tax-exempt Industrial
Development Bonds (IDBs) through the City of Chula Vista. The variable-
rate bonds were issued at an initial rate of 3.5 percent. The proceeds
from the bonds, which will mature in 2023, were used to redeem $25
million of 8.75 percent IDBs with the City of San Diego. Also during
1997, SDG&E purchased and retired $62 million of 9.625 percent and 8.5
percent first mortgage bonds.
In December 1997, $658 million of rate-reduction bonds were issued
on SDG&E's behalf at an average interest rate of 6.26 percent. A portion
of the bond proceeds was used to retire $14.9 million of variable-rate,
taxable IDBs in December 1997 and $15.7 million of variable-rate,
taxable IDBs in January 1998. Additional retirements are planned.
Additional information concerning the rate-reduction bonds is provided
below under "Electric Industry Restructuring."
SDG&E currently has approximately $83 million of temporary
investments that will be maintained into the future. The purpose of
maintaining such a level of investments is to offset a like amount of
long-term debt. The specific debt series being offset consists of
variable-rate IDBs. The CPUC has approved specific ratemaking treatment
which allows SDG&E to offset IDBs as long as there is at least a like
amount of temporary investments. If and when SDG&E requires all or a
portion of the $83 million of IDBs to meet future needs for long-term
debt, such as to finance new construction, the amount of investments
which is being maintained will be reduced below $83 million and the
level of IDBs being offset will be reduced by the same amount.
During 1997, Enova Corporation repurchased three million shares of
its outstanding common stock. During 1998, the $1.82-series preferred
stock becomes callable at $26 per share.
SDG&E maintains its capital structure so as to obtain long-term
financing at the lowest possible rates. The following table shows the
percentages of capital represented by the various components. In 1993
the capital structure is net of the construction funds held by a
trustee.
29
1993 1994 1995 1996 1997 Goal
-----------
(A) (B) (A)
- ------------------------------------------------------------------------
Common equity 47 % 48 % 49 % 50 % 51 % 41 % 46-49 %
Preferred stock 4 4 4 4 4 3 3-5
Debt and leases 49 48 47 46 45 56 46-49
- ------------------------------------------------------------------------
Total 100 % 100 % 100 % 100 % 100 % 100 % 100 %
- ------------------------------------------------------------------------
(A) Excludes rate reduction bonds ($658 million at December 31, 1997).
(B) Includes rate reduction bonds ($658 million at December 31, 1997).
The CPUC regulates SDG&E's capital structure, limiting the dividends
it may pay Enova. At December 31, 1997, $152 million of common equity
was available for future dividends. In addition, at December 31, 1997,
approximately one half of the $658 million of rate-reduction bonds was
also available for future dividends. Of this available amount, $100
million in dividends were paid by SDG&E to Enova on January 2, 1998, in
conjunction with the acquisition of Sempra Energy Trading. This
restriction is not expected to affect Enova's ability to meet its cash
obligations.
In December 1997, Moody's Investors Service upgraded SDG&E's long-
term-bond rating from an A1/stable outlook to an A1/positive outlook,
reflecting SDG&E's business mix, which is heavily weighted toward
distribution and transmission. The outlook upgrade also reflects the
probability of recovery of stranded costs and the expected proceeds from
the sale of generating assets (see discussion under "Electric
Generation"). Standard & Poor's Ratings Group affirmed SDG&E's long-
term-bond rating of A+/positive outlook.
Cash Flows from Investing Activities Cash used in investing activities
in 1997 included SDG&E's construction expenditures and payments to its
nuclear decommissioning trusts. SDG&E's capital expenditures were $197
million in 1997 and are estimated to be $242 million in 1998. Actual
capital expenditures in 1997 were lower than anticipated due to changes
in the scope and timing of several major capital projects. Estimated
1998 capital expenditures are closer to normal levels, with increases to
meet industry restructuring needs and improvements to the electric
distribution system. SDG&E continuously reviews its construction,
investment and financing programs and revises them in response to
changes in competition, customer growth, inflation, customer rates, the
cost of capital, and environmental and regulatory requirements. Among
other things, the level of expenditures in the next few years will
depend heavily on the impacts of industry restructuring and the sale of
SDG&E's Encina and South Bay power plants and other electric-generating
assets, as well as the timing and extent of expenditures to comply with
air-emission reduction and other environmental requirements. Additional
information concerning the proposed sale of SDG&E's electric-generating
assets is provided below under "Electric Generation."
Payments to the nuclear-decommissioning trusts are expected to
continue until SONGS is decommissioned, which is not expected to occur
before 2013. Although Unit 1 was permanently shut down in 1992, it is
scheduled to be decommissioned concurrently with Units 2 and 3. However,
this will depend on the outcome of the proposed sale of SDG&E's
electric-generating assets, including its interest in SONGS.
Enova's level of nonutility expenditures in the next few years will
depend primarily on the activities of its subsidiaries other than SDG&E,
including Sempra Energy Solutions and the natural gas distribution
projects in Mexico and the eastern United States. Nonutility
expenditures were $158 million in 1997 and are estimated to be $100
30
million in 1998, not including special projects. The decrease in
expected expenditures in 1998 is primarily attributable to a decrease in
expected investments by Enova Financial.
As discussed previously, in January 1997, certain subsidiaries of
Enova and Pacific Enterprises formed Sempra Energy Solutions, a joint
venture to market integrated energy and energy-related products and
services. During 1997, Enova invested $21 million in Sempra Energy
Solutions. In addition, in January 1998, Sempra Energy Solutions
completed the acquisition of CES/Way International, a leading national
energy-service provider.
In September 1997, Sempra Energy Solutions formed a joint venture
with Bangor Hydro to build, own and operate a $40 million natural gas
distribution system in Bangor, Maine. In addition, in December 1997
Sempra Energy Solutions signed a partnership agreement with Frontier
Utilities to build and operate a $55 million natural gas distribution
system in North Carolina.
In December 1997, Enova and Pacific Enterprises completed the joint
acquisition of AIG Trading Corporation, a leading natural gas and power
marketing firm. Enova contributed $110.6 million to that acquisition,
which was subsequently renamed Sempra Energy Trading.
In July 1997, Enova International and its partners, Pacific
Enterprises International and Proxima S.A. de C.V., delivered their
first supply of natural gas to Baja California. The Mexican company
formed by the three partners, Distribuidora de Gas Natural de Mexicali,
will invest up to $25 million during the first five years of the 30-year
license period to supply natural gas to the region. The partnership is
expected to serve 25,000 customers over the next four years. In March
1997, the Mexican Energy Regulatory Commission awarded the partners
their second natural gas privatization license in Mexico, allowing
Distribuidora de Gas Natural de Chihuahua to build and operate a natural
gas distribution system in Chihuahua. That partnership plans to invest
approximately $50 million in the project and is expected to serve 50,000
customers over the next five years. In January 1998, Enova International
and its partner, Union Fenosa ACEX of Spain, submitted a bid to build,
own and operate a natural gas distribution system in Monterrey, Mexico.
The project will consist of an initial investment of $190 million for a
system that will serve 320,000 customers, with an additional $60 million
invested over five years to serve a total of 400,000 customers. Two
other international consortia have submitted bids on the project. The
Mexican Energy Regulatory Commission is expected to announce the winning
bidder in March 1998.
In December 1997, Enova Power Corporation, a subsidiary of Enova
Energy, and Houston Industries Power Generation formed El Dorado Energy,
a joint venture to build, own and operate a natural gas power plant in
Boulder City, Nevada. Enova invested $2.3 million in El Dorado Energy in
1997 and expects to invest an additional $37 million in 1998 and $17
million in 1999.
Additional information about these acquisitions and joint ventures
is discussed in Note 3 of the notes to consolidated financial
statements.
Derivative Financial Instruments The policy of Enova is to use
derivative financial instruments to reduce exposure to fluctuations in
interest rates, foreign currency exchange rates and natural gas prices.
These financial instruments are with major investment firms and expose
Enova to market and credit risks. At times, these risks may be
concentrated with certain counterparties, although counterparty
nonperformance is not anticipated.
SDG&E periodically enters into interest-rate swap and cap agreements
to moderate its exposure to interest-rate changes and to lower its
overall cost of borrowing. These swap and cap agreements generally
31
remain off the balance sheet as they involve the exchange of fixed- and
variable-rate interest payments without the exchange of the underlying
principal amounts. The related gains or losses are reflected in the
income statement as part of interest expense. SDG&E would be exposed to
interest-rate fluctuations on the underlying debt should other parties
to the agreement not perform. Such nonperformance is not anticipated. At
December 31, 1997, SDG&E had an agreement for a floating-to-fixed-rate
swap associated with $45 million of variable-rate bonds maturing in
2002.
SDG&E's pension fund periodically uses foreign-currency forward
contracts to reduce its exposure to exchange-rate fluctuations
associated with certain investments in foreign equity securities. These
contracts generally have maturities ranging from three to six months. At
December 31, 1997, and 1996, there were no foreign-currency forward
contracts outstanding.
In November 1996, SDG&E commenced price risk management activities,
on a limited basis, in the area of hedging price volatility of natural
gas requirements. SDG&E uses energy derivatives for both hedging and
trading purposes within certain limitations imposed by company policies.
These derivative financial instruments include forward contracts, swaps,
options and other contracts which have maturities ranging from 30 days
to nine months. Additional information on derivative financial
instruments of SDG&E is provided in Note 8 of the notes to consolidated
financial statements and under "Market Risk" below.
Sempra Energy Trading Corp. derives a substantial portion of its
revenue from trading activities in natural gas, petroleum and
electricity. Trading profits are earned as Sempra Energy Trading acts as
a dealer in structuring and executing transactions that permit its
counterparties to manage their risk profiles. In addition, Sempra Energy
Trading takes positions in energy markets based on the expectations of
future market conditions. These positions may be offset with similar
positions or may be offset in the exchange traded markets. These
positions include options, forwards, futures and swaps. Additional
information on derivative financial instruments of Sempra Energy Trading
is provided in Note 3 of the notes to consolidated financial statements
and under "Market Risk" below.
Market Risk Market risk arises from the potential change in the value
of financial instruments and physical commodities based on fluctuations
in natural gas, petroleum and electricity commodity exchange prices and
basis. Market risk is also affected by changes in volatility and
liquidity in markets in which these instruments are traded. SDG&E
utilizes a variety of financial structures, products and terms which
require the company to manage, on a portfolio basis, the resulting
market risks inherent in these transactions, subject to parameters
established by company policies. Market risks are monitored separately
from the groups that create or actively manage these risk exposures to
ensure compliance with the company's stated risk management policies at
both the Enova and subsidiary levels.
SDG&E measures the risk in its portfolio on a daily basis in
accordance with value-at-risk methodologies, which simulate forward
price curves in the energy markets to estimate the size and probability
of future potential losses. The quantification of market risk using
value-at-risk provides a consistent measure of risk across diverse
energy markets and products. The use of this methodology requires a
number of key assumptions, including the selection of a confidence level
for losses and the holding period chosen for the value-at-risk
calculation.
SDG&E expresses value-at-risk as the amount of SDG&E's earnings at
risk based on a 95 percent confidence level using a time horizon of the
average life of the portfolio. As of December 31, 1997, SDG&E's value-
32
at-risk for its price-risk management activities was $2.8 million (net
of income taxes) of SDG&E's net earnings. Since this is not an absolute
measure of risk under all conditions for all products, SDG&E performs
alternative scenario analyses to estimate the economic impact of a
sudden market movement on the value of the portfolio. This and the
professional judgment of experienced business and risk managers is used
to supplement the value-at-risk methodology.
Based upon the ongoing policies and controls discussed above, SDG&E
does not anticipate a material adverse effect on its financial position
or results of operations as a result of market fluctuations.
A Risk Management Committee, composed of Enova and Pacific
Enterprises officers, is responsible for monitoring operating
performance and compliance with established risk management policies for
Sempra Energy Solutions and its subsidiaries. Sempra Energy Trading has
established position and stop-loss limits for each line of business to
monitor its market risk and traders are required to maintain positions
within these market-risk limits. The position limits are monitored
during the day by Sempra Energy Trading's senior management, which
determines whether to adjust its market-risk profile.
All of Sempra Energy Trading's market-risk sensitive instruments are
entered into for trading purposes. The following table provides the
potential changes in net principal transaction revenues resulting from
hypothetical 10-percent increases and 10-percent decreases in the
applicable commodity prices for significant commodity market-price
sensitive instruments held on December 31, 1997. This quantitative
information about market risk is limited because it does not take into
account potential hedging transactions or changes to the market-risk
profile of the portfolio by management in reaction to such changes in
market conditions. Additionally, it does not take into account
anticipated management reaction to breaches of counterparty credit
limitations caused by the shocks within a given risk category. Further,
inherent limitations arise from assuming that hypothetical 10-percent
increases and 10-percent decreases in commodity prices move in the same
direction, and this information does not recognize co-movements in
prices.
The following table presents the impact on Sempra Energy Trading's
net principal transaction revenues resulting from a 10-percent increase
and a 10-percent decrease in the respective December 31, 1997 commodity
prices:
In thousands of dollars
- -----------------------------------------------------------------------
Commodity 10% Increase 10% Decrease
- -----------------------------------------------------------------------
Crude oil and derivatives $ 3,288 $ (3,288)
Natural gas (2,441) 2,441
Emission credits (81) 81
Electricity (540) 540
- -----------------------------------------------------------------------
SDG&E's payments to the externally managed nuclear decommissioning
trust funds expose SDG&E to market risk. Market risk can result from
fluctuations in the volatility and liquidity in markets in which these
instruments are traded. These fluctuations can also correspondingly
affect the level of funding of the decommissioning trust.
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. SDG&E and Sempra Energy Trading
avoid concentration of counterparties and maintain credit policies with
regard to counterparties that management believes significantly minimize
33
overall credit risk. These policies include an evaluation of potential
counterparties' financial condition (including credit rating),
collateral requirements under certain circumstances, and the use of
standardized agreements which allow for the netting of positive and
negative exposures associated with a single counterparty.
The companies monitor credit risk exposure through an approval
process and the assignment of credit limits. These credit limits are
established based on risk and return considerations under terms
customarily available in the industry.
ELECTRIC INDUSTRY RESTRUCTURING
Background In September 1996, the state of California enacted a law
restructuring California's electric utility industry (AB 1890). The
legislation adopts the December 1995 CPUC policy decision that
restructures the industry to stimulate competition and reduce rates.
In May 1997, the CPUC issued a decision providing for direct access
to be available to all California electric customers on January 1, 1998.
The CPUC concluded that there were no technical or operational barriers
to justify limiting direct access availability once electric
restructuring commenced. The decision allowed customers to begin
choosing electricity providers in November 1997. In December 1997, the
CPUC agreed to delay the initiation of electric restructuring until
March 31, 1998, to allow California's Power Exchange (PX) and
Independent System Operator (ISO) to resolve computer software problems
and conduct additional user training. Beginning on March 31, 1998,
customers will be given the choice to continue to purchase electricity
from their local utility under regulated tariffs, to enter into
contracts with other energy service providers (i.e., private generators,
brokers, etc.) or buy their power from the independent PX that serves as
a wholesale power pool allowing all energy producers to participate
competitively. The PX obtains power from qualifying facilities, nuclear
units and, lastly, from the lowest-bidding suppliers. The ISO will
schedule the power transactions and access to the transmission system.
To facilitate this, the utilities will transfer the operational control
of their transmission facilities to the ISO. The local utility will
continue to provide distribution services, regardless of which source
the consumer chooses. These customer choices will, in effect, open up
the service territories of all California utilities. This will allow
Enova, through Sempra Energy Solutions, to pursue customers outside of
SDG&E's traditional service territory to provide electricity and other
energy-related services. This also allows other energy-service providers
to enter SDG&E's service territory to compete for generation customers.
Transition Costs Both the CPUC decision and the California legislation
allow utilities, within certain limits, the opportunity to recover their
stranded costs incurred for certain above-market CPUC-approved
facilities, contracts and obligations through the establishment of a
nonbypassable competition transition charge (CTC). The CPUC's direction
is that traditional cost-of-service regulation will move toward
performance-based regulation.
Utilities are allowed a reasonable opportunity to recover their
stranded costs through December 31, 2001. Stranded costs such as
reasonable employee-related costs directly caused by restructuring and
purchased-power contracts (including those with qualifying facilities)
may be recovered beyond 2001, subject to a reasonableness review.
SDG&E's transition-cost application, filed in October 1996,
identified $2 billion of estimated stranded costs, including generation,
purchased-power and qualifying facilities' contracts, and regulatory
assets. The amount includes sunk costs, as well as ongoing costs the
CPUC finds necessary to maintain generation facilities through December
31, 2001. These identified transition costs were determined to be
34
reasonable by independent auditors selected by the CPUC, with $73
million identified as requiring further action before being deemed
recoverable transition costs. Through December 31, 1997, SDG&E has
recovered transition costs of $0.2 billion for nuclear generation and
$0.1 billion for nonnuclear generation. Additionally, overcollections of
$0.1 billion recorded in the Energy Cost Adjustment Clause (ECAC) and
the Electric Revenue Adjustment Mechanism (ERAM) balancing accounts as
of December 31, 1997, have been applied to transition cost recovery,
leaving approximately $1.6 billion for future CTC recovery. Included
therein is $0.4 billion for post-2001 purchased-power-contract payments
that may be recovered after 2001, subject to an annual reasonableness
review. Outside of the exceptions discussed above, transition costs not
recovered by December 31, 2001, will not be collected from customers.
Such costs, if any, would be written off as a charge against earnings.
AB 1890 clarifies that all existing and future consumers must pay CTC,
except for a segment of self-generators and irrigation districts. SDG&E
has very few, if any, of these types of customers and does not
anticipate a material impact from the exemption. During the 1998-2001
period, the recovery of transition costs is limited by the rate freeze
(discussed below). Management believes that the rates within the rate
freeze and the proceeds from the sale of electric-generating assets
(discussed below) will be sufficient to recover all of SDG&E's approved
transition costs by December 31, 2001.
In November 1997, the CPUC issued a decision allowing SDG&E the
opportunity to recover all of its sunk nonnuclear generation costs, with
the exception of $39 million in fixed costs relating to gas
transportation to power plants, which SDG&E believes will be recovered
through contracts with the ISO. The decision does not include generation
plant additions made after December 20, 1995. Instead, SDG&E must file
an application seeking a CPUC reasonableness review thereof. In October
1997, SDG&E filed an application with the CPUC seeking recovery of $14.5
million in 1996 capital additions for the Encina and South Bay power
plants. A final CPUC decision is expected in 1998.
Rate-Reduction Bonds AB 1890 required a 10-percent rate reduction for
residential and small-commercial customers beginning in January 1998. AB
1890 also provided for the issuance of rate-reduction bonds by an agency
of the state of California to enable California's investor-owned
electric utilities (IOUs) to use the proceeds to finance this rate
reduction. In December 1997, $658 million of rate-reduction bonds were
issued on behalf of SDG&E at an average interest rate of 6.26 percent.
These bonds are being repaid over 10 years by SDG&E's residential and
small-commercial customers via a nonbypassable charge on their
electricity bills. In September 1997, SDG&E and the other California
IOUs received a favorable ruling by the Internal Revenue Service on the
tax treatment of the bond transaction. The ruling states, among other
things, that the receipt of the bond proceeds does not result in gross
income to SDG&E at the time of issuance, but rather the proceeds are
taxable over the life of the bonds. The Securities and Exchange
Commission determined that these bonds should be reflected on the
utilities' balance sheets as debt, even though the bonds are not secured
by, or payable from, utility assets, but rather by the revenue streams
collected from customers. SDG&E formed a subsidiary, SDG&E Funding LLC,
to facilitate the issuance of the rate-reduction bonds. In exchange for
the bond proceeds, SDG&E sold to SDG&E Funding all of its rights to the
revenue streams. Consequently, the revenue streams are not the property
of SDG&E nor are they available to satisfy any claims of SDG&E's
creditors. There was no gain or loss recorded from the issuance of the
bonds or the receipt of the proceeds. SDG&E has begun to use a portion
of the proceeds to redeem its higher cost debt, described herein under
"Liquidity and Capital Resources - Financing Activities." In December
35
1997, the California Supreme Court dismissed a petition submitted by a
coalition of consumer groups to overturn the CPUC's Rate-Reduction Bond
financing orders. A related coalition of consumer groups has also put
together a California ballot initiative that, among other things, would
possibly result in an additional 10-percent rate reduction, require that
this rate reduction be achieved through the elimination or reduction of
CTC payments and prohibit the collection of the charge on customer bills
that would finance the rate reduction. SDG&E cannot predict the final
outcome of the initiative. If the initiative were to be voted into law
and upheld by the courts, the financial impact on SDG&E could be
substantial.
Electric Rates AB 1890 included a rate freeze for all customers. Until
the earlier of March 31, 2002, or when transition cost recovery is
complete, SDG&E's average system rate will be frozen at 9.64 cents per
kilowatt-hour, except for the impacts of natural gas price changes and
the mandatory 10-percent rate reduction. As a result of significant
increases in natural gas prices during the first quarter of 1997, SDG&E
received CPUC authority to increase rates, but rates could not be
increased above 9.985 cents per kwh. With the 10-percent rate reduction
beginning on January 1, 1998, the maximum system-average rate became
9.43 cents per kwh. SDG&E's ability to recover its transition costs is
dependent on its total revenues under the rate freeze exceeding normal
cost-of-service revenues during the transition period by at least the
amount of the CTC less any proceeds from the sale of electric-generating
assets (discussed below). During the transition period, SDG&E will not
earn awards from special programs, such as DSM, unless total revenues
are also adequate to cover the awards. Fuel-price volatility is the most
significant variable in the ability of SDG&E to recover its transition
costs and program awards.
Balancing Accounts In October 1997, the CPUC issued a decision
eliminating the ECAC and the ERAM balancing accounts, effective December
31, 1997. As of December 31, 1997, net overcollections for these
accounts of $130 million have been transferred to the interim
transition-cost-balancing account to be applied to CTC recovery, subject
to a reasonableness review. The decision eliminates further ECAC
proceedings for generation costs incurred beginning in January 1998.
Additionally, the decision eliminates all other electric balancing
accounts, except for those associated with the administration of DSM,
low-income assistance, and research and development (R&D) programs,
which will be used to assist in the administration of public-purpose
funds (discussed below). In addition, SDG&E has requested the retention
of the Electric Vehicle balancing account through December 31, 1998. The
elimination of ERAM and ECAC resulted in earnings volatility that began
in the first quarter of 1997. Although no effect in 1997 was seen for
the full year, quarterly earnings fluctuated significantly, as was the
case for the other California IOUs. The largest impacts were reduced
first-quarter earnings and increased third-quarter earnings. This
quarterly volatility pattern is expected to continue in the future.
Beginning in 1998, annual earnings also will be affected by sales
volumes.
Regulatory Accounting Standards SDG&E had been accounting for the
economic effects of regulation on all of its utility operations in
accordance with Statement of Financial Accounting Standards (SFAS) No.
71, "Accounting for the Effects of Certain Types of Regulation." Under
SFAS No. 71, a regulated entity 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 revenues for amounts due to customers.
36
The SEC indicated a concern that the California IOUs may not meet
the criteria of SFAS No. 71 with respect to their electric-generation
net regulatory assets. SDG&E has ceased the application of SFAS No. 71
to its generation business, in accordance with the conclusion by the
Emerging Issues Task Force of the Financial Accounting Standards Board
that the application of SFAS No. 71 should be discontinued when
deregulatory legislation is issued that determines that a portion of an
entity's business will no longer be regulated. SDG&E's discontinuance of
SFAS No. 71 applied to its generation business will not result in a
write-off of its net regulatory assets, since the CPUC has approved the
recovery of these assets by the distribution portion of its business,
subject to the rate freeze.
Consumer Education In August 1997, the CPUC authorized $89 million in
rate recovery to fund California's Customer Education Program (CEP).
SDG&E's share of this amount is approximately $9 million. The CEP's
objective is to provide information to California electric customers to
help them compare and choose among electric products and services in a
competitive environment. The CEP began in September 1997 and is expected
to end by May 31, 1998.
Public-Purpose Programs The CPUC has established a new administrative
structure and initial funding levels to manage DSM, renewable-energy,
low-income assistance and R&D programs beginning in January 1998. The
CPUC has formed independent boards to oversee a competitive bidding
process to administer DSM and low-income programs. On an interim basis,
the CPUC has required that the California IOUs transfer their
administration of DSM and low-income programs to these boards by October
1998, and January 1999, respectively. Until the transition to a fully
competitive energy-service market is complete, customers will be
required to provide the funding. For 1998, SDG&E will be funded $32
million and $12 million for DSM and renewables programs, respectively.
Low-income assistance funding will remain at 1996 authorized levels. The
California Energy Commission will be allocated most of the $63 million
authorized to administer the R&D programs, of which SDG&E will be funded
$4 million. SDG&E's earnings potential from DSM programs will be reduced
when the transition to the competitive market is complete.
Federal Restructuring Activities In October 1997, the FERC approved
key elements of the California IOUs' restructuring proposal effective
January 1, 1998. This includes the transfer by the IOUs of the
operational control of their transmission facilities to the ISO, which
is under FERC jurisdiction. The FERC also approved, on an interim basis,
the establishment of the California PX to operate as an independent
wholesale power pool. The California IOUs will pay to the PX a
restructuring charge (in four annual installments) and an
administrative-usage charge for each megawatt-hour of volume transacted.
SDG&E's share of the restructuring charge is approximately $10 million,
which is eligible for transition-cost recovery. The IOUs have jointly
guaranteed $300 million of commercial loans to the PX and ISO for their
development and initial start-up. SDG&E's share of the guarantee is $30
million.
ELECTRIC GENERATION
In November 1997, SDG&E's Board of Directors approved a plan to auction
the company's power plants and other electric-generating assets,
enabling SDG&E to continue to concentrate its business on the
transmission and distribution of electricity and natural gas as
California opens its electric utility industry to competition in 1998.
The plan includes the divestiture of SDG&E's fossil power plants - the
Encina (Carlsbad, California) and South Bay (Chula Vista, California)
37
plants - and its combustion turbines, as well as its 20-percent interest
in the San Onofre Nuclear Generating Station (SONGS) and its portfolio
of long-term purchased-power contracts, including those with qualifying
facilities. The power plants, including the interest in SONGS, have a
net book value as of December 31, 1997, of $800 million ($200 million
for fossil and $600 million for SONGS) and a combined generating
capacity of 2,400 megawatts. The proceeds from the auction will be
applied directly to SDG&E's transition costs. In December 1997, SDG&E
filed with the CPUC for its approval of the auction plan. The sale of
the nonnuclear generating assets is expected to be completed by the end
of the first quarter of 1999.
Although the other California IOUs are required by the CPUC to
divest themselves of at least 50 percent of their fossil power plants as
a part of industry restructuring, SDG&E is not under the same mandate.
Other companies in the free market, not bound by the rules that apply to
the state's regulated utilities, are expected to have a greater
opportunity to provide competitive generation services with SDG&E's
plants. The FERC has ruled that it has jurisdiction over all electricity
sales into the California PX, meaning that the buyers of divested
California power plants would qualify as wholesale power generators. The
FERC's ruling has increased the interest in the nonnuclear plants owned
by the other California IOUs, and is expected to have the same impact on
SDG&E's fossil plants.
As previously discussed, subsidiaries of Enova Energy and Houston
Industries have formed a joint venture to build, own and operate a 480-
megawatt natural gas-fired power plant in Boulder City, Nevada, 40 miles
southeast of Las Vegas. The joint venture, called El Dorado Energy,
plans to sell the plant's electricity into the wholesale market to
utilities throughout the western United States. The new plant will
employ an advanced combined-cycle gas-turbine technology, enabling it to
become one of the more efficient and environmentally friendly power
plants in the nation. Its proximity to existing natural gas pipelines
and electric transmission lines will allow El Dorado to actively compete
in the deregulated electric-generation market. Construction on the $280
million project, which will be funded 50 percent each by Enova and
Houston Industries, began in the first quarter of 1998, with an expected
operational date set for the fourth quarter of 1999.
AFFILIATE TRANSACTION GUIDELINES
In December 1997, the CPUC issued a decision on the rules governing
transactions between a regulated utility and its affiliates that are not
regulated by the CPUC. The decision adopts guidelines that are more
favorable to consumers and less restrictive to utilities and their
affiliates than the conditions that were recommended in October 1997 by
a CPUC administrative law judge's proposed decision and an alternate
decision by two CPUC commissioners. Key elements of the decision
include: allowing the unregulated affiliates to operate within the
utility's service territory without limitation; permitting utilities to
share logos with their parent company and unregulated affiliates as long
as proper disclaimers to California customers clearly communicate the
utility-affiliate relationship; and allowing officers or board of
directors of the parent company to also hold positions with the utility
or unregulated affiliate, but not both. The rules adopted require
separating functions between the utility and the affiliates with the
exception of sharing certain corporate support services. These
guidelines include transactions between affiliated utilities. However,
these transactions have been addressed by the CPUC in the Enova/Pacific
Enterprises business combination proceedings and the draft decision
arising from that proceeding would exclude transactions between SDG&E
and SoCalGas from the guidelines.
38
PERFORMANCE-BASED RATEMAKING (PBR)
Background The CPUC has affirmed its belief that the new competitive
environment should be based on policies that encourage efficient
operation and improved productivity rather than on reasonableness
reviews and disallowances. SDG&E has been participating in a PBR process
for base rates, gas procurement, and electric generation and dispatch.
SDG&E has applied to extend the Gas Procurement mechanism. The
Generation and Dispatch mechanism has been terminated. SDG&E has filed a
proposal for a new Distribution PBR mechanism to replace the current
experimental Base-Rate PBR when it terminates at the end of 1998.
Base Rates In December 1997, the CPUC approved $6.5 million in
performance rewards for SDG&E's 1996 PBR. The CPUC has eliminated the
price-performance benchmark indicator, which compares SDG&E's average
electric-system rate to a national average, from SDG&E's Base-Rate PBR
effective in 1997 due to the electric-rate freeze. For the 1998 PBR, all
customer sharing amounts will be credited to the transition-cost
balancing account rather than refunded to customers.
In December 1997, the CPUC eliminated SDG&E's 1999 General Rate Case
filing requirement, and replaced it with a 1999 Cost of Service study in
its new Distribution PBR application for electric distribution and gas
operations (filed in January 1998 to begin in 1999). The Distribution
PBR, which includes six categories of performance indicators, will
measure SDG&E's ability to provide efficient, safe and reliable utility
transmission (gas only) and distribution services. The application
requests a $60 million increase in SDG&E's revenue requirements ($35
million for electric distribution and $25 million for gas). The electric
distribution increase does not affect rates and, therefore, reduces the
amount available to recover transition costs. Under the new mechanism,
all customer-sharing amounts will be reflected as reductions to future
rates rather than refunded directly to customers. SDG&E's ability to
control its costs within the limits of the revenues authorized by the
study will impact future earnings.
1998 Revenues In December 1997, the CPUC approved a $67 million
increase in SDG&E's authorized electric distribution revenue
requirements and a $7 million increase in gas base rates, effective on
January 1, 1998. The electric distribution increase, which reflects 1998
PBR escalations, does not affect rates and, therefore, reduces the
amount available to recover transition costs.
Natural Gas In September 1997, SDG&E filed with the CPUC its
application for a permanent Gas Procurement PBR mechanism. The filing
proposes a mechanism structured around a commodity price cap plus an
incremental adjustment, designed to recover transportation costs to the
California border. SDG&E is holding settlement discussions with the
CPUC's Office of Ratepayer Advocates over the proposed
new mechanism.
NATURAL GAS OPERATIONS
The ongoing restructuring of the natural gas utility industry has
allowed customers to bypass utilities as suppliers and, to a lesser
extent, as transporters of natural gas. Currently, nonutility
electricity producers and other large customers may use a natural gas
utility's facilities to transport gas purchased from other suppliers.
Also, smaller customers may form groups to buy natural gas from another
supplier.
In January 1998, the CPUC opened a rulemaking proceeding designed to
open the natural gas industry to all customers, expanding the
opportunities of residential and small commercial customers to have
access to competing natural gas suppliers. The rulemaking will allow
39
smaller customers to receive the price and service benefits already
realized by larger customers. A potential benefit from future natural
gas reform, benefiting both customers and industry participants, would
be the opportunity for energy providers to offer integrated retail
electric and natural gas service to develop synergies between the two
energy markets. In developing a natural gas retail restructuring
proposal, the CPUC has provided several guiding principles: replace
traditional regulation with competition in those markets where
competition or the potential for competition exists, thereby allowing
market forces to dictate prices; reform regulation for those utility
functions that are not fully competitive; maintain a standard of
consumer protection in both competitive and noncompetitive markets; and
maintain supply reliability and ensure the safety of consumers' natural
gas service. Hearings on the proposed restructuring are scheduled to
begin in April 1998, with a final CPUC decision expected to be issued
before the end of 1998.
Enova's nonutility subsidiaries are involved in several projects to
develop natural gas systems in the United States and in Mexico.
Discussion on these activities is included herein under "Liquidity and
Capital Resources - Investing Activities."
COST OF CAPITAL
In October 1997, SDG&E filed with the CPUC its 1998 Market Indexed
Capital Adjustment Mechanism (MICAM). MICAM, approved by the CPUC in
1996, adjusts SDG&E's authorized cost of capital based on changes in
interest rates. For the current MICAM review, interest-rate movements
over the corresponding 12 months did not trigger the mechanism to
change, resulting in SDG&E's 1998 cost of capital remaining at 1997
authorized levels of 11.60 percent for the rate of return on equity and
9.35 percent for the rate of return on rate base. Beginning in 1998,
MICAM only applies to electric distribution and gas rate base, and
excludes the rates of return on nuclear and nonnuclear generating assets
(recovered as transition costs), which are authorized at rates of 7.14
percent and 6.75 percent, respectively. During 1998, the CPUC will
conduct proceedings to establish separate rates for the electric and gas
components. SDG&E's authorized capital structure, which excludes the
rate-reduction bonds, remains 49.75 percent common equity, 44.5 percent
long-term debt and 5.75 percent preferred stock.
Electric transmission rates are regulated by the FERC. SDG&E's 1998
rate of return for transmission is 9.54 percent.
RESOURCE PLANNING
Sources of Fuel and Energy SDG&E's primary sources of fuel and
purchased power include natural gas from Canada and the Southwest,
surplus power from other utilities in the Southwest and the Northwest,
and uranium from Canada. Although short-term natural gas supplies are
volatile due to weather and other conditions, these sources should
provide SDG&E with an adequate supply of competitively priced natural
gas. SDG&E has been involved in litigation concerning its long-term
contracts for natural gas with four Canadian suppliers. SDG&E has
settled with one supplier, with gas being delivered under the terms of
the settlement agreement. The remaining suppliers have ceased deliveries
pending legal resolution. A U.S. Court of Appeals has upheld a U.S.
District Court's decision to invalidate the contracts with two of the
suppliers, although the value of the gas delivered has not yet been
determined by the court. SDG&E has long-term pipeline capacity
commitments related to these contracts for natural gas supplies. If the
supply of Canadian natural gas to SDG&E is not resumed, SDG&E intends to
use the capacity in other ways, including the release of a portion of
this capacity to third parties. SDG&E cannot predict the final outcome
of the litigation, but does not expect that an unfavorable outcome would
40
have a material effect on its financial condition, results of operations
or liquidity. Additional information on Canadian gas litigation is
discussed in Note 9 of the notes to consolidated financial statements.
San Onofre Nuclear Generating Station In January 1996, the CPUC
approved the accelerated recovery of the existing capital costs of Units
2 and 3. The decision allowed SDG&E to recover its remaining investment
in the units at a lower rate of return (7.14 percent) over an eight-year
period beginning in 1996, rather than over the life of the units'
license, which extends to 2013. The accelerated recovery began in April
1996. At December 31, 1997, approximately $600 million was not yet
recovered. California electric-industry-restructuring legislation
requires that all generation-related stranded assets, which includes the
uneconomic sunk costs of Units 2 and 3, be recovered by 2001. The 1996
decision also includes a performance incentive plan that encourages
continued, efficient operation of the plant. Under this plan, customers
will pay about $0.04 per kilowatt-hour through December 31, 2003. This
pricing structure replaces the traditional method of recovering the
units' operating expenses and capital improvements. This is intended to
make the units more competitive with other sources.
The California Coastal Commission (CCC) approved the SONGS owners'
preliminary plan to provide 150 acres of wetlands restoration, 150 acres
of kelp reef and other mitigation that was ordered by the CCC in April
1997. SDG&E's share of the cost is estimated to be $23 million.
Additional information is included under "Water Quality" below.
While conducting routine inspections of Unit 3 during its scheduled
refueling in the second quarter of 1997, it was noted that, in several
areas, the thickness of the heat transfer tubes' structural supports was
significantly reduced, apparently due to erosion. In June 1997, the
Nuclear Regulatory Commission approved the removal of the affected tubes
from service as a corrective action and the unit's return to service.
Unit 2, which also had this inspection during its scheduled refueling in
the first quarter of 1997, showed no signs of this type of erosion. As a
precautionary measure, Unit 2 was shut down in January 1998 for a 30-day
mid-cycle outage for an inspection of its steam generators. The SONGS
owners have scheduled a 30-day outage for Unit 3 in March 1998, for this
inspection. The discovery of such problems in the future could increase
the possibility that the units would be removed from service prior to
2013.
ENVIRONMENTAL MATTERS
SDG&E's operations are conducted in accordance with federal, state and
local environmental laws and regulations governing hazardous wastes, air
and water quality, land use and solid-waste disposal. SDG&E incurs
significant costs to operate its facilities in compliance with these
laws and regulations, and to clean up the environment as a result of
prior operations of SDG&E or of others.
The costs of compliance with environmental laws and regulations are
normally recovered in customer rates. However, restructuring of the
California electric-utility industry (see "Electric Industry
Restructuring" above) will change the way utility rates are set and
costs are recovered. SDG&E has proposed a change in the hazardous waste
memorandum account to exclude cleanup costs related to electric-
generation activities, as described below. Capital costs related to
environmental regulatory compliance for electric generation are intended
to be included in transition costs for recovery through 2001. However,
depending on the final outcome of industry restructuring and the impact
of competition, the costs of compliance with future environmental
regulations may not be fully recoverable.
Capital expenditures to comply with environmental laws and
regulations were $4 million in 1997, $6 million in 1996 and $4 million
41
in 1995, and are expected to be $38 million in the aggregate over the
next five years. These expenditures primarily include the estimated cost
of retrofitting SDG&E's power plants to reduce air emissions. However,
in November 1997 SDG&E announced a plan to auction its power plants and
other electric-generating resources. Additional information on SDG&E's
plan to divest its electric-generating assets is discussed in Note 10 of
the notes to consolidated financial statements.
Hazardous Wastes In 1994, the CPUC approved the Hazardous Waste
Collaborative, which allows utilities to recover cleanup costs of
hazardous waste contamination at sites where the utility may have
responsibility or liability under the law to conduct or participate in
any required cleanup. In general, utilities are allowed to recover 90
percent of their cleanup costs and any related costs of litigation with
responsible parties. SDG&E has asked the CPUC that beginning on January
1, 1998, the hazardous waste memorandum account be modified to exclude
cleanup costs related to electric-generation activities. Electric-
generation-related cleanup costs are intended to be eligible for
transition cost recovery. A CPUC decision is still pending.
SDG&E lawfully disposed of hazardous wastes at facilities owned and
operated by other entities. Operations at these facilities may result in
actual or threatened risks to the environment or public health. Where
the owner or operator of such a facility fails to complete any
corrective action required by regulatory agencies to abate such risks,
applicable environmental laws may impose an obligation to undertake
corrective actions on SDG&E and others who disposed of hazardous wastes
at the facility.
During the early 1900s, SDG&E and its predecessors manufactured gas
from coal and oil at its Station A facility and at two small facilities
in Escondido and Oceanside. Certain amounts of residual by-products from
the gas manufacturing process and subsurface hydrocarbon contamination
were discovered on portions of the Station A site during an
environmental assessment which was completed in 1996. A risk assessment
has been completed for Station A and demolition was performed during
1997 at a cost of $1 million. Cleanup will commence in 1998, to be
completed in 1999, and is estimated to cost $5 million for subsurface
remediation. SDG&E also may be required to assess certain off-site
contamination which, in part, may have originated from the gas
manufacturing process or other operations at Station A. Not included in
this estimate are potential costs related to a previously removed
shallow underground tank-like structure found under a public street
immediately west of Station A. Any potential costs related to this tank
would be immaterial. SDG&E is completing negotiations for an appropriate
site-remediation work plan for Station A with the County of San Diego
Department of Environmental Health.
The Escondido facility was remediated during 1990 through 1993 at a
cost of $3 million and a site-closure letter from the Department of
Environmental Health has been received. However, contaminants similar to
those on the Escondido site have been observed on adjacent property. In
1997, SDG&E assessed the nature and extent of these off-site
contaminants at a cost of $75,000. Hazardous contaminants were found on
property to the east of the site and are believed to have originated
from SDG&E operations. Remediation of these contaminants was initiated
in 1997 and completed in 1998 at a total cost of $250,000. A site-
closure letter has been requested from the Department of Environmental
Health. Nonhazardous contaminants were determined to be present on
property to the north, but may not require further action subject to
future land-use decisions. Finally, potential contaminants resulting
from the gas manufacturing process by-products were assessed at the
Oceanside facility, as well as on adjacent property. The cost to
remediate the hazardous contaminants discovered in the assessment at the
42
property adjacent to the Oceanside facility and at the facility itself
is estimated to be $150,000.
Asbestos was used in the construction of SDG&E's Station B power
plant, which closed in 1993. Activities to dismantle and decommission
the facility require the removal of the asbestos in a manner complying
with all applicable environmental, health and safety laws. This work
also includes the removal or cleanup of paints containing heavy metals
and small amounts of PCBs, fuel oil and other substances. These
activities commenced in 1997 at a cost of $3 million. This work effort
is expected to be completed in 1998 at an estimated additional cost of
$3 million.
Electric and Magnetic Fields (EMFs) In property-damage litigation in
1996, the California Supreme Court agreed with SDG&E and unanimously
affirmed the 1995 California Court of Appeal decision that the CPUC has
exclusive jurisdiction over EMF health and safety issues. The California
Supreme Court also stated that scientific evidence is insufficient to
conclude that EMFs pose a health hazard. In addition, in a December 1997
case involving Pacific Gas & Electric, the California Court of Appeal
held that the CPUC has exclusive jurisdiction over EMF personal injury,
as well as EMF property-damage cases. Plaintiffs have sought review of
this case at the California Supreme Court, which request is still
pending.
Although scientists continue to research the possibility that
exposure to EMFs causes adverse health effects, to date, science has
demonstrated no cause-and-effect relationship between adverse health
effects and exposure to the type of EMFs emitted by utilities, power
lines and other electrical facilities. Some laboratory studies suggest
that such exposure creates biological effects, but those effects have
not been shown to be harmful. The studies that have most concerned the
public are certain epidemiological studies, some of which have reported
a weak correlation between childhood leukemia and the proximity of homes
to certain power lines and equipment. Other epidemiological studies
found no correlation between estimated exposure and any disease.
Scientists cannot explain why some studies using estimates of past
exposure report correlations between estimated EMF levels and disease,
while others do not.
To respond to public concerns, the CPUC has directed California
utilities to adopt a low-cost EMF-reduction policy that requires
reasonable design changes to achieve noticeable reduction of EMF levels
that are anticipated from new projects. However, consistent with the
major scientific reviews of the available research literature, the CPUC
has indicated that no health risk has been identified.
Air Quality The San Diego Air Pollution Control District (APCD)
regulates air quality in San Diego County in conformance with the
California and Federal Clean Air Acts. California's standards are more
restrictive than federal standards.
During 1996 and 1997, SDG&E installed equipment on South Bay Unit 1
in order to comply with the nitrogen oxide emission limits that the APCD
imposed on electric-generating boilers through its Rule 69. Under this
rule, SDG&E must maintain the total nitrogen oxide emissions from its
entire system below a prescribed emissions cap, which decreases
periodically through 2005. The estimated capital costs for compliance
with the rule through 2005 are $60 million. The California Air Resources
Board has expressed concern that Rule 69 does not meet the requirements
of the California Clean Air Act and may advocate or propose more
restrictive emissions limitations which will likely cause SDG&E's Rule
69 compliance costs to increase.
Under a South Coast Air Quality Management District program called
RECLAIM, SDG&E is required to reduce its nitrogen oxide emission levels
43
of the natural gas compressor engines at its Moreno gas-compression
facility by 10 percent a year through 2003. This will be accomplished
through the installation of new emission-monitoring equipment,
operational changes to take advantage of low-emission engines and engine
retrofits. The cost of complying with RECLAIM may be as much as $3
million.
Water Quality Wastewater discharge permits issued by the Regional
Water Quality Control Board (RWQCB) for SDG&E's Encina and South Bay
power plants are required to enable SDG&E to discharge its cooling water
and certain other wastewaters into the Pacific Ocean and into San Diego
Bay. Wastewater discharge permits are prerequisite to the continued
cooling-water and other wastewater discharges and, therefore, the
continued operation of the power plants as they are currently
configured. Increasingly stringent cooling-water and wastewater
discharge limitations may be imposed in the future and SDG&E may be
required to build additional facilities or modify existing facilities to
comply with these requirements. Such facilities could include wastewater
treatment facilities, cooling towers or offshore-discharge pipelines.
Any required construction could involve substantial expenditures, and
certain plants or units may be unavailable for electric generation
during construction.
In 1981, SDG&E submitted a demonstration study in support of its
request for two exceptions to certain thermal discharge requirements
imposed by the California Thermal Plan for Encina power plant Unit 5. In
November 1994, the RWQCB issued a new discharge permit, subject to the
results of certain additional thermal discharge and cooling water
related studies, to be used in considering SDG&E's earlier thermal
discharge exception requests. The results of these additional studies
were submitted to the RWQCB and the United States Environmental
Protection Agency in 1997. If SDG&E's exception requests are denied,
SDG&E could be required to construct off-shore discharge facilities at a
cost of $75 million to $100 million or to perform mitigation, the costs
of which may be significant.
In November 1996, the RWQCB issued a new discharge permit to SDG&E
for the South Bay power plant. SDG&E filed an appeal to the State Water
Resources Control Board (SWRCB) of various provisions which SDG&E
considers unduly stringent. The SWRCB has not yet formally acted on the
appeal. However, the SWRCB sponsored workshops with the RWQCB and the
Environmental Health Coalition in November and December 1997, as a
result of which several important issues may be resolved in 1998. As
with the Encina power plant, increasingly stringent cooling-water and
wastewater discharge limitations may require SDG&E to build additional
facilities to comply with these requirements. To comply with its current
permit, in 1997 SDG&E diverted its in-plant wastewater discharges from
San Diego Bay to the sanitary sewer at a cost of $2 million.
During 1997, in conjunction with its permit requirements to treat
wastewater at its Encina and South Bay power plants, SDG&E evaluated
whether any remediation activities may be required at the power plants
based on currently available records and other information. In addition,
SDG&E evaluated whether remediation is required at its Silvergate plant,
which was shut down in 1984. As a result of these evaluations, only
minor and localized remediation efforts were required. However, these
evaluations did not include an extensive sampling and analysis of the
property at such sites. Extensive sampling and analysis may identify
additional contamination or other environmental conditions requiring
remediation.
As previously discussed, in December 1997, SDG&E filed an
application with the CPUC to divest its electric-generating assets,
including its Encina and South Bay power plants, gas combustion turbines
and its interest in the San Onofre Nuclear Generating Station. As a part
44
of the sale of any such facilities, SDG&E will complete an environmental
baseline analysis of such sites, which may identify significant
contamination or other environmental conditions requiring abatement or
remediation.
The California Coastal Commission (CCC) required a study of the
offshore impact on the marine environment from the cooling-water
discharge by SONGS Units 2 and 3 as a condition of granting a
construction permit. The study concluded that some environmental damage
is caused by the discharge. To mitigate the damage, the CCC ordered
Southern California Edison, SDG&E and the cities of Anaheim and
Riverside to improve the plant's fish-protection system, build a 300-
acre artificial reef to help restore kelp beds and restore 150 acres of
coastal wetlands. SDG&E and Edison asked the CCC to reconsider and
modify this mitigation plan to reduce the size of the artificial reef
and shorten the monitoring period based on new studies that show that
the environmental damage is much less than anticipated. During 1997 the
CCC ordered that the plant owners proceed with a mitigation program that
includes the enhanced fish-protection system, a 150-acre artificial reef
and restoration of 150 acres of coastal wetlands. In addition, plant
owners must deposit $3.6 million with the state for the enhancement of
marine fish hatchery programs and pay for state monitoring and oversight
of the mitigation projects. SDG&E's share of the cost is estimated to be
$23 million. The pricing structure contained in the CPUC's decision
regarding accelerated recovery of SONGS Units 2 and 3 (see "San Onofre
Nuclear Generating Station" above) likely will accommodate most of these
added mitigation costs.
NEW ACCOUNTING STANDARDS
In June 1997, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 130, "Reporting
Comprehensive Income." This statement, which is effective for 1998
financial statements, requires reporting and display of comprehensive
income and its components (revenues, expenses, gains and losses) in a
full set of general-purpose financial statements. The term
"comprehensive income" describes all changes in equity of a business
enterprise during a period from transactions and other events including,
as applicable, foreign-currency items, minimum pension liability
adjustments and unrealized gains and losses on certain investments in
debt and equity securities. Upon adoption, financial statements for
earlier periods provided for comparative purposes must be restated. The
impact on Enova and SDG&E of the adoption of this new accounting
standard is considered immaterial to the companies' financial
statements.
Also in June 1997, the FASB issued SFAS No. 131, "Disclosures about
Segments of an Enterprise and Related Information." This statement,
which is effective for 1998 financial statements, requires that public
companies report certain information about operating segments in
complete sets of financial statements of the enterprise and in condensed
financial statements of interim periods. It also requires certain
information about the company's products and services, geographic areas
in which they operate, and their major customers. Under SFAS No. 131,
operating segments are to be determined consistent with the way that
management organizes and evaluates financial information internally for
making operating decisions and assessing performance. Upon adoption,
statements for earlier periods provided for comparative purposes must
reflect this information. The impact of the adoption of this new
accounting standard is the potential redefinition of the company's
segments. The company estimates that the primary segments upon adoption
of SFAS No. 131 will be electric operations, gas operations, energy
services and other.
45
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report to Shareholders includes forward-looking statements
within the definition of Section 27A of the Securities Act of 1933 and
Section 21E of the Securities Exchange Act of 1934. When used in this
"Management's Discussion and Analysis of Financial Condition and Results
of Operations," the words "estimates," "expects," "anticipates," "plans"
and "intends," variations of such words, and similar expressions are
intended to identify forward-looking statements that involve risks and
uncertainties.
Although Enova and SDG&E believe that their expectations are based
on reasonable assumptions, they can give no assurance that those
expectations will be realized. Important factors that could cause actual
results to differ materially from those in the forward-looking
statements herein include political developments affecting state and
federal regulatory agencies, the pace and substance of electric-industry
deregulation in California and in the United States, the ability to
effect a coordinated and orderly implementation of both state
legislation and the CPUC's restructuring regulations, the consummation
and timing of the proposed business combination of Enova and Pacific
Enterprises, the timing and level of proceeds of sales of SDG&E's
electric-generating assets, the level of sales of electricity, the rate
of growth of nonutility subsidiary revenues, international political
developments, environmental regulations, and the timing and extent of
changes in interest rates and prices for natural gas and electricity.
46
Item 8. Financial Statements and Supplementary Data - Enova Corporation
ENOVA CORPORATION
STATEMENTS OF CONSOLIDATED INCOME
In thousands except per share amounts
For the years ended December 31 1997 1996 1995
------------ ------------ ------------
Operating Revenues
Electric $1,769,421 $1,590,882 $1,503,926
Gas 398,127 348,035 310,142
Other 49,459 54,557 56,608
------------ ------------ ------------
Total operating revenues 2,217,007 1,993,474 1,870,676
------------ ------------ ------------
Operating Expenses
Electric fuel 163,765 134,350 100,256
Purchased power 441,490 310,731 341,727
Gas purchased for resale 183,208 152,408 113,355
Maintenance 87,597 57,652 91,740
Depreciation and decommissioning 347,438 332,490 278,239
Property and other taxes 43,419 44,764 45,566
General and administrative 223,032 262,058 210,207
Other 222,727 212,245 209,358
Income taxes 160,161 151,813 134,578
------------ ------------ ------------
Total operating expenses 1,872,837 1,658,511 1,525,026
------------ ------------ ------------
Operating Income 344,170 334,963 345,650
------------ ------------ ------------
Other Income and (Deductions)
Allowance for equity funds used
during construction 5,192 5,898 6,435
Taxes on nonoperating income 9,959 3,339 (27)
Other - net 1,653 (3,265) (5,876)
------------ ------------ ------------
Total other income 16,804 5,972 532
------------ ------------ ------------
Income Before Interest Charges and
Preferred Dividends 360,974 340,935 346,182
------------ ------------ ------------
Interest Charges and Preferred Dividends
Long-term debt 85,617 89,198 95,523
Short-term debt and other 19,474 17,516 20,215
Allowance for borrowed funds
used during construction (2,306) (3,288) (2,865)
Preferred dividend requirements of SDG&E 6,582 6,582 7,663
------------ ------------ ------------
Net interest charges and preferred dividends 109,367 110,008 120,536
------------ ------------ ------------
Income From Continuing Operations 251,607 230,927 225,646
Discontinued Operations, Net of Income Taxes -- -- 148
------------ ------------ ------------
Earnings Applicable to Common Shares $ 251,607 $ 230,927 $ 225,794
============ ============ ============
Average Common Shares Outstanding 114,322 116,572 116,535
============ ============ ============
Earnings Per Common Share (basic and diluted) $ 2.20 $ 1.98 $ 1.94
============ ============ ============
Dividends Declared Per Common Share $ 1.56 $ 1.56 $ 1.56
============ ============ ============
See notes to consolidated financial statements.
47
ENOVA CORPORATION
CONSOLIDATED BALANCE SHEETS
In thousands of dollars
Balance at December 31 1997 1996
-------------- --------------
ASSETS
Utility plant - at original cost $5,888,539 $5,704,464
Accumulated depreciation and decommissioning (2,952,455) (2,630,093)
-------------- --------------
Utility plant - net 2,936,084 3,074,371
-------------- --------------
Investments in partnerships and unconsolidated
subsidiaries 516,113 271,035
-------------- --------------
Nuclear decommissioning trust 399,143 328,042
-------------- --------------
Current assets
Cash and temporary investments 624,375 173,079
Accounts receivable 231,678 186,529
Notes receivable 27,083 33,564
Inventories 67,074 63,437
Other 89,826 47,094
-------------- --------------
Total current assets 1,040,036 503,703
-------------- --------------
Deferred taxes recoverable in rates 184,837 189,193
-------------- --------------
Deferred charges and other assets 157,711 282,893
-------------- --------------
Total $5,233,924 $4,649,237
============== ==============
CAPITALIZATION AND LIABILITIES
Capitalization (see Statements of Consolidated
Capital Stock and of Long-Term Debt)
Common equity $1,570,383 $1,569,670
Preferred stock not subject to mandatory redemption 78,475 78,475
Preferred stock subject to mandatory redemption 25,000 25,000
Long-term debt 2,057,033 1,479,338
-------------- --------------
Total capitalization 3,730,891 3,152,483
-------------- --------------
Current liabilities
Current portion of long-term debt 121,700 69,902
Accounts payable 163,395 175,815
Dividends payable 46,050 47,213
Interest accrued 23,160 21,259
Regulatory balancing accounts overcollected - net 58,063 35,338
Other 146,267 158,317
-------------- --------------
Total current liabilities 558,635 507,844
-------------- --------------
Customer advances for construction 37,661 34,666
Accumulated deferred income taxes - net 501,030 497,400
Accumulated deferred investment tax credits 62,332 64,410
Deferred credits and other liabilities 343,375 392,434
Contingencies and commitments (Notes 9 and 10) -- --
-------------- --------------
Total $5,233,924 $4,649,237
============== ==============
See notes to consolidated financial statements.
48
ENOVA CORPORATION
STATEMENTS OF CONSOLIDATED CASH FLOWS
In thousands of dollars
For the years ended December 31 1997 1996 1995
--------- --------- ----------
Cash Flows from Operating Activities
Income from continuing operations $ 251,607 $ 230,927 $ 225,646
Adjustments to reconcile income from continuing
operations to net cash provided by operating activities
Depreciation and decommissioning 347,438 332,490 278,239
Amortization of deferred charges and other assets 6,246 6,556 12,068
Amortization of deferred credits and other
liabilities (37,802) (38,399) (32,975)
Allowance for equity funds used during construction (5,192) (5,898) (6,435)
Deferred income taxes and investment tax credits 18,749 (6,875) (42,237)
Other - net 55,817 73,850 57,475
Changes in working capital components
Accounts and notes receivable (38,668) (7,440) 7,141
Inventories (3,637) 4,522 7,648
Other current assets (23,322) (14,242) (5,609)
Interest and taxes accrued (30,350) (28,199) 23,131
Accounts payable and other current liabilities (24,470) 49,427 26,983
Regulatory balancing accounts 22,725 (37,313) 59,030
Cash flows provided by discontinued operations -- -- 6,148
----------- --------- ---------
Net cash provided by operating activities 539,141 559,406 616,253
----------- --------- ---------
Cash Flows from Financing Activities
Dividends paid (179,586) (181,849) (180,625)
Issuances of long-term debt 677,850 228,946 124,641
Repayment of long-term debt (171,133) (286,668) (165,871)
Short-term borrowings - net -- -- (89,325)
Redemption of common stock (74,122) (480) (241)
Redemption of preferred stock -- (15,155) (18)
---------- ----------- ----------
Net cash provided (used) by financing activities 253,009 (255,206) (311,439)
---------- ----------- ----------
Cash Flows from Investing Activities
Utility construction expenditures (197,184) (208,850) (220,748)
Contributions to decommissioning funds (22,038) (22,038) (22,038)
Other - net (121,632) 3,338 3,874
Discontinued operations -- -- 5,122
---------- ----------- ----------
Net cash used by investing activities (340,854) (227,550) (233,790)
---------- ----------- ----------
Net increase 451,296 76,650 71,024
Cash and temporary investments, beginning of year 173,079 96,429 25,405
---------- ----------- ----------
Cash and temporary investments, end of year $ 624,375 $ 173,079 $ 96,429
========== =========== ==========
Supplemental Schedule of Noncash Investing
and Financing Activities
Real estate investments $ 125,726 $ 96,832 $ 50,496
Cash paid (309) -- (2,550)
----------- ----------- ---------
Liabilities assumed $ 125,417 $ 96,832 $ 47,946
=========== =========== =========
See notes to consolidated financial statements.
49
ENOVA CORPORATION
STATEMENTS OF CONSOLIDATED CHANGES IN
CAPITAL STOCK AND RETAINED EARNINGS
In thousands of dollars
For the years ended December 31, 1995, 1996, 1997
Preferred Stock
-----------------------------
Not Subject Subject to Premium on
to Mandatory Mandatory Common Capital Retained
Redemption Redemption Stock Stock Earnings
--------- --------- --------- --------- --------
Balance, January 1, 1995 $ 93,493 $ 25,000 $ 291,341 $ 564,508 $ 618,581
Earnings applicable to
common shares 225,794
Long-term incentive plan
activity-net 117 1,530
Preferred stock retired
(880 shares) (18) 8
Common stock dividends declared (181,809)
- ----------------------------- --------- --------- --------- --------- ---------
Balance, December 31, 1995 93,475 25,000 291,458 566,046 662,566
Earnings applicable to common shares 230,927
Long-term incentive plan activity-net 113 582
Preferred stock retired
(150,000 shares) (15,000) (155)
Common stock dividends declared (181,867)
- ----------------------------- --------- --------- --------- --------- ---------
Balance, December 31, 1996 78,475 25,000 291,571 566,473 711,626
Earnings applicable to common shares 251,607
Long-term incentive plan activity-net 172 1,158
Common stock retired (3,062,490 shares) (7,656) (66,145)
Common stock dividends declared (178,423)
- ----------------------------- --------- --------- --------- --------- ---------
Balance, December 31, 1997 $ 78,475 $ 25,000 $ 284,087 $ 501,486 $ 784,810
============================= ========= ========= ========= ========= =========
See notes to consolidated financial statements.
50
ENOVA CORPORATION
STATEMENTS OF CONSOLIDATED CAPITAL STOCK
In thousands of dollars except call price
Balance at December 31 1997 1996
----------- ----------
COMMON EQUITY
Common stock, without par value, authorized
300,000,000 shares, outstanding: 1997,
113,634,744 shares; 1996, 116,628,735 shares $ 284,087 $ 291,571
Premium on capital stock 501,486 566,473
Retained earnings 784,810 711,626
----------- ----------
Total common equity $1,570,383 $1,569,670
=========== ==========
PREFERRED STOCK (A) Trading Call
Not subject to mandatory redemption Symbol(B) Price
$20 par value, authorized
1,375,000 shares --------- --------
5% Series, 375,000 shares outstanding SDOPrA $24.00 $ 7,500 $ 7,500
4.50% Series, 300,000 shares outstanding SDOPrB $21.20 6,000 6,000
4.40% Series, 325,000 shares outstanding SDOPrC $21.00 6,500 6,500
4.60% Series, 373,770 shares outstanding -- $20.25 7,475 7,475
Without par value (C)
$1.70 Series, 1,400,000 shares outstanding -- $25.85(D) 35,000 35,000
$1.82 Series, 640,000 shares outstanding SDOPrH $26.00(D) 16,000 16,000
----------- ----------
Total not subject to mandatory redemption $ 78,475 $ 78,475
=========== ==========
Subject to mandatory redemption
Without par value (C)
$1.7625 Series, 1,000,000 shares
outstanding(E) -- $25.00(D) $ 25,000 $ 25,000
=========== ===========
(A) All series of preferred stock have cumulative preferences as to dividends.
The $20 par value preferred stock has two votes per share, whereas the no
par value preferred stock is nonvoting. The $20 par value preferred stock
has a liquidation value at par. The no par value preferred stock has a
liquidation value of $25 per share.
(B) All listed shares are traded on the American Stock Exchange.
(C) SDG&E is authorized to issue 10,000,000 shares total (both subject to and not
subject to mandatory redemption). Enova is authorized to issue 30,000,000 shares
total, of which no shares were issued and outstanding at December 31, 1997.
(D) The $1.70 and $1.7625 series are not callable until 2003; the $1.82 series
is not callable until November 1998. All other series are currently callable.
(E) The $1.7625 series has a sinking fund requirement to redeem 50,000 shares
per year from 2003 to 2007. The remaining 750,000 shares must be redeemed
in 2008.
See notes to consolidated financial statements.
51
ENOVA CORPORATION
STATEMENTS OF CONSOLIDATED LONG-TERM DEBT
In thousands of dollars
First Call
Balance at December 31 Date 1997 1996
----------------- ---------- ----------
SDG&E
First mortgage bonds
5.5% Series I, due March 1, 1997 4/15/67 $ -- $ 25,000
8.75% Series II, due March 1, 2023(A) 9/1/97 -- 25,000
9.625% Series JJ, due April 15, 2020 4/15/00 54,260 100,000
6.8% Series KK, due June 1, 2015(B) Non-callable 14,400 14,400
8.5% Series LL, due April 1, 2022 4/1/02 43,725 60,000
7.625% Series MM, due June 15, 2002 Non-callable 80,000 80,000
6.1% and 6.4% Series NN, due September 1, 2018
and 2019(A) 9/1/02 118,615 118,615
Various % Series OO, due December 1, 2027(C) (D) 250,000 250,000
5.9% Series PP, due June 1, 2018(A) 6/1/03 70,795 70,795
Variable % Series QQ, due June 1, 2018(A) (E) -- 14,915
5.85% Series RR, due June 1, 2021(B) 6/1/03 60,000 60,000
5.9% Series SS, due September 1, 2018(A) 9/1/03 92,945 92,945
Variable % Series TT, due September 1, 2020(A) (E) 57,650 57,650
Variable % Series UU, due September 1, 2020(A) (E) 16,700 16,700
-------------- ---------- ----------
Total 859,090 986,020
---------- ----------
Unsecured bonds
5.90% Series CPCFA96A, due June 1, 2014(B) Non-callable 129,820 129,820
Variable % Series CV96A, due July 1, 2021(C) (E) 38,900 38,900
Variable % Series CV96B, due December 1, 2021(C) (E) 60,000 60,000
Variable % Series CV97A, due March 1, 2023(C) (E) 25,000 --
-------------- ---------- ----------
Total 253,720 228,720
---------- ----------
Rate reduction bonds (F) 658,000 --
Capitalized leases 95,301 105,315
Other long-term debt 465 528
Unamortized discount on long-term debt (6,178) (2,128)
Current portion of long-term debt (72,575) (33,639)
---------- ----------
Total SDG&E 1,787,823 1,284,816
---------- ----------
Other Subsidiaries
Debt incurred to acquire limited partnerships,
various rates, payable annually through 2008 312,862 219,051
Other long-term debt 5,473 11,734
Current portion of long-term debt (49,125) (36,263)
--------- ---------
Total Other Subsidiaries 269,210 194,522
--------- ---------
Total Enova $2,057,033 $1,479,338
=========== ==========
(A) Issued to secure SDG&E's obligation under a series of loan agreements with the City
of San Diego under which the city loaned the proceeds from the sale of industrial-
development revenue bonds to the company to finance certain qualified facilities.
All series are tax-exempt except QQ and UU.
(B) Issued to secure SDG&E's obligation under a series of loan agreements with the
California Pollution Control Financing Authority under which the Authority loaned
proceeds from the sale of tax-exempt pollution-control revenue bonds to the company
to finance certain qualified facilities.
(C) Issued to secure SDG&E's obligation under a series of loan agreements with the City
of Chula Vista under which the city loaned the proceeds from the sale of tax-exempt
industrial-development revenue bonds to the company to finance certain qualified
facilities.
(D) The first call date for $75 million is December 1, 2002. The remaining $175 million
of the bonds is currently variable rate and is callable at various dates within
one year. Of this, $45 million is subject to a floating-to-fixed rate swap, which
expires December 15, 2002 (Note 8).
(E) Callable at various dates within one year.
52
(F) Issued to facilitate 10-percent rate reduction mandated by California's electric
restruturing law. Issued in December 1997 at an average interest rate of 6.26
percent. Bonds are secured by the revenue streams collected from customers over 10
years and are not secured by utility assets.
See notes to consolidated financial statements.
53
ENOVA CORPORATION
STATEMENTS OF CONSOLIDATED FINANCIAL
INFORMATION BY SEGMENTS OF BUSINESS
In thousands of dollars
At December 31 or for the
years then ended 1997 1996 1995
- ---------------------------------- ----------- ----------- -----------
Operating Revenues (A) $ 2,217,007 $ 1,993,474 $ 1,870,676
=========== =========== ===========
Operating Income
Electric operations $ 257,706 $ 269,038 $ 263,346
Gas operations 59,382 39,724 51,654
Other 27,082 26,201 30,650
----------- ----------- -----------
Total $ 344,170 $ 334,963 $ 345,650
=========== =========== ===========
Depreciation and Decommissioning
Electric operations $ 286,804 $ 279,251 $ 227,616
Gas operations 37,078 35,027 33,225
Other 23,556 18,212 17,398
----------- ----------- -----------
Total $ 347,438 $ 332,490 $ 278,239
=========== =========== ===========
Utility Plant Additions (B)
Electric operations $ 160,689 $ 167,166 $ 171,151
Gas operations 36,495 41,684 49,597
----------- ----------- -----------
Total $ 197,184 $ 208,850 $ 220,748
=========== =========== ===========
Identifiable Assets
Utility plant - net
Electric operations $ 2,487,472 $ 2,625,620 $ 2,737,201
Gas operations 448,612 448,751 441,140
----------- ----------- -----------
Total 2,936,084 3,074,371 3,178,341
----------- ----------- -----------
Inventories
Electric operations 50,354 47,445 53,828
Gas operations 15,036 15,633 14,131
Other 1,684 359 --
----------- ----------- -----------
Total 67,074 63,437 67,959
----------- ----------- -----------
Other identifiable assets
Electric operations 770,885 697,145 802,172
Gas operations 128,525 161,252 148,714
Other (C) 699,191 488,102 434,940
----------- ----------- -----------
Total 1,598,601 1,346,499 1,385,826
----------- ----------- -----------
Other Utility Assets 632,165 164,930 116,498
----------- ----------- -----------
Total Assets $ 5,233,924 $ 4,649,237 $ 4,748,624
=========== =========== ===========
(A) The detail to operating revenues is provided in the Statements of
Consolidated Income. The gas operating revenues shown therein include
$14 million in 1997, $9 million in 1996 and $9 million in 1995, representing
the gross margin on sales to the electric segment. These margins arose from
interdepartmental transfers of $144 million in 1997, $111 million in 1996
and $85 million in 1995, based on transfer pricing approved by the
California Public Utilities Commission in tariff rates.
(B) Excluding allowance for equity funds used during construction.
(C) Includes $378 million in real estate investments.
Utility income taxes and corporate expenses are allocated between electric and gas
operations in accordance with regulatory accounting requirements.
See notes to consolidated financial statements.
54
ENOVA CORPORATION
QUARTERLY FINANCIAL DATA (UNAUDITED)
In thousands except per share amounts
Quarter ended March 31 June 30 September 30 December 31
- ------------------------------------------------------------------------------------------
1997
Operating revenues $ 507,930 $ 501,481 $ 581,058 $ 626,538
Operating expenses 438,535 416,241 485,699 532,362
----------- ---------- ---------- -----------
Operating income 69,395 85,240 95,359 94,176
Other income and (deductions) 6,086 (124) (3,425) 14,267
Net interest charges and
preferred dividends 26,615 28,738 26,868 27,146
----------- ---------- ---------- -----------
Earnings applicable to
common shares $ 48,866 $ 56,378 $ 65,066 $ 81,297
Average common shares outstanding 116,452 113,616 113,616 113,643
Earnings per common share
(basic and diluted)* $ 0.42 $ 0.50 $ 0.57 $ 0.72
1996
Operating revenues $ 465,897 $ 470,967 $ 507,593 $ 549,017
Operating expenses 372,905 396,442 420,307 468,857
----------- ---------- ---------- -----------
Operating income 92,992 74,525 87,286 80,160
Other income 1,168 11 4,373 420
Net interest charges and
preferred dividends 28,108 27,186 28,914 25,800
----------- ---------- ---------- -----------
Earnings applicable to
common shares $ 66,052 $ 47,350 $ 62,745 $ 54,780
Average common shares outstanding 116,570 116,565 116,566 116,587
Earnings per common share
(basic and diluted)* $ 0.57 $ 0.41 $ 0.54 $ 0.47
These amounts are unaudited, but in the opinion of Enova reflect all adjustments necessary
for a fair presentation.
* The sum of quarterly earnings per share does not equal the annual total due to rounding.
Quarterly Common Stock Data (Unaudited)
1997 1996
First Second Third Fourth First Second Third Fourth
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
Market price
High 23 24 3/8 25 1/4 27 1/8 24 3/4 23 1/8 23 23
Low 21 5/8 21 3/8 23 3/8 23 15/16 21 5/8 20 3/8 20 1/2 21 5/8
Dividends
declared $0.39 $0.39 $0.39 $0.39 $0.39 $0.39 $0.39 $0.39
55
ENOVA CORPORATION
Ratings at December 31, 1997 (Unaudited)
Issue Standard & Poor's Moody's
Bonds A+ A1
Commercial paper A-1 P-1
Preferred stock A a2
The presentation of these ratings is not a recommendation to buy, sell or hold these
securities.
56
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors of Enova Corporation:
We have audited the accompanying consolidated balance sheets and the
statements of consolidated capital stock and of consolidated long-
term debt of Enova Corporation and subsidiaries as of December 31,
1997 and 1996, and the related statements of consolidated income,
consolidated changes in capital stock and retained earnings,
consolidated cash flows, and consolidated financial information by
segments of business for each of the three years in the period ended
December 31, 1997. These consolidated 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 generally accepted
auditing standards. 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 Enova
Corporation and subsidiaries as of December 31, 1997 and 1996, and
the results of their operations and their cash flows for each of the
three years in the period ended December 31, 1997, in conformity with
generally accepted accounting principles.
/S/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
San Diego, California
February 23, 1998
57
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ENOVA CORPORATION
NOTE 1: BUSINESS COMBINATION
In October 1996 Enova Corporation and Pacific Enterprises (PE), parent
company of Southern California Gas Company (SoCalGas), announced an
agreement to combine the two companies. As a result of the combination,
(i) each outstanding share of common stock of Enova will be converted
into one share of common stock of the new company, (ii) each outstanding
share of common stock of PE will be converted into 1.5038 shares of
common stock of the new company and (iii) the preferred stock and
preference stock of SDG&E, PE and SoCalGas will remain outstanding.
The combination was unanimously approved by the boards of directors
of both companies and subsequently was approved by the shareholders of
both companies. The combination will be a tax-free transaction and is
expected to be accounted for as a pooling of interests. Enova and PE
have selected Sempra Energy as the name of the new combined company,
with the corporate headquarters to be located in San Diego, California.
Headquarters for SDG&E and SoCalGas, whose names will be retained, will
remain in San Diego and Los Angeles, California, respectively.
Consummation of the combination is conditional upon the approvals of the
California Public Utilities Commission and various other regulatory
bodies, with completion expected in the summer of 1998. On February 23,
1998, the CPUC's administrative law judge handling the proceeding issued
a draft decision that proposed approval of the combination. Among other
things, the draft decision proposed 50/50 sharing of the net cost
savings resulting from the combination between shareholders and
customers, but only for five years rather than the 10 years sought. The
draft decision would reduce the net shareable savings from $1.1
billion to $340 million. The CPUC decision is scheduled for the end of
March 1998. Additional information concerning Enova/PE joint activities
is discussed in Note 3.
NOTE 2: SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations On January 1, 1996, Enova Corporation (referred to
herein as Enova, which includes the parent and its wholly owned
subsidiaries) became the parent of SDG&E and its unregulated
subsidiaries (referred to herein as nonutility subsidiaries). SDG&E's
outstanding common stock was converted on a share-for-share basis into
Enova common stock. SDG&E's debt securities, preferred and preference
stock were unaffected and remain with SDG&E.
The consolidated financial statements include Enova and its wholly
owned subsidiaries. The subsidiaries include SDG&E, Califia, Enova
Financial, Enova Energy, Enova Technologies, Enova International and
Pacific Diversified Capital. In 1997, nonutility subsidiaries
contributed 8 percent to operating income (8 percent in 1996 and 9
percent in 1995).
Utility Plant and Depreciation Utility plant represents the buildings,
equipment and other facilities used by SDG&E to provide electric and gas
service. The cost of utility plant includes labor, materials, contract
services and related items, and an allowance for funds used during
construction. The cost of retired depreciable utility plant, plus
removal costs minus salvage value is charged to accumulated
depreciation. Information regarding industry restructuring and its
effect on utility plant is included in Note 10. Utility plant in service
by major functional categories at December 31, 1997, are: electric
generation $1.8 billion, electric distribution $2.3 billion, electric
transmission $0.7 billion, other electric $0.3 billion and gas
operations $0.8 billion. The corresponding amounts at December 31, 1996,
were essentially the same as 1997. Accumulated depreciation and
decommissioning of electric and gas utility plant in service at December
31, 1997, are $2.6 billion and $0.4 billion, respectively, and at
December 31, 1996, were $2.2 billion and $0.4 billion, respectively.
58
Depreciation expense is based on the straight-line method over the
useful lives of the assets or a shorter period prescribed by the
California Public Utilities Commission (CPUC) (for SONGS, see below).
The provisions for depreciation as a percentage of average depreciable
utility plant (by major functional categories) in 1997 and (in 1996,
1995, respectively) are: electric generation 8.83 (7.57, 4.04), electric
distribution 4.39 (4.38, 4.36), electric transmission 3.28 (3.25, 3.21),
other electric 6.02 (5.95, 5.89) and gas operations 4.03 (4.07, 4.06).
The increases for electric generation in 1997 and 1996 reflect the
accelerated recovery of San Onofre Nuclear Generating Station (SONGS)
Units 2 and 3 approved by the CPUC in April 1996.
Inventories Included in inventories at December 31, 1997, are SDG&E's
$43 million of materials and supplies ($40 million in 1996), and $22
million of fuel oil and natural gas ($23 million in 1996). Materials and
supplies are valued at average cost; fuel oil and natural gas are valued
by the last-in first-out (LIFO) method.
Other Current Assets Included in other current assets at December 31,
1997, is $44 million for Enova's current and deferred income taxes ($47
million in 1996). Included therein is SDG&E's portion of $26 million
($33 million in 1996).
Short-term Borrowings There were no short-term borrowings at December
31, 1997, and 1996. At December 31, 1997, SDG&E had $50 million of bank
lines available to support commercial paper. Commitment fees are paid on
the unused portion of the lines and there are no requirements for
compensating balances.
Other Current Liabilities Included in other current liabilities at
December 31, 1997, is Califia's $21 million current portion of deferred
lease revenue ($33 million in 1996) and $35 million for SDG&E's accrued
vacation and sick leave ($33 million in 1996). In 1996 the $21 million
noncurrent portion of Califia's deferred lease revenue is included in
"Deferred Credits and Other Liabilities." The deferred revenue is
amortized over the lease terms that end in 1998.
Allowance for Funds Used During Construction (AFUDC) The allowance
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, as an offset to interest charges shown in the Statements of
Consolidated Income, although it is not a current source of cash. The
average rate used to compute AFUDC was 9.35 percent in 1997, 9.36
percent in 1996 and 9.74 percent in 1995.
Effects of Regulation SDG&E's accounting policies conform with
generally accepted accounting principles for regulated enterprises and
reflect the policies of the CPUC and the Federal Energy Regulatory
Commission. SDG&E has been preparing 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 may record 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 revenues for amounts due to customers. To
the extent that a portion of SDG&E's operations is no longer subject to
SFAS No. 71, or recovery is no longer probable as a result of changes in
regulation or SDG&E'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 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. As discussed in Note 10, California enacted a law
restructuring the electric utility industry. The law adopts the December
1995 CPUC policy decision, and allows California utilities the
opportunity to recover existing utility plant and regulatory assets over
a transition period that ends in 2001. SDG&E has ceased the application
of SFAS No. 71 with respect to its electric-generation business. SDG&E
continues to evaluate the applicability of SFAS No. 121 as industry
restructuring progresses. Additional information
59
concerning regulatory assets and liabilities is described below in
"Revenues and Regulatory Balancing Accounts" and in Note 10.
Revenues and Regulatory Balancing Accounts Revenues from utility
customers have consisted of deliveries to customers and the changes in
regulatory balancing accounts. Earnings fluctuations from changes in the
costs of fuel oil, purchased energy and natural gas, and consumption
levels for electricity and the majority of natural gas previously were
eliminated by balancing accounts authorized by the CPUC. This is still
the case for natural gas sales. However, as a result of California's
electric-restructuring law, beginning in 1997 overcollections recorded
in the Energy Cost Adjustment Clause (ECAC) and Electric Revenue
Adjustment Mechanism (ERAM) balancing accounts were transferred to the
interim transition cost-balancing account, which is being applied to
transition cost recovery (see Note 10). At December 31, 1997,
overcollections of $130 million were included in this account. Of this
amount, $98 million of overcollections were recorded at December 31,
1996. The elimination of ECAC and ERAM resulted in quarter-to-quarter
earnings volatility in 1997. This earnings volatility will continue in
future years. Additional information on industry restructuring is
included in Note 10.
Deferred Charges and Other Assets Deferred charges include SDG&E's
unrecovered premium on early retirement of debt and other regulatory-
related expenditures that SDG&E expects to recover in future rates,
excluding generation operations (discussed above). These items are
amortized as recovered in rates. The net regulatory assets associated
with SDG&E's generation operations at December 31, 1997, were credited
to the interim transition cost balancing account.
Deferred Credits and Other Liabilities Other liabilities at December
31, 1997, include $117 million of accumulated decommissioning costs
associated with SONGS Unit 1 ($96 million in 1996), which was
permanently shut down in 1992. Additional information on SONGS Unit 1
decommissioning costs is included in Note 5.
Discontinued Operations
Enova's financial statements for periods prior to 1996 reflect the June
1995 sale of Wahlco Environmental Systems, Inc. as discontinued
operations, in accordance with Accounting Principles Board Opinion No.
30, "Reporting the Effects of a Disposal of a Segment of Business."
Discontinued operations are summarized in the table below:
In millions of dollars 1995
- ---------------------------------------------------------------------
Revenues $ 24
Loss from operations before income taxes --
Loss on disposal before income taxes (12)
Income tax benefits 12
The loss on disposal of Wahlco reflects the sale of Wahlco and Wahlco's
1995 net operating losses prior to the sale.
Use of Estimates in the Preparation of Financial Statements The
preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities
and 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 could differ from those
estimates.
Statements of Consolidated Cash Flows Temporary investments are highly
liquid investments with original maturities of three months or less, or
investments that are readily convertible to cash.
Basis of Presentation Certain prior-year amounts have been reclassified
to conform to the current year's format.
60
NOTE 3: SIGNIFICANT ACQUISITIONS AND JOINT VENTURES
Sempra Energy Trading On December 31, 1997, Enova and Pacific
Enterprises completed their acquisition (50% interest each) of Sempra
Energy Trading (formerly AIG Trading Corporation), a leading natural gas
and power marketing firm headquartered in Greenwich, Connecticut, for a
total cost of $225 million.
Sempra Energy Trading's primary business focus is wholesale trading
and marketing of natural gas, power and oil to customers primarily in
North America. Sempra Energy Trading had net assets of $30 million at
December 31, 1997.
An allocation of the purchase price has not yet been completed. The
difference between the cost and underlying equity in the net assets will
be amortized over a period of not more than 15 years.
As of December 31, 1997, Sempra Energy Trading's trading assets and
trading liabilities approximate the following:
In millions of dollars
- ---------------------------------------------------------------------
Trading Assets
Unrealized gains on swaps and forwards $ 497
Due from commodity clearing organization and clearing brokers 41
OTC commodity options purchased 33
Due from trading counterparties 16
- ---------------------------------------------------------------------
Total $ 587
=====================================================================
Trading Liabilities
Unrealized losses on swaps and forwards $ 487
Due to trading counterparties 41
OTC commodity options written 29
- ---------------------------------------------------------------------
Total $ 557
=====================================================================
The notional amounts of Sempra Energy Trading's financial
instruments are provided below and include a maturity profile as of
December 31, 1997, based upon the expected timing of the future cash
flows. The notional amounts do not necessarily represent the amounts
exchanged by parties to the financial instruments and do not measure
Sempra Energy Trading's exposure to credit or market risks. The notional
or contractual amounts are used to summarize the volume of financial
instruments, but do not reflect the extent to which positions may offset
one another. Accordingly, Sempra Energy Trading is exposed to much
smaller amounts potentially subject to risk.
Within One to Five Five to Ten After
In millions of dollars One Year Years Years Ten Years Total
- --------------------------------------------------------------------------------
Forwards and
commodity swaps $3,175 $458 $90 $74 $3,797
Futures 856 189 -- -- 1,045
Options purchased 704 52 -- -- 756
Options written 592 62 -- -- 654
- --------------------------------------------------------------------------------
Total $5,327 $761 $90 $74 $6,252
================================================================================
Enova and Pacific Enterprises have jointly and severally guaranteed
certain trading obligations of Sempra Energy Trading with credit worthy
counterparties in connection with authorized transactions and in
connection with funding. The total obligations guaranteed by the
companies as of December 31, 1997, are $190 million.
Sempra Energy Solutions In January 1998 Sempra Energy Solutions
completed the acquisition of CES/Way International, a leading national
energy-service
61
provider. In September 1997 Sempra Energy Solutions formed a joint
venture with Bangor Hydro to build, own and operate a $40 million
natural gas distribution system in Bangor, Maine. In December 1997,
Sempra Energy Solutions signed a partnership agreement with Frontier
Utilities to build and operate a $55 million natural gas distribution
system in North Carolina.
Enova International Gas Distribution Projects Enova International,
Pacific Enterprises International and Proxima S.A. de C.V., partners in
the Mexican companies Distribuidora de Gas Natural de Mexicali and
Distribuidora de Gas Natural de Chihuahua, are the licensees to build
and operate natural gas distribution systems in Mexicali and Chihuahua.
DGN - Mexicali will invest up to $25 million during the first five years
of the 30-year license period. DGN - Chihuahua plans to invest $50
million in the gas distribution project in Chihuahua over the next five
years.
El Dorado Power Project In December 1997 Enova Power Corporation, a
subsidiary of Enova Energy, and Houston Industries Power Generation
(HIPG) formed a joint venture, El Dorado Energy, to build, own and
operate a 480-megawatt natural gas-fired plant in Boulder City, Nevada.
Total cost of construction is expected to be $280 million, with each
company providing 50 percent of the funding. Enova Power and HIPG each
will be responsible for 50 percent of the plant's fuel procurement and
output marketing. Construction on the plant is expected to begin in the
first quarter of 1998 and be completed in the fourth quarter of 1999.
NOTE 4: LONG-TERM DEBT
Amounts and due dates of long-term debt are shown on the Statements of
Consolidated Long-Term Debt. Excluding capital leases, which are
described in Note 9, maturities of long-term debt for SDG&E are $66
million due in 1998, $65 million due in 1999, 2000 and 2001, and $145
million due in 2002. Total maturities of long-term debt for nonutility
subsidiaries are $49 million for 1998, $53 million for 1999, $44 million
for 2000, $35 million for 2001 and $34 million for 2002. SDG&E has CPUC
authorization to issue an additional $185 million in long-term debt.
First Mortgage Bonds First mortgage bonds are secured by a lien on
substantially all of SDG&E's utility plant. Additional first mortgage
bonds may be issued upon compliance with the provisions of the bond
indenture, which provides for, among other things, the issuance of an
additional $1.3 billion of first mortgage bonds at December 31, 1997.
Certain first mortgage bonds may be called at SDG&E's option.
First mortgage bonds totaling $249 million have variable-interest-
rate provisions. During 1997, SDG&E retired $127 million of first
mortgage bonds, of which $102 million were retired prior to scheduled
maturity.
Unsecured Bonds During 1997, SDG&E issued $25 million of unsecured
bonds. Unsecured bonds totaling $124 million have variable-interest-rate
provisions.
Rate-Reduction Bonds In December 1997, $658 million of rate-reduction
bonds were issued on behalf of SDG&E at an average interest rate of 6.26
percent. These bonds were issued to facilitate the 10-percent rate
reduction mandated by California's electric-restructuring law. These
bonds are being repaid over 10 years by SDG&E's residential and small-
commercial customers via a charge on their electricity bills. These
bonds are secured by the revenue streams collected from customers and
are not secured by, or payable from, utility assets. Additional
information on rate-reduction bonds and electric industry restructuring
is discussed in Note 10.
Other At December 31, 1997, SDG&E had $340 million of bank lines,
providing a committed source of long-term borrowings, with no debt
outstanding. Bank lines, unless renewed by SDG&E, expire in 1998 ($60
million) and in 2000 ($280 million). Commitment fees are paid on the
unused portion of the lines and there are no requirements for
compensating balances.
62
Nonutility loans (Enova Financial and Califia) of $318 million and
$231 million at December 31, 1997, and 1996, respectively, are secured
by real estate and equipment.
SDG&E's interest payments, including those applicable to short-term
borrowings, amounted to $89 million in 1997, $93 million in 1996 and
$100 million in 1995. Nonutility interest payments amounted to $12
million in 1997, $12 million in 1996 and $14 million in 1995.
SDG&E periodically enters into interest-rate swap and cap agreements
to moderate its exposure to interest-rate changes and to lower its
overall cost of borrowings. At December 31, 1997, SDG&E had such an
agreement, maturing in 2002, with underlying debt of $45 million. See
additional information in Note 8.
Although holders of variable-rate bonds may elect to redeem them
prior to scheduled maturity, for purposes of determining the maturities
listed above, it is assumed the bonds will be held to maturity.
NOTE 5: FACILITIES UNDER JOINT OWNERSHIP
SONGS and the Southwest Powerlink transmission line are owned jointly
with other utilities. SDG&E's interests at December 31, 1997, are:
In millions of dollars
- ----------------------------------------------------------------------
Southwest
Project SONGS Powerlink
- ----------------------------------------------------------------------
Percentage ownership 20 89
Utility plant in service $1,143 $ 217
Accumulated depreciation $ 593 $ 96
Construction work in progress $ 9 $ --
SDG&E's share of operating expenses is included in the Statements
of Consolidated Income. Each participant in the projects must provide
its own financing. The amounts specified above for SONGS include nuclear
production, transmission and other facilities.
SONGS Decommissioning Objectives, work scope and procedures for the
future dismantling and decontamination of the SONGS units must meet the
requirements of the Nuclear Regulatory Commission, the Environmental
Protection Agency, the California Public Utilities Code and other
regulatory bodies.
SDG&E's share of decommissioning costs for the SONGS units is
estimated to be $401 million in current dollars and is based on studies
performed and updated periodically by outside consultants. The most
recent study was performed in 1993. A new study is planned for 1998. A
new escalation methodology was utilized to estimate the liability in
1997. This methodology was authorized by the CPUC in its 1996
Performance-Based Ratemaking decision for Southern California Edison
(principal owner of SONGS), and incorporates an internal rate of return
calculation that results in higher escalation amounts. Although electric
industry restructuring legislation requires that stranded costs, which
include SONGS plant costs, be amortized in rates by 2001, the recovery
of decommissioning costs is allowed until the time as the costs are
fully recovered.
The amount accrued each year is based on the amount allowed by
regulators and is currently being collected in rates. This amount is
considered sufficient to cover SDG&E's share of future decommissioning
costs. The depreciation and decommissioning expense reflected on the
Statements of Consolidated Income includes $22 million of
decommissioning expense for each of the years 1997, 1996 and 1995.
The amounts collected in rates are invested in externally managed
trust funds. In accordance with SFAS No. 115, "Accounting for Certain
Investments in Debt and Equity Securities," the securities held by the
trust are considered available for sale and are adjusted to market value
($399 million at December 31, 1997, and $328 million at December 31,
1996) and shown on the Consolidated Balance Sheets. The fair values
reflect unrealized gains of $89 million and $50 million at December 31,
1997, and 1996, respectively. The corresponding accumulated accrual is
included on the Consolidated Balance Sheets in
63
"Accumulated Depreciation and Decommissioning" for SONGS Units 2 and 3
and in "Deferred Credits and Other Liabilities" for Unit 1. SONGS Unit 1
was permanently shut down in 1992.
The Financial Accounting Standards Board is reviewing the
accounting for liabilities related to closure and removal of long-lived
assets, such as nuclear power plants, including the recognition,
measurement and classification of such costs. The Board could require,
among other things, that SDG&E's future balance sheets include a
liability for the estimated decommissioning costs, and a related
increase in the cost of utility plant.
Additional information regarding SONGS is included in Notes 9 and
10.
NOTE 6: EMPLOYEE BENEFIT PLANS
Pension Plan SDG&E has a defined-benefit pension plan, which covers
substantially all of its employees. Benefits are related to the
employees' compensation. Plan assets consist primarily of common stocks
and bonds. SDG&E funds the plan based on the projected unit credit
actuarial cost method. Net pension cost consisted of the following for
the years ended December 31:
In thousands of dollars 1997 1996 1995
- ----------------------------------------------------------------------
Cost related to current service $16,756 $18,547 $14,598
Interest on projected benefit obligation 39,089 37,253 30,760
Return on plan assets (119,554) (72,829) (132,674)
Net amortization and deferral 63,500 25,315 93,708
- ----------------------------------------------------------------------
Cost pursuant to general
accounting standards (209) 8,286 6,392
Regulatory adjustment -- (15,286) 608
- ----------------------------------------------------------------------
Net cost (benefit) $ (209) $(7,000) $7,000
======================================================================
The plan's status was as follows at December 31:
In thousands of dollars 1997 1996
- ----------------------------------------------------------------------
Accumulated benefit obligation
Vested $495,278 $435,029
Non-vested 11,637 12,321
- ----------------------------------------------------------------------
Total $506,915 $447,350
======================================================================
Plan assets at fair value $699,000 $598,610
Projected benefit obligation 589,911 539,391
- ----------------------------------------------------------------------
Plan assets less projected
benefit obligation 109,089 59,219
Unrecognized effect of accounting change (761) (950)
Unrecognized prior service cost 28,444 31,315
Unrecognized actuarial gains (204,061) (157,082)
- ----------------------------------------------------------------------
Net liability $(67,289) $(67,498)
======================================================================
The projected benefit obligation assumes a 7.25 percent actuarial
discount rate in 1997 (7.50 percent in 1996) and a 5.0 percent average
annual compensation increase. The expected long-term rate of return on
plan assets is 8.5 percent. The increase in the total accumulated
benefit obligation and projected benefit obligation at December 31,
1997, is due primarily to a decrease in the actuarial discount rate.
SDG&E's annual cost for a supplemental retirement plan for a limited
number of key employees was approximately $3 million in 1997, 1996 and
1995.
64
Post-Retirement Health Benefits SDG&E provides certain health and life
insurance benefits to retired employees. These benefits are accrued
during the employee's years of service, up to the year of benefit
eligibility. SDG&E is recovering the cost of these benefits based upon
actuarial calculations and funding limitations. The costs for the
benefits were $4 million in 1997, $5 million in 1996 and $5 million in
1995. These costs include $2 million of amortization per year for the
unamortized transition obligation (arising from the initial
implementation of this accounting policy) of approximately $31 million,
which is being amortized through 2012.
Savings Plan Essentially all employees are eligible to participate in
SDG&E's savings plan. Eligible employees may make a contribution of 1
percent to 15 percent of their base pay to the savings plan for
investment in mutual funds or in Enova common stock. SDG&E contributes
amounts equal to up to 3 percent of participants' compensation for
investment in Enova common stock. SDG&E's annual compensation expense
for this plan was $3 million in 1997, $2 million in 1996 and $2 million
in 1995.
Stock-Based Compensation Enova has a long-term incentive stock
compensation plan that provides for aggregate awards of up to 2,700,000
shares of Enova common stock. The plan terminates in April 2005. In each
of the last 10 years, 49,000 shares to 75,000 shares of stock were
issued to officers and key employees, subject to forfeiture over four
years if certain corporate goals are not met. The long-term incentive
stock compensation plan also provides for the granting of stock options.
In October 1997, Enova rescinded all options granted in October 1996.
There were no stock options outstanding at December 31, 1997. As
permitted by SFAS No. 123, "Accounting for Stock-Based Compensation,"
SDG&E has adopted the disclosure-only requirements of SFAS No. 123 and
continues to account for stock-based compensation by applying the
provisions of Accounting Principles Board Opinion No. 25, "Accounting
for Stock Issued to Employees." The differences between compensation
cost included in net income and the related cost measured by the fair-
value-based method defined in SFAS No. 123 are immaterial. SDG&E's
compensation expense for this plan was approximately $1 million in 1997,
$1 million in 1996 and $2 million in 1995.
65
NOTE 7: INCOME TAXES
Income tax payments totaled $162 million in 1997, $176 million in 1996
and $148 million in 1995.
The components of accumulated deferred income taxes at December 31
are as follows:
In thousands of dollars 1997 1996
- ----------------------------------------------------------------------
Deferred tax liabilities
Differences in financial and tax
bases of utility plant $567,804 $628,617
Loss on reacquired debt 30,535 26,399
Other 91,708 80,033
- ----------------------------------------------------------------------
Total deferred tax liabilities 690,047 735,049
- ----------------------------------------------------------------------
Deferred tax assets
Unamortized investment tax credits 62,144 66,729
Equipment leasing activities 8,494 22,333
Regulatory balancing accounts 27,903 37,010
Unbilled revenue 22,365 21,923
Other 89,856 123,158
- ---------------------------------------------------------------------
Total deferred tax assets 210,762 271,153
- ---------------------------------------------------------------------
Net deferred income tax liability 479,285 463,896
Current portion (net asset) 21,745 33,504
- ---------------------------------------------------------------------
Non-current portion (net liability) $501,030 $497,400
=====================================================================
The components of income tax expense are as follows:
In thousands of dollars 1997 1996 1995
- ---------------------------------------------------------------------
Current
Federal $93,040 $115,410 $134,212
State 38,413 39,939 42,630
- ---------------------------------------------------------------------
Total current taxes 131,453 155,349 176,842
- ---------------------------------------------------------------------
Deferred
Federal 23,222 434 (23,914)
State 1,600 (1,518) (13,464)
- ---------------------------------------------------------------------
Total deferred taxes 24,822 (1,084) (37,378)
- ---------------------------------------------------------------------
Deferred investment
tax credits - net (6,073) (5,791) (4,859)
- ---------------------------------------------------------------------
Total income tax expense $150,202 $148,474 $134,605
=====================================================================
Federal and state income taxes are allocated between operating
income and other income.
66
The reconciliation of the statutory federal income tax rate to the
effective income tax rate is as follows:
1997 1996 1995
- ---------------------------------------------------------------------
Statutory federal income tax rate 35.0 % 35.0 % 35.0 %
Depreciation 8.1 6.3 5.5
State income taxes - net of
federal income tax benefit 7.0 6.9 5.5
Tax credits (10.8) (9.5) (7.6)
Equipment leasing activities (2.3) (2.8) (2.8)
Repair allowance (1.9) (1.2) (3.0)
Other - net 2.3 4.4 4.8
- ---------------------------------------------------------------------
Effective income tax rate 37.4 % 39.1 % 37.4 %
=====================================================================
NOTE 8: FINANCIAL INSTRUMENTS
Fair Value The fair values of financial instruments (cash, temporary
investments, funds held in trust, notes receivable, investments in
limited partnerships, dividends payable, short- and long-term debt,
deposits from customers, and preferred stock subject to mandatory
redemption) are not materially different from the carrying amounts,
except for long-term debt. The carrying amounts and fair value of long-
term debt are $2.1 billion and $2.2 billion, respectively, at December
31, 1997, and $1.5 billion and $1.5 billion, respectively, at December
31, 1996. The fair values of SDG&E's first mortgage bonds are estimated
based on quoted market prices for them or for similar issues. The fair
values of long-term notes payable are based on the present values of the
future cash flows, discounted at rates available for similar notes with
comparable maturities. The fair values of the rate-reduction bonds
issued in December 1997 are estimated to approximate carrying value due
to the relatively short period of time between the issuance date and the
valuation date, and the relative market stability during those periods.
Off-Balance-Sheet Financial Instruments Enova's policy is to use
derivative financial instruments to reduce its exposure to fluctuations
in interest rates, foreign-currency exchange rates and natural gas
prices. These financial instruments expose Enova to market and credit
risks which may at times be concentrated with certain counterparties,
although counterparty nonperformance is not anticipated.
Interest-Rate-Swap Agreements SDG&E periodically enters into interest-
rate-swap agreements to moderate its exposure to interest-rate changes
and to lower its overall cost of borrowing. These swap agreements
generally remain off the balance sheet as they involve the exchange of
fixed- and variable-rate interest payments without the exchange of the
underlying principal amounts. The related gains or losses are reflected
in the income statement as part of interest expense. At December 31,
1997, SDG&E had one interest-rate-swap agreement: a floating-to-fixed-
rate swap associated with $45 million of variable-rate bonds maturing in
2002. SDG&E expects to hold this derivative financial instrument to its
maturity. This swap agreement has effectively fixed the interest rate on
the underlying variable-rate debt at 5.4 percent. SDG&E would be exposed
to interest-rate fluctuations on the underlying debt should the
counterparty to the agreement not perform. Such nonperformance is not
anticipated. This agreement, if terminated, would result in an
obligation of $2 million at December 31, 1997, and at December 31, 1996.
Foreign-Currency Forward Exchange Contracts SDG&E's pension fund
periodically uses foreign-currency forward contracts to reduce its
exposure to exchange-rate fluctuations associated with certain
investments in foreign equity securities. These contracts generally have
maturities ranging from three to six months. At December 31, 1997, there
were no foreign-currency forward contracts outstanding.
67
Energy Derivatives SDG&E uses energy derivatives for both hedging and
trading purposes within certain limitations imposed by company policies.
These derivative financial instruments include forward contracts, swaps,
options and other contracts which have maturities ranging from 30 days
to nine months. SDG&E's accounting policy is to adjust the book value of
these derivatives to market each month with gains and losses recognized
in earnings. These instruments are included in other current assets on
the Consolidated Balance Sheet. Certain instruments such as swaps are
entered into and closed out within the same month and, therefore, do not
have any balance-sheet impact. Gains and losses are included in electric
or gas revenue or expense, whichever is appropriate, on the Consolidated
Income Statement.
As of December 31, 1997, the net fair value of open positions was
$5.9 million. The net unrealized profit of these open positions was $0.3
million. These positions hedge approximately 6 percent of SDG&E's annual
total purchased-gas volumes. The average fair value of derivative
financial instruments during 1997 was an obligation of $0.2 million. The
net gains arising from these activities during 1997 were $2.5 million.
Information on derivative financial instruments of Sempra Energy Trading
is provided in Note 3.
Market and Credit Risk SDG&E and Sempra Energy Trading utilize a
variety of financial structures, products and terms which require the
company to manage, on a portfolio basis, the resulting market risks
inherent in these transactions, subject to parameters established by
company policies. Market risks are monitored separately from the groups
that create or actively manage these risk exposures to ensure compliance
with the company's stated risk management policies.
Credit risk relates to the risk of loss that would incur as a result
of nonperformance by counterparties pursuant to the terms of their
contractual obligations. SDG&E and Sempra Energy Trading avoid
concentration of counterparties and maintain credit policies with regard
to counterparties that management believes significantly minimize
overall credit risk.
A Risk Management Committee, composed of Enova and Pacific
Enterprises officers, is responsible for monitoring operating
performance and compliance with established risk management policies for
Sempra Energy Solutions and its subsidiaries.
NOTE 9: CONTINGENCIES AND COMMITMENTS
Purchased-Power Contracts SDG&E buys electric power under several
short-term and long-term contracts. Purchases are for up to 7 percent of
plant capacity under contracts with other utilities and up to 100
percent of plant capacity under contracts with nonutility suppliers. No
one supplier provides more than 3 percent of SDG&E's total system
requirements. The contracts expire on various dates between 1998 and
2025.
At December 31, 1997, the estimated future minimum payments under
the contracts were:
In millions of dollars
- ---------------------------------------------------------------------
1998 $234
1999 232
2000 200
2001 183
2002 134
Thereafter 2,462
- ---------------------------------------------------------------------
Total minimum payments $3,445
=====================================================================
These payments represent capacity charges and minimum energy
purchases. SDG&E is required to pay additional amounts for actual
purchases of energy that exceed the minimum energy commitments. Total
payments, including energy payments, under the contracts were $421
million in 1997, $296 million in 1996
68
and $329 million in 1995. Payments under purchased-power contracts
increased in 1997 due to increased sales volume and lower nuclear
generation availability.
In November 1997, SDG&E announced a plan to auction its power plants
and other electric-generating resources, which include its long-term
purchased-power contracts. Additional information on SDG&E's plan to
divest its electric-generating assets is discussed in Note 10.
Natural Gas Contracts SDG&E has a contract with Southern California Gas
Company (SoCalGas) that provides SDG&E with intrastate transportation
capacity on SoCalGas' pipelines. This contract is currently being
renegotiated and continues on a month-to-month basis under the original
terms until a new agreement is reached. The commitment presumes a
contract renewal for one year. SDG&E's long-term contracts with
interstate pipelines for transportation capacity expire on various dates
between 2007 and 2023. SDG&E's contract with SoCalGas for 8 billion
cubic feet of natural gas storage capacity expires in March 1998. A new
agreement has been reached for 6 billion cubic feet of natural gas
storage capacity from April 1998 through March 1999. SDG&E has long-term
natural gas supply contracts (included in the table below) with four
Canadian suppliers that expire between 2001 and 2004. SDG&E has been
involved in negotiations and litigation with the suppliers concerning
the contracts' terms and prices. SDG&E has settled with one supplier,
with gas being delivered under the terms of the settlement agreement.
The remaining suppliers have ceased deliveries pending legal resolution.
A U.S. Court of Appeals has upheld a U.S. District Court's invalidation
of the contracts with two of these suppliers, although the value of the
gas delivered has not yet been determined by the court.
At December 31, 1997, the future minimum payments under natural gas
contracts were:
Transportation Natural
In millions of dollars and Storage Gas
- ----------------------------------------------------------------------
1998 $65 $19
1999 15 17
2000 14 19
2001 14 21
2002 14 24
Thereafter 234 25
- ----------------------------------------------------------------------
Total minimum payments $356 $125
======================================================================
Total payments under the contracts were $125 million in 1997, $100
million in 1996 and $95 million in 1995.
69
Leases SDG&E has nuclear fuel, office buildings, a generating facility
and other properties that are financed by long-term capital leases.
Utility plant includes $198 million at December 31, 1997, and $200
million at December 31, 1996, related to these leases. The associated
accumulated amortization is $102 million and $95 million, respectively.
SDG&E and nonutility subsidiaries also lease office facilities, computer
equipment and vehicles under operating leases. Certain leases on office
facilities contain escalation clauses requiring annual increases in rent
ranging from 2 percent to 7 percent.
The minimum rental commitments payable in future years under all
noncancellable leases are:
Operating Capitalized
Leases Leases
In millions of dollars Enova SDG&E SDG&E
- ---------------------------------------------------------------------
1998 $35 $13 $26
1999 12 12 26
2000 12 12 20
2001 8 8 12
2002 8 8 12
Thereafter 36 36 20
- ---------------------------------------------------------------------
Total future rental commitment $111 $89 116
- ---------------------------------------------------------------------
Imputed interest (6% to 9%) (21)
- ---------------------------------------------------------------------
Net commitment $95
=====================================================================
Enova's rental payments totaled $81 million in 1997, $88 million in
1996 and $85 million in 1995. Included in these amounts are SDG&E
payments of $43 million, $46 million and $44 million, respectively.
Environmental Issues SDG&E's operations are conducted in accordance
with federal, state and local environmental laws and regulations
governing hazardous wastes, air and water quality, land use, and solid-
waste disposal. SDG&E incurs significant costs to operate its facilities
in compliance with these laws and regulations. The costs of compliance
with environmental laws and regulations have been recovered in customer
rates. Capital expenditures to comply with environmental laws and
regulations were $4 million in 1997, $6 million in 1996 and $4 million
in 1995, and are expected to be $38 million over the next five years.
These expenditures primarily include the estimated cost of retrofitting
SDG&E's power plants to reduce air emissions.
SDG&E has been associated with various sites which may require
remediation under federal, state or local environmental laws. SDG&E is
unable to determine 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. Environmental liabilities that may
arise from these assessments are recorded when remedial efforts are
probable, and the costs can be estimated. In 1994 the CPUC approved the
Hazardous Waste Collaborative Memorandum account allowing utilities to
recover their hazardous waste costs, including those related to
Superfund sites or similar sites requiring cleanup. The decision allows
recovery of 90 percent of cleanup costs and related third-party
litigation costs and 70 percent of the related insurance-litigation
expenses. As discussed in Note 10, restructuring of the California
electric-utility industry will change the way utility rates are set and
costs are recovered. Both the CPUC and state legislation have indicated
that the California utilities will be allowed an opportunity to recover
existing utility plant and regulatory assets over a transition period
that ends in 2001. SDG&E has asked the CPUC that beginning on January 1,
1998, the collaborative account be modified, and that electric-
generation-related cleanup costs be eligible for transition cost
recovery. A CPUC decision is still pending. Depending on the final
outcome of industry restructuring and the impact of competition, the
70
costs of compliance with environmental regulations may not be fully
recoverable.
Nuclear Insurance SDG&E and the co-owners of SONGS have purchased
primary insurance of $200 million, the maximum amount available, for
public-liability claims. An additional $8.7 billion of coverage is
provided by secondary financial protection required by the Nuclear
Regulatory Commission and provides for loss sharing among utilities
owning nuclear reactors if a costly accident occurs. SDG&E could be
assessed retrospective premium adjustments of up to $32 million in the
event of a nuclear incident involving any of the licensed, commercial
reactors in the United States, if the amount of the loss exceeds $200
million. In the event the public-liability limit stated above is
insufficient, the Price-Anderson Act provides for Congress to enact
further revenue-raising measures to pay claims, which could include an
additional assessment on all licensed reactor operators.
Insurance coverage is provided for up to $2.8 billion of property
damage and decontamination liability. Coverage is also provided for the
cost of replacement power, which includes indemnity payments for up to
three years, after a waiting period of 17 weeks. Coverage is provided
primarily through mutual insurance companies owned by utilities with
nuclear facilities. If losses at any of the nuclear facilities covered
by the risk-sharing arrangements were to exceed the accumulated funds
available from these insurance programs, SDG&E could be assessed
retrospective premium adjustments of up to $6 million.
Department of Energy Decommissioning The Energy Policy Act of 1992
established a fund for the decontamination and decommissioning of the
Department of Energy nuclear-fuel-enrichment facilities. Utilities using
the DOE services are contributing a total of $2.3 billion, subject to
adjustment for inflation, over a 15-year period ending in 2006. Each
utility's share is based on its share of enrichment services purchased
from the DOE. SDG&E's annual contribution is $1 million, and will be
recovered as part of decommissioning costs (see Note 10).
Litigation Enova and its subsidiaries, including SDG&E, are involved in
various legal matters, including those arising out of the ordinary
course of business. Management believes that these matters will not have
a material adverse effect on Enova's results of operations, financial
condition or liquidity.
Distribution System Conversion Under a CPUC-mandated program and
through franchise agreements with various cities, SDG&E is committed, in
varying amounts, to convert overhead distribution facilities to
underground. As of December 31, 1997, the aggregate unexpended amount of
this commitment was approximately $100 million. Capital expenditures for
underground conversions were $17 million in 1997, $15 million in 1996
and $12 million in 1995.
Concentration of Credit Risk SDG&E grants credit to its utility
customers, substantially all of whom are located in its service
territory, which covers all of San Diego County and an adjacent portion
of Orange County.
NOTE 10: INDUSTRY RESTRUCTURING
In September 1996, the state of California enacted a law restructuring
California's electric-utility industry (AB 1890). The legislation adopts
the December 1995 CPUC policy decision restructuring the industry to
stimulate competition and reduce rates. The new law supersedes the CPUC
policy decision when in conflict.
Beginning on March 31, 1998, customers will be able to buy their
electricity through a power exchange that will obtain power from
qualifying facilities, nuclear units and, lastly, from the lowest-
bidding suppliers. The power exchange will serve as a wholesale power
pool allowing all energy producers to participate competitively. An
Independent System Operator will schedule power transactions and access
to the transmission system. Consumers also may choose either to continue
to purchase from their local utility under
71
regulated tariffs or to enter into private contracts with generators,
brokers or others. The local utility will continue to provide
distribution service regardless of which source the consumer chooses.
Utilities are allowed a reasonable opportunity to recover their
stranded costs through December 31, 2001. Stranded costs, such as those
related to reasonable employee-related costs directly caused by
restructuring and purchased-power contracts (including those with
qualifying facilities), may be recovered beyond December 31, 2001.
Outside of those exceptions, stranded costs not recovered through 2001
will not be collected from customers. Such costs, if any, would be
written off as a charge against earnings.
SDG&E's transition cost application filed in October 1996 identifies
costs totaling $2 billion (net present value in 1998 dollars). These
identified transition costs were determined to be reasonable by
independent auditors selected by the CPUC, with $73 million requiring
further action before being deemed recoverable transition costs. Of this
amount, the CPUC has excluded from transition cost recovery $39 million
in fixed costs relating to gas transportation to power plants, which
SDG&E believes will be recovered through contracts with the ISO. Total
transition costs include sunk costs, as well as ongoing costs the CPUC
finds reasonable and necessary to maintain generation facilities through
December 31, 2001. Both the CPUC policy decision and AB 1890 provide
that above-market costs for existing purchased-power contracts may be
recovered over the terms of the contracts or sooner. Qualifying
facilities purchases include approximately 100 existing contracts, which
extend as far as 2025. Other power purchases consist of two long-term
contracts expiring in 2001 and 2013. Transition costs also include other
items SDG&E has accrued under cost-of-service regulation. Nuclear
decommissioning costs are nonbypassable until fully recovered, but are
not included as part of transition costs.
Through December 31, 1997, SDG&E has recovered transition costs of
$0.2 billion for nuclear generation and $0.1 billion for nonnuclear
generation. Additionally, overcollections of $0.1 billion recorded in
the ECAC and ERAM balancing accounts as of December 31, 1997, have been
applied to transition cost recovery, leaving approximately $1.6 billion
for future recovery. Included therein is $0.4 billion for post-2001
purchased-power-contract payments that may be recovered after 2001,
subject to an annual reasonableness review. SDG&E has announced a plan
to auction its power plants and other electric-generating assets. This
plan includes the divestiture of SDG&E's fossil power plants and
combustion turbines, its 20-percent interest in SONGS and its portfolio
of long-term purchased-power contracts. The power plants, including the
interest in SONGS, have a net book value as of December 31, 1997, of
$800 million ($200 million for fossil and $600 million for SONGS). The
proceeds from the auction will be applied directly to SDG&E's transition
costs. In December 1997, SDG&E filed with the CPUC for its approval of
the auction plan. The sale of the nonnuclear-generating assets is
expected to be completed by the end of the first quarter of 1999. During
the 1998-2001 period, recovery of transition costs is limited by the
rate freeze (discussed below). Management believes that the rates within
the rate cap and the proceeds from the sale of electric-generating
assets will be sufficient to recover all of SDG&E's approved transition
costs by December 31, 2001.
The California legislation provides for a 10-percent reduction of
residential and small commercial customers' rates, which began in
January 1998, as a result of the utilities' receiving the proceeds of
rate-reduction bonds issued by an agency of the state of California. In
December 1997, $658 million of rate-reduction bonds were issued on
behalf of SDG&E at an average interest rate of 6.26 percent. These bonds
are being repaid over 10 years by SDG&E's residential and small-
commercial customers via a nonbypassable charge on their electric bills.
In addition, the California legislation includes a rate freeze for
all customers. Until the earlier of March 31, 2002, or when transition
cost recovery is complete, SDG&E's system-average rate will be frozen at
June 1996 levels (9.64 cents per kwh), except for the impact of fuel
cost changes and the 10-percent rate reduction described above.
Beginning in 1998 system-average rates cannot be increased above 9.43
cents per kwh, which includes the mandatory rate reduction and any
impact of fuel cost changes.
72
As discussed in Note 2, SDG&E has been accounting for the economic
effects of regulation in accordance with SFAS No. 71. The SEC indicated
a concern that the California investor-owned utilities may not meet the
criteria of SFAS No. 71 with respect to their electric-generation net
regulatory assets. SDG&E has ceased the application of SFAS No. 71 to
its generation business, in accordance with the conclusion by the
Emerging Issues Task Force of the Financial Accounting Standards Board
that the application of SFAS 71 should be discontinued when deregulatory
legislation is issued that determines that a portion of an entity's
business will no longer be regulated. The discontinuance of SFAS No. 71
applied to the utilities' generation business did not result in a write-
off of their net regulatory assets, since the CPUC has approved the
recovery of these assets by the distribution portion of their business,
subject to the rate cap.
73
Item 8. Financial Statements and Supplementary Data - San Diego Gas & Electric
Company
SAN DIEGO GAS & ELECTRIC COMPANY
STATEMENTS OF CONSOLIDATED INCOME
In thousands except per share amounts
For the years ended December 31 1997 1996 1995
------------ ------------ ------------
Operating Revenues
Electric $1,769,421 $1,590,882 $1,503,926
Gas 398,127 348,035 310,142
------------ ------------ ------------
Total operating revenues 2,167,548 1,938,917 1,814,068
------------ ------------ ------------
Operating Expenses
Electric fuel 163,765 134,350 100,256
Purchased power 441,400 310,731 341,727
Gas purchased for resale 183,078 152,151 113,355
Maintenance 87,597 57,652 91,740
Depreciation and decommissioning 323,882 314,278 260,841
Property and other taxes 43,261 44,764 45,566
General and administrative 212,634 247,653 207,078
Other 177,760 166,391 166,303
Income taxes 217,083 202,185 172,202
------------ ------------ ------------
Total operating expenses 1,850,460 1,630,155 1,499,068
------------ ------------ ------------
Operating Income 317,088 308,762 315,000
------------ ------------ ------------
Other Income and (Deductions)
Allowance for equity funds used
during construction 5,192 5,898 6,435
Taxes on nonoperating income (2,073) 4,227 (827)
Other - net 4,243 (5,431) 923
------------ ------------ ------------
Total other income and (deductions) 7,362 4,694 6,531
------------ ------------ ------------
Income Before Interest Charges 324,450 313,456 321,531
------------ ------------ ------------
Interest Charges
Long-term debt 69,545 76,463 82,591
Short-term debt and other 13,825 12,635 17,886
Amortization of debt discount and
expense, less premium 5,154 4,881 4,870
Allowance for borrowed funds
used during construction (2,306) (3,288) (2,865)
------------ ------------ ------------
Net interest charges 86,218 90,691 102,482
------------ ------------ ------------
Income From Continuing Operations 238,232 222,765 219,049
Discontinued Operations, Net of
Income Taxes -- -- 14,408
------------ ------------ ------------
Net Income (before preferred
dividend requirements) 238,232 222,765 233,457
Preferred Dividend Requirements 6,582 6,582 7,663
------------ ------------ ------------
Earnings Applicable to Common Shares $ 231,650 $ 216,183 $ 225,794
============ ============ ============
See notes to consolidated financial statements.
74
SAN DIEGO GAS & ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
In thousands of dollars
Balance at December 31 1997 1996
-------------- --------------
ASSETS
Utility plant - at original cost $5,888,539 $5,704,464
Accumulated depreciation and decommissioning (2,952,455) (2,630,093)
-------------- -------------
Utility plant - net 2,936,084 3,074,371
-------------- -------------
Nuclear decommissioning trust 399,143 328,042
-------------- -------------
Current assets
Cash and temporary investments 536,050 81,409
Accounts receivable 229,148 187,986
Due from affiliates 125,417 --
Inventories 65,390 63,078
Other 51,840 33,227
-------------- -------------
Total current assets 1,007,845 365,700
-------------- -------------
Deferred taxes recoverable in rates 184,837 189,193
-------------- -------------
Deferred charges and other assets 126,584 203,210
-------------- -------------
Total $4,654,493 $4,160,516
============== =============
CAPITALIZATION AND LIABILITIES
Capitalization
Common equity $1,387,363 $1,404,136
Preferred stock not subject to mandatory redemption 78,475 78,475
Preferred stock subject to mandatory redemption 25,000 25,000
Long-term debt 1,787,823 1,284,816
-------------- -------------
Total capitalization 3,278,661 2,792,427
-------------- -------------
Current liabilities
Current portion of long-term debt 72,575 33,639
Accounts payable 161,039 174,884
Due to affiliates -- 7,214
Dividends payable 45,968 47,131
Interest accrued 10,468 12,824
Regulatory balancing accounts overcollected-net 58,063 35,338
Other 114,388 110,743
-------------- -------------
Total current liabilities 462,501 421,773
-------------- -------------
Customer advances for construction 37,661 34,666
Accumulated deferred income taxes - net 471,890 487,119
Accumulated deferred investment tax credits 62,332 64,410
Deferred credits and other liabilities 341,448 360,121
Contingencies and commitments (Notes 9 and 10) -- --
-------------- -------------
Total $4,654,493 $4,160,516
============== =============
See notes to consolidated financial statements.
75
SAN DIEGO GAS & ELECTRIC COMPANY
STATEMENTS OF CONSOLIDATED CASH FLOWS
In thousands of dollars
For the years ended December 31 1997 1996 1995
------------ ------------ ------------
Cash Flows from Operating Activities
Income from continuing operations $ 238,232 $ 222,765 $ 219,049
Adjustments to reconcile income from continuing
operations to net cash provided by operating activities
Depreciation and decommissioning 323,882 314,278 260,841
Amortization of deferred charges and other assets 6,247 5,926 12,068
Amortization of deferred credits and other
liabilities (4,238) (3,901) (1,169)
Allowance for equity funds used during construction (5,192) (5,898) (6,435)
Deferred income taxes and investment tax credits 10,713 (16,369) (42,046)
Other - net 19,416 25,570 21,108
Changes in working capital components
Accounts and notes receivable (41,162) 19,573 9,159
Inventories (2,312) 4,881 7,648
Other current assets (4,464) (14,119) (5,550)
Interest and taxes accrued (40,169) (24,897) 15,737
Accounts payable and other current liabilities (142,831) 50,235 25,288
Regulatory balancing accounts 22,725 (37,313) 59,030
Cash flows provided(used) by discontinued operations -- (11,544) 49,188
----------- ------------- ------------
Net cash provided by operating activities 380,847 529,187 623,916
----------- ------------- ------------
Cash Flows from Financing Activities
Dividends paid (256,168) (188,700) (188,288)
Issuances of long-term debt 677,850 226,646 123,734
Repayment of long-term debt (133,267) (257,772) (126,164)
Short-term borrowings-net -- -- (58,325)
Repurchase of common stock -- -- (241)
Redemption of preferred stock -- (15,155) (18)
------------ ------------ ------------
Net cash provided (used) by financing activities 288,415 (234,981) (249,302)
------------ ------------ ------------
Cash Flows from Investing Activities
Utility construction expenditures (197,184) (208,850) (220,748)
Contributions to decommissioning funds (22,038) (22,038) (22,038)
Other - net 4,601 (2,664) (2,456)
Discontinued operations -- -- (120,222)
------------ ------------ ------------
Net cash used by investing activities (214,621) (233,552) (365,464)
------------ ------------ ------------
Net increase 454,641 60,654 9,150
Cash and temporary investments, beginning of year 81,409 20,755 11,605
------------ ------------ ------------
Cash and temporary investments, end of year $ 536,050 $ 81,409 $ 20,755
============ ============ ============
Supplemental Disclosure of Cash Flow Information
Interest payments, net of amounts capitalized $ 88,574 $ 93,652 $ 104,373
============ ============ ============
Net assets of affiliates transferred to parent $ -- $ 150,095 $ --
============ ============ ============
See notes to consolidated financial statements.
76
SAN DIEGO GAS & ELECTRIC COMPANY
STATEMENTS OF CONSOLIDATED CHANGES IN
CAPITAL STOCK AND RETAINED EARNINGS
In thousands of dollars
For the years ended December 31, 1995, 1996, 1997
Preferred Stock
-----------------------------
Not Subject Subject to Premium on
to Mandatory Mandatory Common Capital Retained
Redemption Redemption Stock Stock Earnings
--------- --------- --------- --------- --------
Balance, January 1, 1995 $ 93,493 $ 25,000 $ 291,341 $ 564,508 $ 618,581
Earnings applicable to common shares 225,794
Long-term incentive plan activity-net 117 1,530
Preferred stock retired (880 shares) (18) 8
Common stock dividends declared (181,809)
- ---------------------------- --------- --------- --------- --------- ---------
Balance, December 31, 1995 93,475 25,000 291,458 566,046 662,566
Earnings applicable to common shares 216,183
Transfer to Enova Corporation 342 (150,437)
Preferred stock retired
(150,000 shares) (15,000) (155)
Common stock dividends declared (181,867)
- ---------------------------- --------- --------- --------- --------- ---------
Balance, December 31, 1996 78,475 25,000 291,458 566,233 546,445
Earnings applicable to common shares 231,650
Special dividend to Enova Corporation ( 70,000)
Common stock dividends declared (178,423)
- ---------------------------- --------- --------- --------- --------- ---------
Balance, December 31, 1997 $ 78,475 $ 25,000 $ 291,458 $ 566,233 $ 529,672
============================ ========= ========= ========= ========= =========
See notes to consolidated financial statements.
77
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors of San Diego Gas &
Electric Company:
We have audited the accompanying consolidated balance sheets of San
Diego Gas & Electric Company and subsidiary as of December 31, 1997
and 1996, and the related statements of consolidated income,
consolidated changes in capital stock and retained earnings, and
consolidated cash flows for each of the three years in the period
ended December 31, 1997. 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 generally accepted
auditing standards. 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 San Diego
Gas & Electric Company and subsidiary of December 31, 1997 and 1996,
and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 1997 in conformity
with generally accepted accounting principles.
/S/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
San Diego, California
February 23, 1998
78
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SAN DIEGO GAS & ELECTRIC COMPANY
Except as modified below, the Notes to Consolidated Financial Statements
of Enova Corporation are incorporated herein by reference insofar as
they relate to San Diego Gas & Electric Company:
Note 1 -- Business Combination
Note 2 -- Significant Accounting Policies
Note 4 -- Long-Term Debt
Note 5 -- Facilities Under Joint Ownership
Note 6 -- Employee Benefit Plans
Note 8 -- Financial Instruments
Note 9 -- Contingencies and Commitments
Note 10 -- Industry Restructuring
Note 3: Significant Affiliate Transactions
In January 1996 Enova Corporation (Enova) became the parent of San Diego
Gas & Electric (SDG&E) and its subsidiaries. At that time SDG&E's
ownership interests in its subsidiaries were transferred to Enova at
book value. SDG&E's financial statements for periods prior to 1996
reflect the results of these subsidiaries as discontinued operations in
accordance with Accounting Principles Board Opinion No. 30 "Reporting
the Effects of a Disposal of a Segment of Business." Discontinued
operations are summarized in the table below:
Year Ended
December 31,
1995
- ------------------------------------------------------
(millions of dollars)
Revenues $81
Loss from operations before
income taxes (24)
Loss on disposal before income
taxes (12)
Income tax benefits 32
- ------------------------------------------------------
In December 1997 SDG&E and Enova signed a promissory note agreement for
an amount not to exceed $400 million to be loaned by SDG&E to Enova due
within one year. Interest on the outstanding balance under the note is
accrued monthly at the current three-month commercial paper rate. As of
December 31, 1997 $130 million had been issued and was outstanding under
the promissory note agreement.
In March 1997 SDG&E paid to Enova a special dividend of $70 million to
be used for the repurchase of three million shares of Enova common
stock.
Note 4: Long-Term Debt
The information contained in Enova Corporation's Statements of
Consolidated Long-Term Debt is incorporated herein by reference.
79
Note 7: Income Taxes
SDG&E's income tax payments totaled $217 million in 1997, $245 million
in
1996 and $200 million in 1995.
The components of accumulated deferred income taxes at December 31 are
as follows:
in thousands of dollars 1997 1996
- ------------------------------------------------------------------
Deferred tax liabilities
Differences in financial and
tax bases of utility plant $567,804 $628,617
Loss on reacquired debt 30,535 26,399
Other 65,675 63,081
- ------------------------------------------------------------------
Total deferred tax liabilities 664,014 718,097
- ------------------------------------------------------------------
Deferred tax assets
Unamortized investment tax credits 64,873 68,239
Regulatory balancing accounts 27,903 37,010
Unbilled revenue 22,365 21,923
Other 90,232 123,534
- ------------------------------------------------------------------
Total deferred tax assets 205,373 250,706
- ------------------------------------------------------------------
Net deferred income tax liability 458,641 467,391
Current portion (net asset) 13,249 19,728
- ------------------------------------------------------------------
Non-current portion (net liability) $471,890 $487,119
==================================================================
The components of income tax expense are as follows:
in thousands of dollars 1997 1996 1995
- ---------------------------------------------------------------
Current
Federal $164,642 $169,309 $170,212
State 43,801 45,018 44,863
- --------------------------------------------------------------
Total current taxes 208,443 214,327 215,075
- --------------------------------------------------------------
Deferred
Federal 12,922 (8,666) (23,647)
State 1,600 (1,518) (13,464)
- --------------------------------------------------------------
Total deferred taxes 14,522 (10,184) (37,111)
- --------------------------------------------------------------
Deferred investment
tax credits - net (3,809) (6,185) (4,935)
- --------------------------------------------------------------
Total income tax
expense $219,156 $197,958 $173,029
==============================================================
Federal and state income taxes are allocated between operating income
and other income.
80
The reconciliation of the statutory federal income tax rate to effective
income tax rate is as follows:
1997 1996 1995
- -------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 7.1 5.7 5.0
State income taxes - net of
federal income tax benefit 5.7 6.1 4.8
Tax credits (1.3) (2.1) (1.8)
Repair allowance (1.6) (1.1) (2.8)
Other - net 3.0 3.4 3.9
- -------------------------------------------------------------
Effective income tax rate 47.9% 47.0% 44.1%
=============================================================
Note 11: Capital Stock
The information contained in SDG&E's Statements of Changes in Capital
Stock and Retained Earnings is incorporated herein by reference. The
information contained in Enova Corporation's Statements of Consolidated
Capital Stock as it relates to preferred and preference stock is
incorporated herein by reference.
Note 12: Segments of Business
The information contained in Enova Corporation's Statements of
Consolidated Financial Information by Segments of Business is
incorporated herein by reference.
81
Note 13: Quarterly Financial Data (Unaudited)
SAN DIEGO GAS & ELECTRIC
In thousands
Quarter ended March 31 June 30 September 30 December 31
1997
Operating revenues $ 494,636 $ 491,892 $ 566,297 $ 614,723
Operating expenses 431,706 413,670 480,303 524,781
--------- --------- --------- ---------
Operating income 62,930 78,222 85,994 89,942
Other income and (deductions) 164 (444) (17) 7,659
Net interest charges 21,165 22,875 21,058 21,120
--------- --------- --------- ---------
Net income (before preferred
dividend requirements) 41,929 54,903 64,919 76,481
Preferred dividend requirements 1,646 1,645 1,646 1,645
--------- --------- --------- ---------
Earnings applicable to common shares $ 40,283 $ 53,258 $ 63,273 $ 74,836
========= ========= ========= =========
1996
Operating revenues $ 451,942 $ 458,221 $ 493,485 $ 535,269
Operating expenses 367,772 388,379 411,657 462,347
--------- --------- --------- ---------
Operating income 84,170 69,842 81,828 72,922
Other income and (deductions) 1,396 (884) 4,372 (190)
Net interest charges 22,994 22,786 24,073 20,838
--------- --------- --------- ---------
Net income (before preferred
dividend requirements) 62,572 46,172 62,127 51,894
Preferred dividend requirements 1,646 1,645 1,646 1,645
--------- --------- --------- ---------
Earnings applicable to common shares $ 60,926 $ 44,527 $ 60,481 $ 50,249
========= ========= ========= =========
These amounts are unaudited, but in the opinion of SDG&E reflect all adjustments necessary
for a fair presentation.
82
