UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 1999
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Commission file number 1-3779
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SAN DIEGO GAS & ELECTRIC COMPANY
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(Exact name of registrant as specified in its charter)
California 95-1184800
- ------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
8326 Century Park Court, San Diego, California 92123
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(Address of principal executive offices)
(Zip Code)
(619) 696-2000
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(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the registrant was required to file such
reports), and (2) has been subject to such filing requirements for
the past 90 days.
Yes X No
----- -----
Common stock outstanding: Wholly owned by Enova Corporation
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
<TABLE>
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(Dollars in millions)
<CAPTION>
Three Months Ended
September 30,
------------------
1999 1998
------------------
<S> <C> <C>
Operating Revenues:
Electric $438 $481
Natural gas 82 82
------------------
Total operating revenues 520 563
------------------
Expenses:
Purchased power - net 174 39
Electric fuel 7 70
Natural gas purchased for resale 29 30
Operation and maintenance 111 126
Depreciation and decommissioning 52 134
Other taxes and franchise payments 20 21
Income taxes 45 55
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Total 438 475
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Operating Income 82 88
------------------
Other Income and (Deductions):
Regulatory interest - net (1) (1)
Allowance for equity funds used
during construction 1 1
Income taxes on nonoperating income (11) (2)
Other - net 26 4
------------------
Total 15 2
------------------
Income Before Interest Charges 97 90
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Interest Charges:
Long-term debt 21 23
Other 15 3
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Total 36 26
------------------
Net Income 61 64
Preferred Dividend Requirements 2 2
------------------
Earnings Applicable to Common Shares $ 59 $ 62
==================
See notes to Consolidated Financial Statements.
</TABLE>
<TABLE>
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(Dollars in millions)
<CAPTION>
Nine Months Ended
September 30,
------------------
1999 1998
------------------
<S> <C> <C>
Operating Revenues:
Electric $1,443 $1,454
Natural gas 277 284
------------------
Total operating revenues 1,720 1,738
------------------
Expenses:
Purchased power - net 327 198
Electric fuel 64 137
Natural gas purchased for resale 119 120
Operation and maintenance 337 391
Depreciation and decommissioning 510 511
Other taxes and franchise payments 60 64
Income taxes 83 106
------------------
Total 1,500 1,527
------------------
Operating Income 220 211
------------------
Other Income and (Deductions):
Regulatory interest - net (3) (1)
Allowance for equity funds used
during construction 3 3
Income taxes on nonoperating income (22) (11)
Other - net 49 21
------------------
Total 27 12
------------------
Income Before Interest Charges 247 223
------------------
Interest Charges:
Long-term debt 63 74
Other 20 8
------------------
Total 83 82
------------------
Net Income 164 141
Preferred Dividend Requirements 5 5
------------------
Earnings Applicable to Common Shares $ 159 $ 136
==================
See notes to Consolidated Financial Statements.
</TABLE>
<TABLE>
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
<CAPTION>
Balance at
-------------------------
September 30, December 31,
1999 1998
(Unaudited)
------- -------
<S> <C> <C>
ASSETS
Utility plant - at original cost $4,431 $4,903
Less accumulated depreciation and decommissioning (2,274) (2,603)
------- -------
Utility plant - net 2,157 2,300
------- -------
Nuclear decommissioning trust 509 494
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Current assets:
Cash and temporary investments 299 284
Accounts receivable 197 199
Due from affiliates 559 110
Inventories 56 77
Regulatory balancing accounts undercollected - net -- 9
Other 14 17
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Total current assets 1,125 696
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Deferred taxes recoverable in rates 93 194
Regulatory assets 239 511
Deferred charges and other assets 49 62
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Total $4,172 $4,257
======= =======
CAPITALIZATION AND LIABILITIES
Capitalization:
Common equity $1,283 $1,124
Preferred stock not subject to mandatory redemption 78 78
Preferred stock subject to mandatory redemption 25 25
Long-term debt 1,440 1,548
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Total capitalization 2,826 2,775
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Current liabilities:
Long-term debt due within one year 66 72
Accounts payable 157 165
Taxes payable 69 --
Dividends payable 2 102
Interest accrued 12 9
Regulatory balancing accounts overcollected - net 149 --
Other 123 185
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Total current liabilities 578 533
------- -------
Customer advances for construction 47 41
Deferred income taxes - net 249 397
Deferred investment tax credits 54 89
Deferred credits and other liabilities 418 422
Commitments and contingent liabilities (Note 3)
------- -------
Total $4,172 $4,257
======= =======
See notes to Consolidated Financial Statements.
</TABLE>
<TABLE>
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited)
(Dollars in millions)
<CAPTION>
Nine Months Ended
September 30,
------------------
1999 1998
------ ------
<S> <C> <C>
Cash Flows from Operating Activities
Net income $ 164 $ 141
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and amortization 510 511
Application of balancing accounts to stranded costs (66) (86)
Portion of depreciation arising from
sales of generating plants (295) --
Deferred income taxes (130) (125)
Non-cash rate reduction bond revenue - net (50) (67)
Other - net 57 7
Net change in other working capital components (232) (98)
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Net cash (used) provided by operating activities (42) 283
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Cash Flows from Investing Activities:
Utility construction expenditures (165) (160)
Net proceeds from sales of generating plants 454 --
Contributions to decommissioning funds (13) (16)
Other - net - 2
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Net cash provided (used) by investing activities 276 (174)
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Cash Flows from Financing Activities:
Dividends paid (105) (138)
Issuance of long-term debt 16 --
Payment on long-term debt (130) (202)
Increase in short-term debt -- --
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Net cash used by financing activities (219) (340)
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Increase (decrease) in cash and temporary investments 15 (231)
Cash and temporary investments, January 1 284 536
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Cash and temporary investments, September 30 $ 299 $ 305
====== ======
Supplemental Disclosure of Cash Flow Information:
Interest payments (net of amounts capitalized) $ 85 $ 87
====== ======
Income tax payments (net of refunds) $ 266 $ 113
====== ======
Dividend to parent of intercompany receivable $ -- $ 100
====== ======
See notes to Consolidated Financial Statements.
</TABLE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. GENERAL
This Quarterly Report on Form 10-Q is that of San Diego Gas &
Electric Company (SDG&E or the Company), the sole subsidiary of Enova
Corporation (Enova). Enova is a wholly owned subsidiary of Sempra
Energy, a California-based Fortune 500 energy services company. The
financial statements herein are the Consolidated Financial Statements
of SDG&E and its subsidiary, SDG&E Funding LLC.
The accompanying Consolidated Financial Statements have been prepared
in accordance with the interim-period-reporting requirements of Form
10-Q. Results of operations for interim periods are not necessarily
indicative of results for the entire year. In the opinion of
management, the accompanying statements reflect all adjustments
necessary for a fair presentation. These adjustments are only of a
normal recurring nature. Certain changes in classification have been
made to prior presentations to conform to the current financial
statement presentation.
The Company's significant accounting policies, as well as those of
its subsidiaries, are described in the notes to Consolidated
Financial Statements in the Company's 1998 Annual Report. The same
accounting policies are followed for interim reporting purposes.
This Quarterly Report should be read in conjunction with the
Company's 1998 Annual Report and its Quarterly Reports on Form 10-Q
for the three-month periods ended March 31, and June 30, 1999.
SDG&E has been accounting for the economic effects of regulation on
all utility operations in accordance with Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation" (SFAS No. 71), as described in the notes to
Consolidated Financial Statements in the Company's 1998 Annual
Report. In conformity with generally accepted accounting principles
for regulated enterprises and the policies of the California Public
Utilities Commission (CPUC), SDG&E has ceased the application of SFAS
No. 71 to its generation business, in accordance with the conclusion
of the Financial Accounting Standards Board that the application of
SFAS No. 71 should be discontinued when legislation is issued that
determines that a portion of an entity's business will no longer be
subject to cost-based regulation. The discontinuance of SFAS No. 71
did not result in a write-off of SDG&E's generation assets, since the
CPUC also approved the recovery of the stranded costs related to
these assets by the distribution portion of its business. (See
further discussion in Note 3.)
2. BUSINESS COMBINATIONS
PE/Enova
On June 26, 1998 (pursuant to an October 1996 agreement) Enova and
Pacific Enterprises(PE), the parent company of the Southern
California Gas Company (SoCalGas) completed a business combination
in which the two companies became subsidiaries of a new company named
Sempra Energy. As a result of the combination, (i) each outstanding
share of common stock of Enova was converted into one share of common
stock of Sempra Energy, (ii) each outstanding share of common stock
of PE was converted into 1.5038 shares of common stock of Sempra
Energy and (iii) the preferred stock and/or preference stocks of
SDG&E, PE and SoCalGas remained outstanding. Additional information
on the business combination is discussed in the Company's 1998 Annual
Report.
No expenses were incurred in connection with the above for the nine
months and three months ended September 30, 1999. During the nine-
month and three-month periods ended September 30, 1998, expenses of
$34 million, after tax, and $5 million, after tax, respectively,
were incurred.
As a result of the business combination, Enova dividended its
nonutility subsidiaries to Sempra Energy during 1998 and early 1999.
SDG&E is now the sole direct subsidiary of Enova.
KN Energy
On February 22, 1999, Sempra Energy and KN Energy, Inc. (KN Energy)
announced that their respective boards of directors had approved
Sempra Energy's acquisition of KN Energy, subject to approval by the
shareholders of both companies and by various federal and state
regulatory agencies. On June 21, 1999, Sempra Energy and KN Energy
announced that they had agreed to terminate the proposed acquisition.
3. MATERIAL CONTINGENCIES
ELECTRIC INDUSTRY RESTRUCTURING -- CALIFORNIA PUBLIC UTILITIES
COMMISSION
In September 1996, the State of California enacted a law
restructuring California's electric utility industry (AB 1890). The
legislation adopted the December 1995 CPUC policy decision
restructuring the industry to stimulate competition and reduce rates.
Beginning on March 31, 1998, customers of California investor-owned
utilities (IOUs) were given the opportunity to choose to continue to
purchase their electricity from the local utility under regulated
tariffs, to enter into contracts with other energy-service providers
(direct access) or to buy their power from the independent Power
Exchange (PX) that serves as a wholesale power pool allowing all
energy producers to participate competitively. The PX obtains its
power from qualifying facilities, from nuclear units and, lastly,
from the lowest-bidding suppliers. The California IOUs are obligated
to sell their power supply, including owned generation and purchased-
power contracts, to the PX. The IOUs are also obligated to purchase
from the PX the power that they distribute. SDG&E's obligation to bid
into and purchase from the PX after the conclusion of the rate freeze
continued during the interim post-rate-freeze period (discussed
below). An Independent System Operator (ISO) schedules power
transactions and access to the transmission system. The local utility
continues to provide distribution service regardless of which energy
source the customer chooses. Purchases from the PX/ISO are included
in purchased-power expenses and PX/ISO power revenues have been
netted therein on the Statements of Consolidated Income presented
herein. Revenues from the PX/ISO reflect sales at market prices of
energy from SDG&E's power plants and from long-term purchased-power
contracts to the PX/ISO commencing April 1, 1998.
As discussed in the notes to Consolidated Financial Statements
contained in the Company's 1998 Annual Report, the IOUs have been
given a reasonable opportunity to recover their stranded costs via a
competition transition charge (CTC) to customers through December 31,
2001. In June 1999, SDG&E completed the recovery of its stranded
costs, other than the above-market portion of qualifying facilities
and other purchased-power contracts that were in effect at December
31, 1995, and San Onofre Nuclear Generating Station (SONGS) costs as
described below. These costs will continue to be collected in rates.
Recovery of the other stranded costs was effected by, among other
things, the sale of SDG&E's fossil power plants and combustion
turbines during the quarter ended June 30, 1999. The South Bay Power
Plant sale to the San Diego Unified Port District for $110 million
was completed on April 23, 1999. Duke South Bay, a subsidiary of Duke
Energy Power Services, will manage the plant for the Port District.
The sale of the Encina Power Plant and 17 combustion-turbine
generators to Dynegy Inc. and NRG Energy Inc. for $356 million was
completed on May 21, 1999. SDG&E will operate and maintain both the
South Bay and Encina facilities for the new owners until April 2001
and May 2001, respectively.
Stranded costs included the cost of SONGS as of December 31, 1995.
SDG&E retains ownership of its 20-percent interest in SONGS.
Subsequent SONGS costs are recoverable only from the sales of power
produced therefrom, at rates previously fixed by the CPUC through
December 31, 2002 and as determined by the market thereafter. If
approved by the CPUC, SDG&E is planning to auction its interest in
SONGS. A major issue being addressed is how to handle the
decommissioning trust to ensure that adequate funding is available at
the time the plant is decommissioned.
AB 1890 also required a 10-percent reduction of residential and small
commercial customers' rates beginning in January 1998, and provided
for the issuance of rate-reduction bonds by an agency of the State of
California to enable the IOUs to achieve this rate reduction. 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. These
bonds are being repaid over 10 years by SDG&E's residential and small
commercial customers via a non-bypassable charge on their electric
bills. In 1997, SDG&E formed a subsidiary, SDG&E Funding LLC, to
facilitate the issuance of the bonds. In exchange for the bond
proceeds, SDG&E sold to SDG&E Funding LLC all of its rights to
revenue streams collected from such customers. Consequently, the
transaction is structured to cause such revenue streams not to be the
property of SDG&E nor to be available to satisfy any claims of
SDG&E's creditors.
The sizes of the rate-reduction bond issuances were set so as to make
the IOUs neutral as to the 10-percent rate reduction, and were based
on a four-year period to recover stranded costs. Because SDG&E
recovered its stranded costs in only 18 months (due to the greater-
than-anticipated plant-sale proceeds), it is deemed that its bond
issuance should have been smaller. Accordingly, SDG&E will return to
its customers over $400 million that it has collected or will collect
from its customers. The timing of the return will differ from the
timing of the collection, but the specific timing of the repayment
and the interest rate thereon are the subject of a CPUC proceeding
and are expected to be resolved in early 2000. This refund will not
affect SDG&E's net income, except to the extent that the interest
associated with the refund (12.63 percent if not reduced as a result
of the CPUC proceeding) differs from the return earned by the Company
on the funds. The bonds and their repayment schedule are not affected
by this refund.
AB 1890 also includes a rate freeze for all IOU customers. Beginning
in 1998, SDG&E's system-average rates were fixed at 9.43 cents per
kwh. The rate freeze would have stayed in place until January 1,
2002. However, in connection with completion of its stranded cost
recovery (described above), SDG&E filed with the CPUC for a mechanism
to deal with electric rates after the end of the rate freeze. SDG&E
is requesting authority to reduce base rates (the non-commodity
portion of rates) to all electric customers. If approved, base
electric rates will decrease beyond the original 10-percent rate
reduction described above. The portion of the electric rate
representing the commodity cost is simply passed through to customers
and will fluctuate with the price of electricity from the PX. Except
for the interim protection mechanism described below, customers will
no longer be protected from commodity price spikes.
In April 1999, SDG&E filed an all-party settlement (including energy
service providers, the CPUC's Office of Ratepayer Advocates (ORA),
and the Utility Consumers Action Network (UCAN)) detailing proposed
implementation plans for lifting the rate freeze. Included in the
settlement is an interim customer-protection mechanism for
residential and small commercial customers that capped rates between
July 1999 and September 1999, regardless of how high the PX price had
moved during that period. The resulting undercollection (which
amounted to less than $1 million) is being recovered through a
balancing account mechanism. A CPUC decision adopting the all-party
settlement was issued in May 1999 and became effective July 1, 1999.
The interim rate-freeze period runs until the CPUC issues its
decision on the pending legal and policy issues of ending the rate
freeze. This decision is expected during the first quarter of 2000.
Thus far, electric-industry deregulation has been confined to
generation. Transmission and distribution have remained subject to
traditional cost-of-service regulation. However, the CPUC is
exploring the possibility of opening up electric distribution to
competition. During 1999, the CPUC will be conducting a rulemaking,
one objective of which may be to develop a coordinated proposal for
the state legislature regarding how various distribution competition
issues should be addressed. The Company will actively participate in
this effort.
ELECTRIC INDUSTRY RESTRUCTURING -- FEDERAL ENERGY REGULATORY
COMMISSION
In October 1997, the Federal Energy Regulatory Commission (FERC)
approved key elements of the California IOUs' restructuring proposal.
This included 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 the establishment of the
California PX to operate as an independent wholesale power pool.
NATURAL GAS INDUSTRY RESTRUCTURING
The natural gas industry experienced an initial phase of
restructuring during the 1980s by deregulating natural gas sales to
noncore customers. On January 21, 1998, the CPUC released a staff
report initiating a project to assess the current market and
regulatory framework for California's natural gas industry. The
general goals of the plan are to consider reforms to the current
regulatory framework emphasizing market-oriented policies benefiting
California's natural gas consumers.
In August 1998, California enacted a law prohibiting the CPUC from
enacting any natural gas industry restructuring decision for core
(residential and small commercial) customers prior to January 1,
2000; the CPUC continues to study the issue. During the
implementation moratorium, the CPUC has been holding hearings
throughout the state and intends to give the legislature a draft
ruling before adopting a final market-structure policy. SDG&E and
SoCalGas have been actively participating in this effort and have
argued in support of competition intended to maximize benefits to
customers rather than to protect competitors.
In October 1999, the State of California enacted a law (AB 1421)
which requires that gas utilities provide "bundled basic gas service"
(including transmission, storage, distribution, purchasing, revenue-
cycle services and after-meter services) to all core customers,
unless the customer chooses to purchase gas from a non-utility
provider. The law prohibits the CPUC from unbundling distribution-
related gas services (metering, billing, etc.) and after-meter
services (leak investigation, inspecting customer piping and
appliances, pilot relighting, carbon monoxide investigation, etc.)
for most customers. The objective is to preserve both customer safety
and customer choice.
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 $9.5 billion of coverage is provided by the
Nuclear Regulatory Commission Secondary Financial Protection Program
and provides for loss sharing among utilities owning nuclear reactors
if a costly accident occurs. SDG&E could be assessed up to $36
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 $2.75 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 12 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 $4.5
million.
CANADIAN NATURAL GAS
SDG&E had been involved in negotiations and litigation with four
Canadian suppliers concerning contract terms and prices. SDG&E has
settled with all of the suppliers. One of the four is delivering
natural gas under the terms of the settlement agreement through 2003;
the other three have ceased deliveries and the contracts were
terminated. Although these contracts were intended to supply SDG&E to
a level approximating the related committed long-term pipeline
capacity, SDG&E intends to continue using the pipeline capacity in
other ways, including the transport of replacement natural gas and
the release of a portion of this capacity to third parties.
4. COMPREHENSIVE INCOME AND OTHER SHAREHOLDERS' EQUITY
In conformity with generally accepted accounting principles, the
Company has adopted Statement of Financial Accounting Standards No.
130, "Reporting Comprehensive Income." Comprehensive income for the
three-month and nine-month periods ended September 30, 1999 and 1998
was equal to net income.
5. SEGMENT INFORMATION
The Company has three separately managed reportable segments:
electric transmission and distribution, electric generation, and
natural gas service. The accounting policies of the segments are the
same as those described in the notes to Consolidated Financial
Statements in the Company's 1998 Annual Report. Segment performance
is evaluated by management based on reported operating income.
Intersegment transactions are generally recorded the same as sales or
transactions with third parties. Interest expense and income tax
expense are not allocated to the reportable segments. Interest
revenue is included in other income on the Statements of Consolidated
Income herein. It is not allocated to the reportable segments. There
were no significant changes in segment assets for the nine months
ended September 30, 1999, except as described in Note 3 concerning
the sale of SDG&E's power plants.
- ---------------------------------------------------------------------
Three months ended Nine months ended
September 30, September 30,
----------------------------------------
(Dollars in millions) 1999 1998 1999 1998
- ---------------------------------------------------------------------
Revenues:
Electric trans. and dist. $ 406 $ 276 $ 887 $ 793
Electric generation 32 205 556 661
Natural gas 82 82 277 284
---------------------------------------
Total $ 520 $ 563 $1,720 $1,738
---------------------------------------
Segment Income:
Electric trans. and dist. $ 112 $ 117 $ 261 $ 234
Electric generation 4 9 (11) 33
Natural gas 11 17 53 50
---------------------------------------
Total segment income 127 143 303 317
Interest expense (36) (26) (83) (82)
Income tax expense (56) (57) (105) (117)
Nonoperating income 26 4 49 23
---------------------------------------
Net income $ 61 $ 64 $ 164 $ 141
---------------------------------------
ITEM 2.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion should be read in conjunction with the
financial statements contained in this Form 10-Q and Management's
Discussion and Analysis of Financial Condition and Results of
Operations contained in the Company's 1998 Annual Report.
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q includes forward-looking
statements within the meaning of the Private Securities Litigation
Reform Act of 1995. The words "estimates," "believes," "expects,"
"anticipates," "plans" and "intends," variations of such words, and
similar expressions are intended to identify forward-looking
statements that involve risks and uncertainties which could cause
actual results to differ materially from those anticipated.
These statements are necessarily based upon various assumptions
involving judgments with respect to the future including, among
others, local, regional, national and international economic,
competitive, political and regulatory conditions and developments;
technological developments; capital market conditions; inflation
rates; interest rates; energy markets; weather conditions; business,
regulatory or legal decisions; the pace of deregulation of retail
natural gas and electricity industries; the timing and success of
business development efforts; and other uncertainties -- all of which
are difficult to predict and many of which are beyond the control of
the Company. Accordingly, while the Company believes that the
assumptions are reasonable, there can be no assurance that they will
approximate actual experience, or that the expectations will be
realized. Readers are urged to review and consider carefully the
risks, uncertainties and other factors which affect the Company's
business described in this quarterly report and other reports filed
by the Company from time to time with the Securities and Exchange
Commission. Readers are cautioned not to put undue reliance on any
forward-looking statements. For those statements, the Company claims
the protection of the safe harbor for forward-looking statements
contained in the Private Securities Litigation Reform Act of 1995.
BUSINESS COMBINATIONS
See Note 2 of the notes to Consolidated Financial Statements
regarding the PE/Enova business combination and the agreement to
terminate the KN Energy acquisition.
CAPITAL RESOURCES AND LIQUIDITY
The Company's utility operations continue to be a major source of
liquidity. In addition, working capital requirements are met through
the issuance of short-term and long-term debt. These capital
resources are expected to remain available. Major changes in cash
flows not described elsewhere are described below. Cash and cash
equivalents at September 30, 1999 are available for investment in
utility plant, the retirement of debt, and other corporate purposes.
CASH FLOWS FROM OPERATING ACTIVITIES
The decrease in cash flows from operations is primarily due to
transactions related to the recovery of stranded electric costs as
described elsewhere herein, partially offset by relative
overcollections of regulatory balancing accounts.
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment are estimated
to be $240 million for the full year 1999 and will be financed
primarily by internally generated funds. These expenditures will
largely represent investment in rate base. Construction, investment
and financing programs are continuously reviewed and revised in
response to changes in competition, customer growth, inflation,
customer rates, the cost of capital, and environmental and regulatory
requirements.
Included in cash flows from investing activities are the proceeds
from SDG&E's plant sales. See additional discussion in Note 3 of the
notes to Consolidated Financial Statements.
CASH FLOWS FROM FINANCING ACTIVITIES
The decrease in net cash used in financing activities was primarily
due to a decrease in dividends paid to Sempra Energy during the nine-
month period ended September 30, 1999, compared to the same period in
1998, and greater long-term debt repayments in 1998.
RESULTS OF OPERATIONS
The tables below summarize the components of electric and natural gas
volumes and revenues by customer class for the nine months ended
September 30, 1999 and 1998.
<TABLE>
Electric Distribution
(Dollars in millions, volumes in millions of Kwhrs)
<CAPTION>
1999 1998
------------------------------------------
Volumes Revenue Volumes Revenue
------------------------------------------
<S> <C> <C> <C> <C>
Residential 4,753 $ 491 4,766 $ 484
Commercial 4,733 446 5,195 500
Industrial 1,523 116 2,496 190
Direct access 2,304 88 438 30
Street and highway lighting 57 5 64 6
Off-system sales 290 7 661 14
------------------------------------------
13,660 1,153 13,620 1,224
Balancing and other 290 230
------------------------------------------
Total 13,660 $1,443 13,620 $1,454
------------------------------------------
</TABLE>
<TABLE>
Gas Sales, Transportation & Exchange
(Dollars in millions, volumes in billion cubic feet)
<CAPTION>
Gas Sales Transportation & Exchange Total
--------------------------------------------------------------------
Throughput Revenue Throughput Revenue Throughput Revenue
--------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
1999:
Residential 30 $ 210 -- $ -- 30 $ 210
Commercial and industrial 19 82 13 11 32 93
Utility electric generation 18 7* 15 4 33 11
--------------------------------------------------------------
67 $ 299 28 $ 15 95 314
Balancing accounts and other (37)
--------
Total $ 277
- ------------------------------------------------------------------------------------------
1998:
Residential 26 $ 198 -- $ -- 26 $ 198
Commercial and industrial 15 80 15 13 30 93
Utility electric generation 45 7* -- -- 45 7
--------------------------------------------------------------
86 $ 285 15 $ 13 101 $ 298
Balancing accounts and other (14)
---------
Total $ 284
- ------------------------------------------------------------------------------------------
* margin only
</TABLE>
Electric revenues decreased 9 percent and 1 percent for the
three-month and nine-month periods ended September 30, 1999
compared to the corresponding periods in 1998, respectively. The
decrease for the three-month period is primarily due to the
reduction in base electric rates from the elimination of the
rate freeze effective July 1, 1999. The decrease for the nine-
month period is primarily due to the January 1998 application to
stranded cost recovery of the $130 million balance in the
Interim Transition Cost Balancing Account (ITCBA), which had
been transferred from the then-discontinued Energy Cost
Adjustment Clause(ECAC) and Electric Revenue Adjustment
Mechanism (ERAM) balancing accounts at December 31, 1997 and the
decrease in revenues discussed above.
Natural gas revenues for the three-month period ended September 30,
1999 were equal to the same period in 1998. Natural gas revenues
decreased 2 percent for the nine-month period ended September 30,
1999 compared to the same period in 1998. Residential sales for the
nine-month period increased primarily due to greater volumes. The
increase in balancing accounts and other is primarily due to greater
overcollections in 1999 versus the same period for 1998.
As discussed in Note 3, PX/ISO power revenues have been netted
against purchased-power expenses, including purchases from the
PX/ISO. The PX/ISO began operations in April 1998.
Cost of natural gas distributed decreased 3 percent and 1
percent for the three-month and nine-month periods ended
September 30, 1999 compared to the corresponding periods in
1998. The decreases were primarily due to decreases in volumes,
partially offset by higher prices of natural gas. Under the
current regulatory framework, changes in revenue resulting from
changes in core-market volumes and the cost of natural gas do
not affect net income.
Depreciation and decommissioning expense decreased 61 percent
for the three-month period ended September 30, 1999, compared to
the same period in 1998. Depreciation and decommissioning was
consistent for the nine-month period ended September 30, 1999
compared to 1998. The decrease for the three-month period is due
to the accelerated recovery of generation assets due to the sale
of SDG&E's fossil power plants and combustion turbines. As a
result of the sale, there was no depreciation expense recorded
in the third quarter of 1999 related to stranded generation
facilities. Nine-month results include the accelerated recovery
of generation assets discussed above, offset by the January 1998
application to stranded cost recovery of the ITCBA.
Operating income decreased 7 percent for the three-month period
ended September 30, 1999 compared to the same period in 1998.
The decrease is primarily due to lower electric sales during the
quarter. Operating income increased 4 percent for the nine-month
period ended September 30, 1999, compared to the same period in
1998, primarily due to lower business combination costs, as
previously discussed.
Income tax expense decreased for the nine-month period ended
September 30, 1999, compared to the corresponding period in
1998. The decrease is primarily due to the contribution to a
local government agency of the land related to one of the sold
generating plants, partially offset by higher income before
taxes. The land contribution also resulted in a significant
decrease in the Company's effective income tax rate.
YEAR 2000 ISSUES
Most companies are affected by the inability of many automated
systems and applications to process the year 2000 and beyond. The
Year 2000 issues are the result of computer programs and other
automated processes using two digits to identify a year, rather than
four digits. Any of the Company's computer programs that include
date-sensitive software may recognize a date using "00" as
representing the year 1900, instead of the year 2000, or "01" as
1901, etc., which could lead to system malfunctions. The Year 2000
issue impacts both Information Technology ("IT") systems and also
non-IT systems, including systems incorporating embedded processors.
To address this problem, in 1996, both Pacific Enterprises and Enova
Corporation established company-wide Year 2000 programs. These
programs were consolidated into Sempra Energy's overall Year 2000
readiness effort. Sempra Energy established a central Year 2000
Program Office, which reports to Sempra Energy's Chief Information
Technology Officer and reports periodically to the audit committee of
the Board of Directors.
The Company's State of Readiness
Sempra Energy has identified all significant IT and non-IT systems
(including embedded systems) that might not be Year 2000 ready and
categorized them in the following areas: IT applications, computer
hardware and software infrastructure, telecommunications, embedded
systems, and third parties. The Company evaluated its exposure in all
of these areas. These systems and applications are being tracked and
measured through four key phases: inventory, assessment,
remediation/testing, and Year 2000 readiness. The Company has
prioritized so that, when possible, critical systems were assessed
and modified/replaced first. Critical systems are those applications
and systems, including embedded processor technology, which, if not
appropriately remediated, may have a significant impact on energy
delivery, revenue collection, or the safety of personnel, customers
or facilities. The Company's Year 2000 testing effort includes
functional testing of Year 2000 dates and validating that changes
have not altered existing functionality. The Company uses an
independent, internal review process to verify that the appropriate
testing has occurred.
The Company's Year 2000 project is currently on schedule, with
critical energy delivery systems for both SoCalGas and SDG&E Year
2000 Ready since June 30, 1999. The Company defines "Year 2000 Ready"
as suitable for continued use into the year 2000 with no significant
operational problems.
Sempra Energy's current schedule for Year 2000 testing and readiness
for non-critical systems is to be completed by the end of 1999. In
certain cases, this schedule is dependent upon the efforts of third
parties, such as suppliers (including energy producers) and
customers. Accordingly, delays by third parties may cause the
Company's schedule to change. In addition, a continued readiness
management process has been implemented to monitor and review the
progress of Year 2000 readiness of the Company's systems.
The Costs to Address the Company's Year 2000 Issues
Sempra Energy's budget for the Year 2000 program is $48 million, of
which $44 million has been spent. As the Company continues to assess
its systems and as the remediation and testing efforts progress, cost
estimates may change. The Company's Year 2000 readiness effort is
being funded entirely by operating cash flows.
The Risks of the Company's Year 2000 Issues
Based upon its current assessment and testing of the Year 2000 issue,
the Company believes the reasonably likely worst case Year 2000
scenarios to have the following impacts upon Sempra Energy and its
operations. With respect to the Company's ability to provide energy
to its domestic utility customers, the Company believes that the
scenario is for small, localized interruptions of utility service
which are restored in a time frame that is within normal service
levels. With respect to services that are essential to Sempra
Energy's operations, such as customer service, business operations,
supplies and emergency response capabilities, the scenario is for
minor disruptions of essential services with rapid recovery and all
essential information and processes ultimately recovered.
To assist in preparing for and mitigating these possible scenarios,
Sempra Energy is a member of several industry-wide efforts
established to deal with Year 2000 problems affecting embedded
systems and equipment used by the nation's natural gas and electric
power companies. Successful contingency drills were held with eight
west-coast natural gas pipeline companies on August 24, 1999 and with
the North American Electric Reliability Council (NERC) on September
9, 1999.
Under these efforts, participating utilities are working together to
assess specific vendors' system problems and to test plans. These
assessments are being shared by the industry as a whole to facilitate
Year 2000 problem solving.
A portion of this risk is due to the various Year 2000 Ready
schedules of major suppliers and customers. The Company continues to
contact its major suppliers and customers to survey their Year 2000
remediation programs. While risks related to the lack of Year 2000
readiness by third parties could materially and adversely affect the
Company's business, results of operations and financial condition,
the Company expects its Year 2000 readiness efforts to reduce
significantly the Company's level of uncertainty about the impact of
third party Year 2000 issues on both its IT systems and its non-IT
systems.
The Company's Contingency Plans
The Company's contingency plans for Year-2000-related interruptions
have been completed and were submitted to the CPUC on July 1, 1999.
These plans will continue to be revised and improved during the
remainder of 1999. The contingency plans include emergency backup and
recovery procedures, replacing electronic applications with manual
processes, and identification of alternate suppliers, along with
increasing inventory levels. In addition, the following key
contingency actions will be taken.
? Only critical system changes will be implemented during
December 1999 and January 2000.
? An hour-by-hour plan will be developed to cover key
contingency actions.
? On-site staffing will be in place at key operational and
administrative locations.
? Designated standby staff will be on-call with thirty-minute
availability.
? Emergency Operations Centers will be activated on December
31, 1999.
? Walk-through drills are being held during the fourth quarter
of 1999.
Due to the speculative and uncertain nature of contingency planning,
there can be no assurances that such plans actually will be
sufficient to reduce the risk of material impacts on the Company's
operations due to Year 2000 issues.
FACTORS INFLUENCING FUTURE PERFORMANCE
Because of the ratemaking and regulatory process, electric and
natural gas industry restructuring, and the changing energy
marketplace, there are several factors that will influence the
Company's future financial performance. These factors are discussed
in this section.
Industry Restructuring
See discussion of industry restructuring in Note 3 of the notes to
Consolidated Financial Statements.
Electric-Generation Assets and Electric Rates
Note 3 of the notes to Consolidated Financial Statements describes
regulatory and legislative actions that affect SDG&E's electric
rates, and the related sale of its fossil plants and recovery of the
cost of all SDG&E generation-related assets.
Performance-Based Regulation (PBR)
To promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, the CPUC has been
directing utilities to use PBR. PBR has replaced the general rate
case and certain other regulatory proceedings for both SoCalGas and
SDG&E. Under PBR, regulators require future income potential to be
tied to achieving or exceeding specific performance and productivity
goals, as well as cost reductions, rather than relying solely on
expanding utility rate base in a market where a utility already has a
highly developed infrastructure.
SDG&E continues to participate in PBR for its electric distribution
and natural gas businesses. In December 1998, the CPUC approved
SDG&E's Cost of Service proceeding, resulting in an authorized
revenue increase of $12 million (an electric distribution increase of
$18 million and a natural gas decrease of $6 million). New rates
became effective on January 1, 1999. On May 13, 1999 the CPUC adopted
a decision on the PBR design issues of SDG&E's distribution PBR
application, incorporating the rate-indexing mechanism proposed by
SDG&E, but also approving tighter bands for sharing enhanced earnings
than previously in effect for SDG&E. The decision also adopted an
all-party settlement on various performance incentives, allowing
SDG&E the opportunity to accrue up to $14.5 million annually in
performance rewards or penalties. Certain intervenors requested a
rehearing of the rate-indexing mechanism. On November 4, 1999 the
CPUC denied this request. The new PBR mechanism is effective
retroactive to January 1, 1999 and remains in effect until December
31, 2002. SDG&E must file a new cost of service study and a request
for a new PBR mechanism in December 2001.
Cost of Capital
Under PBR, annual Cost of Capital proceedings were replaced by an
automatic adjustment mechanism if changes in certain indices exceed
established tolerances. For SDG&E, electric-industry restructuring is
changing the method of calculating the utility's annual cost of
capital. SDG&E's May 1998 application to the CPUC for unbundled rates
established new, separate rates of return for SDG&E's electric
distribution and natural gas businesses. The application proposed a
12.00 percent rate of return on common equity (ROE), which would
produce an overall ROR of 9.33 percent. A CPUC decision in June 1999
granted SDG&E an ROE of 10.6 percent (overall ROR of 8.75 percent).
This resulted in annual revenue requirement reductions of $14.6
million and $4.8 million for electric distribution and gas sales,
respectively, effective July 1, 1999. SDG&E filed an Application for
Rehearing of this decision in July 1999, requesting that the ROE be
increased to 10.8 percent after correcting computational errors in
the original decision. The Application for Rehearing is pending.
Annual Earnings Assessment Proceeding
An application was filed in May 1999 to recover shareholder rewards
for the Demand Side Management (DSM) programs and incentives earned
for the energy-efficiency and low-income programs totaling $12
million ($10 million for electric and $2 million for gas). The
revenue requirement increase is proposed to become effective on
January 1, 2000. The DSM rewards and low-income program incentives
will be collected and recorded in earnings over ten years. The
energy-efficiency program incentives are recovered in one year.
Rewards and incentives for these programs are subject to CPUC
approval. A final decision is expected during the first quarter of
2000.
The CPUC has extended interim utility administration of energy-
efficiency and low-income programs through December 31, 2001.
Biennial Cost Allocation Proceeding (BCAP)
The BCAP determines how a utility's costs are allocated among various
customer classes (residential, commercial, industrial, etc.). SDG&E
filed the 1999 BCAP application in October 1998, with hearings held
during the first half of 1999. At the conclusion of hearings, a joint
BCAP recommendation was reached proposing, among other things, an
overall natural gas rate reduction of $11 million for SDG&E. A CPUC
decision is expected during the first quarter of 2000.
ITEM 3. MARKET RISK
There have been no significant changes in the risk issues affecting
the Company
subsequent to those discussed in the Annual Report on Form 10-K for
1998 except as to the sale of the power plants and related impact on
stranded costs. "ITEM 2. Management's Discussion and Analysis of
Financial Condition and Results of Operations" herein includes
discussion of various risk issues.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Except for the matters referred to in the Company's 1998 Annual
Report or referred to elsewhere in this Quarterly Report on Form 10-Q
for the three months ended September 30, 1999, neither the Company
nor any of its affiliates is a party to, nor is its property the
subject of, any material pending legal proceedings other than routine
litigation incidental to its businesses.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit 12 - Computation of ratios
12.1 Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends.
Exhibit 27 - Financial Data Schedules
27.1 Financial Data Schedule for the nine months ended
September 30, 1999.
(b) Reports on Form 8-K
None.
SIGNATURE
Pursuant to the requirement of the Securities Exchange Act of 1934,
SDG&E has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
SAN DIEGO GAS & ELECTRIC COMPANY
(Registrant)
Date: November 12, 1999 By: /s/ E.A. Guiles
-----------------------------
E.A. Guiles
President
<TABLE>
EXHIBIT 12.1
SAN DIEGO GAS & ELECTRIC COMPANY
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
(Dollars in millions)
<CAPTION>
For the Nine
Months Ended
1994 1995 1996 1997 1998 9/30/99
-------- -------- -------- -------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Fixed Charges and Preferred
Stock Dividends:
Interest:
Long-Term Debt $ 82 $ 82 $ 76 $ 70 $ 55 $37
Short-Term Debt & Other 9 18 13 14 13 22
Rate Reduction Bonds -- -- -- -- 41 26
Amortization of Debt
Discount and Expense,
Less Premium 5 5 5 5 8 6
Interest Portion of
Annual Rentals 9 10 8 9 8 5
-------- -------- -------- ------- --------- ----------
Total Fixed
Charges 105 115 102 98 125 96
-------- -------- -------- -------- --------- ----------
Preferred Dividend
Requirements 8 8 7 7 7 5
Ratio of Income Before
Tax to Net Income 1.83501 1.78991 1.88864 1.91993 1.73993 1.63909
-------- -------- -------- -------- --------- ----------
Preferred Dividends
for Purpose of Ratio 14 14 13 13 11 8
-------- -------- -------- -------- --------- ----------
Total Fixed Charges
and Preferred Stock
Dividends For
Purpose of Ratio $119 $129 $115 $111 $136 $104
======== ======== ======== ======== ========= =========
Earnings:
Net Income (before
preferred dividend
requirements) $206 $219 $223 $238 $191 $163
Add:
Fixed charges
(from above) 105 115 102 98 125 96
Less: Fixed charges
capitalized 1 2 1 2 1 1
Taxes on Income 172 173 198 219 141 105
-------- -------- -------- -------- --------- ----------
Total Earnings for
Purpose of Ratio $482 $505 $522 $553 $456 $363
======== ======== ======== ======== ========= ==========
Ratio of Earnings
to Combined Fixed
Charges and Preferred
Stock Dividends 4.06 3.92 4.54 5.00 3.36 3.49
======== ======== ======== ======== ========= ==========
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND> THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION
EXTRACTED FROM THE CONDENSED STATEMENT OF CONSOLIDATED INCOME,
BALANCE SHEET AND CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY
BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
<CIK> 0000086521
<NAME> SAN DIEGO GAS & ELECTRIC COMPANY
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,157
<OTHER-PROPERTY-AND-INVEST> 509
<TOTAL-CURRENT-ASSETS> 1,125
<TOTAL-DEFERRED-CHARGES> 378
<OTHER-ASSETS> 3
<TOTAL-ASSETS> 4,172
<COMMON> 291
<CAPITAL-SURPLUS-PAID-IN> 566
<RETAINED-EARNINGS> 426
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,283
25
78
<LONG-TERM-DEBT-NET> 1,427
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 54
0
<CAPITAL-LEASE-OBLIGATIONS> 13
<LEASES-CURRENT> 12
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,280
<TOT-CAPITALIZATION-AND-LIAB> 4,172
<GROSS-OPERATING-REVENUE> 1,720
<INCOME-TAX-EXPENSE> 83
<OTHER-OPERATING-EXPENSES> 1,417
<TOTAL-OPERATING-EXPENSES> 1,500
<OPERATING-INCOME-LOSS> 220
<OTHER-INCOME-NET> 27
<INCOME-BEFORE-INTEREST-EXPEN> 247
<TOTAL-INTEREST-EXPENSE> 83
<NET-INCOME> 164
5
<EARNINGS-AVAILABLE-FOR-COMM> 159
<COMMON-STOCK-DIVIDENDS> 0
<TOTAL-INTEREST-ON-BONDS> 63
<CASH-FLOW-OPERATIONS> (42)
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
