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 June 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
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(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
June 30,
------------------
1999 1998
------------------
<S> <C> <C>
Operating Revenues:
Electric $646 $476
Natural gas 94 93
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Total operating revenues 740 569
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Expenses:
Purchased power - net 88 63
Electric fuel 21 36
Natural gas purchased for resale 43 38
Operation and maintenance 119 167
Depreciation and decommissioning 391 178
Other taxes and franchise payments 20 20
Income taxes (9) 22
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Total 673 524
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Operating Income 67 45
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Other Income and (Deductions):
Regulatory interest - net (2) 1
Allowance for equity funds used
during construction 2 1
Income taxes on nonoperating income (4) (6)
Other - net 8 13
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Total 4 9
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Income Before Interest Charges 71 54
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Interest Charges:
Long-term debt 21 24
Other 3 3
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Total 24 27
------------------
Net Income 47 27
Preferred Dividend Requirements 1 2
------------------
Earnings Applicable to Common Shares $ 46 $ 25
==================
See notes to Consolidated Financial Statements.
</TABLE>
<TABLE>
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
(Dollars in millions)
<CAPTION>
Six Months Ended
June 30,
------------------
1999 1998
------------------
<S> <C> <C>
Operating Revenues:
Electric $1,006 $973
Natural gas 195 202
------------------
Total operating revenues 1,201 1,175
------------------
Expenses:
Purchased power - net 154 159
Electric fuel 57 67
Natural gas purchased for resale 90 90
Operation and maintenance 226 266
Depreciation and decommissioning 458 377
Other taxes and franchise payments 40 43
Income taxes 38 51
------------------
Total 1,063 1,053
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Operating Income 138 122
------------------
Other Income and (Deductions):
Regulatory interest - net (2) -
Allowance for equity funds used
during construction 2 2
Income taxes on nonoperating income (11) (9)
Other - net 23 17
------------------
Total 12 10
------------------
Income Before Interest Charges 150 132
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Interest Charges:
Long-term debt 43 51
Other 5 4
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Total 48 55
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Net Income 102 77
Preferred Dividend Requirements 3 3
------------------
Earnings Applicable to Common Shares $ 99 $ 74
==================
See notes to Consolidated Financial Statements.
</TABLE>
<TABLE>
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
<CAPTION>
Balance at
-------------------------
June 30, December 31,
1999 1998
(Unaudited)
------- -------
<S> <C> <C>
ASSETS
Utility plant - at original cost $4,376 $4,903
Less accumulated depreciation and decommissioning (2,233) (2,603)
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Utility plant - net 2,143 2,300
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Nuclear decommissioning trust 507 494
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Current assets:
Cash and temporary investments 355 284
Accounts receivable 219 199
Due from affiliates 453 110
Inventories 47 77
Regulatory balancing accounts undercollected - net -- 9
Other 23 17
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Total current assets 1,097 696
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Deferred taxes recoverable in rates 99 194
Regulatory assets 253 511
Deferred charges and other assets 58 62
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Total $4,157 $4,257
======= =======
CAPITALIZATION AND LIABILITIES
Capitalization:
Common equity $1,224 $1,124
Preferred stock not subject to mandatory redemption 78 78
Preferred stock subject to mandatory redemption 25 25
Long-term debt 1,486 1,548
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Total capitalization 2,813 2,775
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Current liabilities:
Long-term debt due within one year 66 72
Accounts payable 139 165
Taxes payable 44 --
Dividends payable 2 102
Interest accrued 9 9
Regulatory balancing accounts overcollected - net 146 --
Other 127 185
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Total current liabilities 533 533
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Customer advances for construction 46 41
Deferred income taxes - net 293 397
Deferred investment tax credits 55 89
Deferred credits and other liabilities 417 422
Commitments and contingent liabilities (Note 3)
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Total $4,157 $4,257
======= =======
See notes to Consolidated Financial Statements.
</table
</TABLE>
<TABLE>
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited)
(Dollars in millions)
<CAPTION>
Six Months Ended
June 30,
------------------
1999 1998
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<S> <C> <C>
Cash Flows from Operating Activities
Net income $ 102 $ 77
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and decommissioning 458 377
Application of balancing accounts to stranded costs (62) (86)
Application of plant sale proceeds to stranded costs (295) --
Deferred income taxes and investment tax credits (91) (54)
Non-cash rate reduction bond revenue (62) (40)
Other - net 26 6
Net change in other working capital components (187) (120)
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Net cash (used) provided by operating activities (111) 160
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Cash Flows from Investing Activities:
Utility construction expenditures (90) (100)
Proceeds from sale of generating plants - net 454 --
Contributions to decommissioning funds (11) (11)
Other - net -- (1)
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Net cash provided (used) by investing activities 353 (112)
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Cash Flows from Financing Activities:
Dividends paid (103) (136)
Issuance of long-term debt 12 --
Payment on long-term debt (80) (182)
Increase in short-term debt -- 8
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Net cash used by financing activities (171) (310)
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Increase (decrease) in cash and temporary investments 71 (262)
Cash and temporary investments, January 1 284 536
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Cash and temporary investments, June 30 $ 355 $ 274
====== ======
Supplemental Disclosure of Cash Flow Information:
Interest payments (net of amounts capitalized) $ 47 $ 61
====== ======
Income tax payments (net of refunds) $ 194 $ 49
====== ======
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), a 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 Report on Form 10-Q
for the three months ended March 31, 1999. The Company's 1998 Annual
Report includes the Consolidated Financial Statements and notes
thereto, and "Management's Discussion & Analysis of Financial
Condition and Results of Operations."
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 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 corporation 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 stock of
SDG&E, PE and SoCalGas remain outstanding. Additional information on
the business combination is discussed in the Company's 1998 Annual
Report.
Expenses incurred in connection with the above were $1.1 million,
after tax, and $29 million, after tax, for the six-month periods
ended June 30, 1999 and 1998, respectively, of which $0.9 million,
after tax, and $28 million, after tax, respectively, occurred during
the three months ended June 30, 1999 and 1998.
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 adopts the December 1995 CPUC policy decision that
restructures the industry to stimulate competition and reduce rates.
Beginning on March 31, 1998, customers 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
investor-owned electric utilities (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
continues 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 as presented.
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. These costs will continue to be collected in rates.
Recovery of the stranded costs were effected by, among other things,
the sale of SDG&E's fossil power plants and combustion turbines.
During the quarter ended June 30, 1999, these sales were completed
for total net proceeds of $454 million. 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 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 facilities for the
new owners for the next two years.
Stranded costs included the cost of the San Onofre Nuclear Generating
Station (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.
AB 1890 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.
AB 1890 includes a rate freeze for all customers. Beginning in 1998,
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 SDG&E's stranded cost recovery
(described above), SDG&E filed with the CPUC for an interim mechanism
to deal with electric rates after the end of the rate freeze. SDG&E
is requesting authority to reduce base rates (the portion of the rate
that SDG&E controls) 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 would temporarily cap
rates between July 1999 and September 1999, regardless of how high
the PX price moves during that period. Any resulting undercollection
would be recovered through a balancing account mechanism for a period
of up to nine months subsequent to September 30, 1999. 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 in
January 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. The
IOUs pay to the PX an up-front 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 being recovered as a
transition cost. The IOUs have guaranteed $300 million of commercial
loans to the ISO and PX for their development and initial start-up.
SDG&E's share of the guarantee is $30 million.
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
customers prior to January 1, 2000; the CPUC continues to study the
issue. During the implementation moratorium, the CPUC will hold
hearings throughout the state and intends to give the legislature a
draft ruling before adopting a final market-structure policy. SDG&E
and SoCalGas will actively participate in this effort.
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 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 $4.5
million.
CANADIAN NATURAL GAS
SDG&E has 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 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
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
six-month periods ended June 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 six months
ended June 30, 1999, except as described in Note 3 concerning the
sale of SDG&E's power plants.
- ---------------------------------------------------------------------
Three months ended Six months ended
June 30, June 30,
----------------------------------------
(Dollars in millions) 1999 1998 1999 1998
- ---------------------------------------------------------------------
Revenues:
Transmission and distribution $ 224 $ 248 $ 482 $ 517
Electric generation 422 228 524 456
Natural gas 94 93 195 202
---------------------------------------
Total $ 740 $ 569 $1,201 $1,175
---------------------------------------
Segment Income:
Transmission and distribution $ 61 $ 45 $ 149 $ 117
Electric generation (24) 14 (15) 24
Natural gas 21 8 42 32
---------------------------------------
Total segment income 58 67 176 173
Interest expense (24) (27) (48) (55)
Income tax (expense) benefit 5 (28) (49) (60)
Nonoperating income 8 15 23 19
---------------------------------------
Net income $ 47 $ 27 $ 102 $ 77
---------------------------------------
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 June 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 costs, 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 on common stock during the six-
month period ended June 30, 1999, compared to the same period in
1998, and greater long-term debt repayments in 1998.
RESULTS OF OPERATIONS
Electric revenues increased 36 percent and 3 percent for the three-
month and six-month periods ended June 30, 1999 primarily due to the
sale of the Company's fossil-fueled power plants, partially offset by
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 ECAC
and ERAM balancing accounts at December 31, 1997. In addition, there
was a decrease in revenues as a result of a decrease in sales to
other utilities, due to the start-up of the PX. The PX is described
further under "Factors Influencing Future Performance".
Natural gas revenues increased one percent and decreased 3 percent
for the three-month and six-month periods ended June 30, 1999
compared to the same period in 1998. The decrease was due to a
decrease in the average cost of natural gas, partially offset by
increased sales to residential customers due to colder weather and
customer growth in 1999.
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 increased 13 percent for the three-
month period ended June 30, 1999. Cost of natural gas was equal to
1998 for the six-month period ended June 30, 1999. The increase for
the quarter was due to the increase in the price of natural gas
purchased. Under the current regulatory framework, changes in revenue
resulting from change in core market volumes and cost of natural gas
do not affect net income.
Depreciation and decommissioning increased in excess of 100 percent
and 21 percent for the three-month and six-month periods ended June
30, 1999, compared to the same period in 1998. The increase is due to
the accelerated recovery of generation assets partially offset by the
January 1998 application to stranded cost recovery of the ITCBA as
discussed above.
Operating income increased 49 percent and 13 percent for the three-
month and six-month periods ended June 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 three-month and six-month
periods ended June 30, 1999, compared to the corresponding period in
1998, due to the contribution to a local government agency of the
land related to one of the sold generating plants, partially offset
by the increase in income before taxes. The land contribution also
resulted in a significant decrease in the Company's effective income
tax rate.
The table below summarizes the components of electric and natural gas
volumes and revenues by customer class for the six months ended June
30, 1999 and 1998.
</TABLE>
<TABLE>
Electric Distribution
(Dollars in millions, volumes in millions of Kwhrs)
<CAPTION>
1999 1998
------------------------------------------
Volumes Revenue Volumes Revenue
------------------------------------------
<S> <C> <C> <C> <C>
Residential 3,134 $ 315 3,011 $ 305
Commercial 2,994 271 3,249 288
Industrial 968 69 1,683 112
Direct access 1,403 48 93 6
Street and highway lighting 38 3 43 4
Off-system sales 52 1 639 13
------------------------------------------
8,589 707 8,718 728
Balancing and other 299 245
------------------------------------------
Total 8,589 $1,006 8,718 $ 973
------------------------------------------
</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 25 $ 172 -- $ -- 25 $ 172
Commercial and industrial 14 60 9 9 23 69
Utility electric generation* 18 7 -- -- 18 7
--------------------------------------------------------------
57 $ 239 9 $ 9 66 248
Balancing accounts and other (53)
--------
Total $ 195
- ------------------------------------------------------------------------------------------
1998:
Residential 21 $ 163 -- $ -- 21 $ 163
Commercial and industrial 11 59 10 9 21 68
Utility electric generation* 21 5 -- -- 21 5
--------------------------------------------------------------
53 $ 227 10 $ 9 63 $ 236
Balancing accounts and other (34)
---------
Total $ 202
- ------------------------------------------------------------------------------------------
* margin only
</TABLE>
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 have now been consolidated into Sempra Energy's overall Year
2000 readiness effort. Sempra Energy has established a central Year
2000 Program Office, which reports to the Company'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
categorizing 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 are being
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 as of 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 fourth quarter 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 $43 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
reasonably likely worst case 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. Under these efforts, participating utilities are
working together to assess specific vendors' system problems and to
test plans. These assessments will be 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 critical third party suppliers and customers. The
Company continues to contact its critical 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 will be 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 below.
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. In January 1999, various
proposed and alternate decisions were released on the PBR design
issues of SDG&E's distribution PBR application. The proposed decision
released by the CPUC's Administrative Law Judge recommended, among
other things, a revenue-per-customer indexing mechanism rather than
the rate-indexing mechanism proposed by SDG&E and much tighter
earnings sharing bands than previously in effect for SDG&E. On May
13, 1999 the CPUC adopted a decision incorporating the rate-indexing
mechanism proposed by SDG&E, but also approved the tighter sharing
bands. 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 are requesting a rehearing of the rate-indexing
mechanism.
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 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 SDG&E 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.
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 its 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.
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 in early 2000.
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 six months ended June 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 4. SUBMISSION OF MATTERS TO VOTE
At the annual meeting on May 11, 1999, the Company's shareholders
elected 15 directors to hold office until the next annual meeting and
until their successors have been elected and qualified. The name of
each nominee and the number of shares voted for or withheld were as
follows:
Nominees Votes For Votes Withheld
- -------------------------------------------------------------------
Hyla H. Bertea 116,583,358 --
Ann L. Burr 116,583,358 --
Herbert L. Carter 116,583,358 --
Richard A. Collato 116,583,358 --
Daniel W. Derbes 116,583,358 --
Wilford D. Godbold, Jr. 116,583,358 --
Robert H. Goldsmith 116,583,358 --
William D. Jones 116,583,358 --
Ignacio E. Lozano, Jr. 116,583,358 --
Warren I. Mitchell 116,583,358 --
Ralph R. Ocampo 116,583,358 --
William G. Ouchi 116,583,358 --
Richard J. Stegemeier 116,583,358 --
Thomas C. Stickel 116,583,358 --
Diana L. Walker 116,583,358 --
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 six months ended
June 30, 1999.
(b) Reports on Form 8-K
A Current Report on Form 8-K filed May 21, 1999 announced
the completion of the sales of SDG&E's Encina Power Plant, 17
combustion turbines, and South Bay Power Plant.
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: August 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 six
Months Ended
1994 1995 1996 1997 1998 6/30/99
-------- -------- -------- -------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
Fixed Charges and Preferred
Stock Dividends:
Interest:
Long-Term Debt $ 82 $ 82 $ 76 $ 70 $ 55 $25
Short-Term Debt 9 18 13 14 13 7
Rate Reduction Bonds -- -- -- -- 41 18
Amortization of Debt
Discount and Expense,
Less Premium 5 5 5 5 8 4
Interest Portion of
Annual Rentals 9 10 8 9 8 3
-------- -------- -------- ------- --------- ----------
Total Fixed
Charges 105 115 102 98 125 57
-------- -------- -------- -------- --------- ----------
Preferred Dividend
Requirements 8 8 7 7 7 3
Ratio of Income Before
Tax to Net Income 1.83501 1.78991 1.88864 1.91993 1.73993 1.47447
-------- -------- -------- -------- --------- ----------
Preferred Dividends
for Purpose of Ratio 14 14 13 13 11 5
-------- -------- -------- -------- --------- ----------
Total Fixed Charges
and Preferred Stock
Dividends For
Purpose of Ratio $119 $129 $115 $111 $136 $ 62
======== ======== ======== ======== ========= =========
Earnings:
Net Income (before
preferred dividend
requirements) $206 $219 $223 $238 $191 $102
Add:
Fixed charges
(from above) 105 115 102 98 125 57
Less: Fixed charges
capitalized 1 2 1 2 1 1
Taxes on Income 172 173 198 219 141 49
-------- -------- -------- -------- --------- ----------
Total Earnings for
Purpose of Ratio $482 $505 $522 $553 $456 $207
======== ======== ======== ======== ========= ==========
Ratio of Earnings
to Combined Fixed
Charges and Preferred
Stock Dividends 4.06 3.92 4.54 5.00 3.36 3.34
======== ======== ======== ======== ========= ==========
</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> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,143
<OTHER-PROPERTY-AND-INVEST> 507
<TOTAL-CURRENT-ASSETS> 1,097
<TOTAL-DEFERRED-CHARGES> 398
<OTHER-ASSETS> 12
<TOTAL-ASSETS> 4,157
<COMMON> 291
<CAPITAL-SURPLUS-PAID-IN> 566
<RETAINED-EARNINGS> 367
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,224
25
78
<LONG-TERM-DEBT-NET> 1,470
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 66
0
<CAPITAL-LEASE-OBLIGATIONS> 16
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,278
<TOT-CAPITALIZATION-AND-LIAB> 4,157
<GROSS-OPERATING-REVENUE> 1,201
<INCOME-TAX-EXPENSE> 38
<OTHER-OPERATING-EXPENSES> 1,025
<TOTAL-OPERATING-EXPENSES> 1,063
<OPERATING-INCOME-LOSS> 138
<OTHER-INCOME-NET> 12
<INCOME-BEFORE-INTEREST-EXPEN> 150
<TOTAL-INTEREST-EXPENSE> 48
<NET-INCOME> 102
3
<EARNINGS-AVAILABLE-FOR-COMM> 99
<COMMON-STOCK-DIVIDENDS> 0
<TOTAL-INTEREST-ON-BONDS> 43
<CASH-FLOW-OPERATIONS> (111)
<EPS-BASIC> 0
<EPS-DILUTED> 0
</TABLE>
