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, 1998
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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.)
101 Ash Street, San Diego, California 92101
- -------------------------------------------------------------------
(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
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Common stock outstanding: Wholly owned by Enova Corporation
ITEM 1. FINANCIAL STATEMENTS.
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
In thousands of dollars
Three Months Nine Months
Ended September 30 Ended September 30
------------------ ---------------------
1998 1997 1998 1997
------------------ ---------------------
Operating Revenues
Electric $481,223 $484,218 $1,454,750 $1,274,928
PX/ISO power 252,194 -- 365,830 --
Gas 82,414 82,079 284,085 277,897
------------------ ---------------------
Total operating revenues 815,831 566,297 2,104,665 1,552,825
------------------ ---------------------
Operating Expenses
PX/ISO power 218,668 -- 331,200 --
Purchased power 72,098 134,712 232,420 311,391
Electric fuel 69,897 45,661 136,997 124,083
Gas purchased for resale 29,621 32,254 119,998 122,767
Maintenance 26,175 19,440 73,808 62,795
Depreciation and decommissioning 133,665 81,116 510,562 242,244
Property and other taxes 10,515 10,870 32,693 33,542
General and administrative 60,901 50,002 213,149 139,253
Other 51,135 45,041 137,618 128,502
Income taxes 54,748 61,207 105,714 161,102
------------------ ---------------------
Total operating expenses 727,423 480,303 1,894,159 1,325,679
------------------ ---------------------
Operating Income 88,408 85,994 210,506 227,146
------------------ ---------------------
Other Income and (Deductions)
Allowance for equity funds used
during construction 1,313 1,402 3,231 4,271
Taxes on nonoperating income (1,722) 536 (10,656) 1,824
Other - net 4,398 (1,955) 25,914 (6,392)
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Net other income and
(deductions) 3,989 (17) 18,489 (297)
------------------ ---------------------
Income Before Interest Charges
and Preferred Dividends 92,397 85,977 228,995 226,849
------------------ ---------------------
Interest Charges
Long-term debt 22,865 17,293 73,918 53,226
Other interest 6,207 4,391 15,117 13,795
Allowance for borrowed funds
used during construction (412) (626) (1,140) (1,923)
------------------ ---------------------
Net interest charges 28,660 21,058 87,895 65,098
------------------ ---------------------
Net Income 63,737 64,919 141,100 161,751
Dividends on preferred stock 1,646 1,646 4,937 4,937
------------------ ---------------------
Earnings Applicable to Common Shares $ 62,091 $ 63,273 $ 136,163 $ 156,814
================== =====================
See notes to consolidated financial statements.
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
In thousands of dollars
September 30, December 31,
Balance at 1998 1997
(Unaudited)
------------ ------------
ASSETS
Utility plant - at original cost $4,886,741 $4,750,607
Accumulated depreciation
and decommissioning (2,533,708) (2,391,541)
------------ ------------
Utility plant - net 2,353,033 2,359,066
------------ ------------
Nuclear decommissioning trusts 432,450 399,143
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Current assets
Cash and cash equivalents 304,671 536,050
Accounts receivable - trade 142,843 144,837
Accounts receivable - other 100,524 84,311
Due from affiliates 232,821 125,417
Inventories 66,608 65,390
Other 14,108 51,840
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Total current assets 861,575 1,007,845
------------ ------------
Deferred taxes recoverable in rates 175,843 184,837
Regulatory assets 435,233 608,353
Deferred charges and other assets 140,384 95,249
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Total $4,398,518 $4,654,493
============ ============
CAPITALIZATION AND LIABILITIES
Capitalization
Common equity $1,204,944 $1,387,363
Preferred stock
Not subject to mandatory redemption 78,475 78,475
Subject to mandatory redemption 25,000 25,000
Long-term debt 1,586,364 1,787,823
------------ ------------
Total capitalization 2,894,783 3,278,661
------------ ------------
Current liabilities
Long-term debt due within one year 72,671 72,575
Accounts payable 136,390 161,039
Accrued interest and dividends 143,029 56,436
Accrued taxes 112,695 --
Regulatory balancing accounts - net 19,845 58,063
Other 138,747 114,388
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Total current liabilities 623,377 462,501
------------ ------------
Customer advances for construction 39,728 37,661
Post-retirement benefits other than pensions 30,894 31,488
Deferred income taxes 355,631 471,890
Deferred investment tax credits 90,918 62,332
Deferred credits and other liabilities 363,187 309,960
------------ ------------
Total deferred credits and
other liabilities 880,358 913,331
------------ ------------
Commitments and contingent
liabilities (Note 3)
Total $4,398,518 $4,654,493
============ ============
See notes to consolidated financial statements.
San Diego Gas & Electric Company and Subsidiary
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited)
In thousands of dollars
For the nine months ended September 30 1998 1997
---------- ----------
Cash Flows from Operating Activities
Net income $141,100 $161,751
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation and decommissioning 510,562 242,244
Amortization of deferred charges and other assets 7,675 4,714
Amortization of deferred credits
and other liabilities (4,431) (3,183)
Allowance for equity funds used during construction (3,231) (4,271)
Deferred income taxes and investment tax credits (124,604) (14)
Application of balancing accounts to stranded costs (86,000) --
Other - net (60,104) 5,611
Net changes in working capital (97,955) 26,021
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Net cash provided by operating activities 283,012 432,873
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Cash Flows from Financing Activities
Dividends paid (137,841) (140,212)
Special dividend paid -- (66,150)
Payment on long-term debt (202,437) (92,796)
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Net cash used by financing activities (340,278) (299,158)
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Cash Flows from Investing Activities
Expenditures for utility plant (159,646) (141,544)
Contributions to decommissioning funds (16,534) (16,527)
Other - net 2,067 (8,162)
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Net cash used in investing activities (174,113) (166,233)
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Net decrease in cash and cash equivalents (231,379) (32,518)
Cash and cash equivalents, beginning of period 536,050 81,409
---------- ----------
Cash and cash equivalents, end of period $304,671 $ 48,891
========== ==========
Supplemental Disclosure of Cash Flow Information
Income tax payments, net of refunds $112,974 $ 135,745
========== ==========
Interest payments, net of amounts capitalized $ 86,980 $ 61,544
========== ==========
Supplemental Schedule of Noncash Activities
Dividend to Parent of Intercompany Receivable $100,000 $ --
========== ==========
See notes to consolidated financial statements.
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), a subsidiary of Enova Corporation
(Enova), which is a subsidiary of Sempra Energy. 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. This Quarterly Report should be read in
conjunction with the Company's 1997 Annual Report on Form 10-K,
which includes the consolidated financial statements and notes
thereto, and the annual "Management's Discussion & Analysis of
Financial Condition and Results of Operations," its Quarterly
Reports on Form 10-Q for the three months ended March 31, 1998 and
for the three months ended June 30, 1998, and the Current Report on
Form 8-K filed by Sempra Energy (Commission no. 1-14201) with the
Securities and Exchange Commission on June 30, 1998 in connection
with the completion of the business combination of Pacific
Enterprises and Enova Corporation.
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 of a
normal recurring nature. Certain changes in classification have
been made to prior presentations to conform to the current
financial statement presentation.
SDG&E has been accounting for the economic effects of regulation on
all of its utility operations in accordance with SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation," as
described in the notes to consolidated financial statements in
SDG&E's Annual Report to Shareholders. 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 regulated. The
discontinuance of SFAS No. 71 has not resulted in a write-off of
SDG&E's generation assets, since the California Public Utilities
Commission (CPUC) has approved the recovery of the stranded costs
related to these assets by the distribution portion of its
business, subject to a rate cap. (See further discussion in Note
3.)
The new revenue and expense captions on the Consolidated Statements
of Income (both entitled "PX/ISO Power") relate to the new
regulatory requirements concerning the way power is purchased by
and sold by the distribution and generation, respectively,
operations of SDG&E. This is discussed in Note 3.
2. BUSINESS COMBINATION
On June 26, 1998 (pursuant to an October 1996 agreement) Enova and
PE 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 Current Report on Form 8-K
filed with the Securities and Exchange Commission by Sempra Energy
on June 30, 1998.
Expenses incurred in connection with the business combination are
$34 million, after tax, and $6 million, after tax, for the nine-
month periods ended September 30, 1998 and 1997, respectively.
These costs consist primarily of employee-related costs, and
investment banking, legal, regulatory and consulting fees.
In conjunction with the business combination, on September 30, 1998
Enova's and PE's ownership interests in certain non-utility
subsidiaries were transferred to Sempra Energy at book value.
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 bid their power supply, including owned generation and
purchased-power contracts, into the PX. An Independent System
Operation (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. An example of these changes in the electric-utility
environment is the U.S. Navy, SDG&E's largest customer. The U.S.
Navy's contract to purchase energy from SDG&E was not renewed when
it expired on September 30, 1998. Instead, the U.S. Navy elected to
obtain energy through direct access and SDG&E continues to provide
the distribution service.
As discussed in Note 13 in the notes to supplemental consolidated
financial statements contained in Sempra Energy's Current Report on
Form 8-K filed with the Securities and Exchange Commission on June
30, 1998, 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. Excluding the costs
of purchased power and other costs whose recovery is not limited to
the pre-2002 period, the balance of SDG&E's stranded assets at
September 30, 1998 is $700 million, consisting of $500 million for
the power plants (see the following paragraph) and $200 million of
related deferred taxes and undercollections. During the 1998-2001
period, recovery of transition costs is limited by a rate cap
(discussed below). Generation plant additions made after December
20, 1995 are not eligible for transition cost recovery. Instead,
each utility must file a separate application seeking a
reasonableness review thereof. The CPUC has approved an agreement
between SDG&E and the CPUC's Office of Ratepayer Advocates (ORA)
for the recovery of $13.6 million of SDG&E's $14.5 million in 1996
capital additions for the Encina and South Bay power plants. In
addition, in August 1998 SDG&E submitted an application to the CPUC
seeking recovery of $22 million in capital additions for 1997 and
the first three months of 1998. That application is being reviewed
by the ORA.
In November 1997 SDG&E announced a plan to auction its power plants
and other generation assets. This plan includes the divestiture of
SDG&E's fossil power plants and combustion turbines, its 20-percent
interest in the San Onofre Nuclear Generating Station (SONGS) and
its portfolio of long-term purchased-power contracts. The power
plants have a net book value as of September 30, 1998 of $500
million ($300 million for SONGS and $200 million for fossil plants)
and a combined generating capacity of 2,400 megawatts. The
proceeds from the sales will be applied directly to SDG&E's
transition costs. The fossil-fuel assets auction is being separated
from the auction of SONGS and the purchased-power contracts. In
October 1998 the CPUC issued a draft decision approving the
commencement of the fossil-fuel assets auction. SDG&E expects the
sale of its fossil plants to be completed in the first quarter of
1999.
SDG&E and the San Diego Unified Port District have signed a
Memorandum of Understanding contemplating the purchase by the Port
District of the 693-MW South Bay Power Plant for $112 million and
SDG&E will donate the related site to the Port District, realizing
a significant income-tax benefit and resulting in full recovery of
the plant's carrying amount. As a result of this transaction, the
South Bay Power Plant has been removed from the auction. First-
round bids on SDG&E's remaining fossil plant, Encina, and the
combustion turbines were submitted in September 1998. Final,
binding bids are due on December 1.
Management believes that the rates within the rate cap and the
proceeds from the sale of electric-generating assets will be
sufficient to recover all of SDG&E's approved transition costs by
December 31, 2001, not including the post-2001 purchased-power
contract payments that may be recovered after 2001 (see discussion
above). However, if the proceeds from the sales are less than
expected or if 1998-2001 generation costs, principally fuel costs,
are greater than anticipated, SDG&E may be unable to recover all of
its approved transition costs. This would result in a charge
against earnings at the time it ceases to be probable that SDG&E
will be able to recover all of the transition costs (see below).
AB 1890 requires 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. Until the earlier
of March 31, 2002, or when transition cost recovery is complete,
SDG&E's system average rate will be frozen at the June 10, 1996
levels of 9.64 cents per kilowatt-hour (kwh), except for the impact
of certain fuel cost changes and the 10-percent rate reduction
described above. Beginning in 1998 system-average rates were fixed
at 9.43 cents per kwh, which includes the maximum-permitted
increase related to fuel cost increases and the mandatory rate
reduction.
In June 1998 a coalition of consumer groups received verification
that its electric restructuring ballot initiative received the
needed signatures to qualify for the November 3, 1998 California
ballot. The initiative seeks to amend or repeal AB 1890 in various
respects, including requiring utilities to provide a 10-percent
reduction in electricity rates charged to residential and small
commercial customers in addition to the 10-percent rate reduction
that became effective on January 1, 1998. Among other things, the
initiative would require that this rate reduction be achieved
through the elimination or reduction of CTC payments and prohibit
the collection of the charge on customer bills that would finance
the rate reduction. The Company cannot predict the outcome on the
vote of the initiative; and the effect of the initiative on SDG&E's
business, if passed by the voters, could be uncertain for some
time. If the initiative is passed by the voters, SDG&E and the
other IOUs intend to challenge it as unconstitutional and to seek
an immediate stay of its implementation. If the initiative were to
be upheld by the courts in whole or in parts, it could have a
material adverse effect on SDG&E's results of operations and
financial position. If the initiative is passed by the voters and
SDG&E is unable to determine that recovery of the related assets is
probable, through invalidation of the initiative or otherwise, it
would write down the assets to the amount, if any, probable of
recovery. If the most onerous interpretations of the initiative's
provisions are applied, and it is assumed that SDG&E's nuclear-
generation facilities have zero market value and that SDG&E's
fossil-generation assets have a market value equal to their
carrying amounts, the potential write-down of SDG&E's generation-
related assets could amount to as much as approximately $400
million after taxes. In addition, the annual after-tax earnings
reductions could be as large as approximately $50 million in 1999,
followed by declining amounts for some years thereafter.
If the initiative (known as "Proposition 9") ultimately is
overturned by the courts but had not been stayed by the courts
pending the litigation process, the likelihood of full recovery of
stranded assets (see above) will be diminished unless the courts or
the CPUC provide for relief for the fact that a portion of the
four-year period for stranded-asset recovery will have passed.
ELECTRIC INDUSTRY RESTRUCTURING -- FEDERAL ENERGY REGULATORY
COMMISSION
In October 1997 the 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.
SDG&E is in discussions with the staffs of the FERC, CPUC and ISO
to determine SDG&E's revenue-requirements for its fossil-fuel "must
run" generating plants. Excluding the cost of fuel, generation
revenue requirements for the plants will be frozen for four years
(even after SDG&E divests its fossil generation). Major capital
additions to the plants during this period will be allowed by the
ISO through separate filings with the FERC.
GAS INDUSTRY RESTRUCTURING
The gas industry experienced an initial phase of restructuring
during the 1980s by deregulating 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 natural-
gas consumers.
On August 25, 1998 the Governor of California signed into law a
bill prohibiting the CPUC from enacting any 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 California Legislature a draft ruling before
adopting a final market structure policy no earlier than January 1,
2000. SDG&E and SoCalGas will actively participate in this effort.
NUCLEAR INSURANCE
SDG&E and the co-owners of the SONGS units have purchased primary
insurance of $200 million, the maximum amount available, for public
liability claims. An additional $8.7 billion of coverage is
provided by secondary financial protection required by the Nuclear
Regulatory Commission and provides for loss sharing among utilities
owning nuclear reactors if a costly accident occurs. SDG&E could be
assessed retrospective premium adjustments of up to $32 million in
the event of a nuclear incident involving any of the licensed,
commercial reactors in the United States, if the amount of the loss
exceeds $200 million. In the event the public-liability limit
stated above is insufficient, the Price-Anderson Act provides for
Congress to enact further revenue-raising measures to pay claims,
which could include an additional assessment on all licensed
reactor operators.
Insurance coverage is provided for up to $2.75 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 through mutual insurance companies owned by utilities
with nuclear facilities. If losses at any of the nuclear facilities
covered by the risk-sharing arrangements were to exceed the
accumulated funds available from these insurance programs, SDG&E
could be assessed retrospective premium adjustments of up to $6
million.
CANADIAN GAS
SDG&E has long-term pipeline capacity commitments related to its
contracts for Canadian natural-gas supplies. Certain of these
supply contracts are in litigation, while others have been settled.
If the supply of Canadian natural gas to SDG&E is not resumed 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 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
three-month and nine-month periods ended September 30, 1998 and
1997 was equal to net income.
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 1997 Form 10-K.
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This Form 10-Q includes forward-looking statements within the
definition of Section 27A of the Securities Act of 1933 and Section
21E of the Securities Exchange Act of 1934. 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. These statements are necessarily based upon various
assumptions involving judgments with respect to the future
including, among others, national, regional and local economic,
competitive and regulatory conditions, technological developments,
inflation rates, interest rates, energy markets, weather
conditions, business and regulatory or legal decisions, 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.
BUSINESS COMBINATION
See Note 2 of the notes to consolidated financial statements.
LIQUIDITY AND CAPITAL RESOURCES
Utility operations continue to be a major source of liquidity.
Liquidity has been favorably impacted by the issuance of Rate
Reduction Bonds (see Note 3 of the notes to consolidated financial
statements). In addition, financing needs are met primarily through
issuances of short-term and long-term debt. These capital resources
are expected to remain available (see Note 3 of the notes to
consolidated financial statements concerning Proposition 9, the
passage of which could materially and adversely affect the
Company's ability to finance its activities). Cash requirements
include utility capital expenditures, and repayments and
retirements of long-term debt. Major changes in cash flows not
described elsewhere are described below. Cash and cash equivalents
at September 30, 1998 are available for investment in new energy-
related domestic and international projects, the retirement of
debt, and other corporate purposes.
OPERATING ACTIVITIES
The decrease in cash flows from operations is due to
undercollections for fuel, short-term purchased power and various
operating costs incurred as a result of the delay of the ISO/PX
startup, and undercollections of CTC charges, partially offset by
overcollections in the gas balancing accounts attributable to
decreasing natural-gas prices. In addition, fluctuations in cash
flows from operations result from electric-industry restructuring,
including the acceleration of depreciation of electric-generating
assets, offset by recovery of stranded costs via the competition
transition charge and the 10-percent rate reduction reflected in
customers' bills in 1998.
INVESTING ACTIVITIES
Capital expenditures are estimated to be $233 million for the full
year 1998 and will be financed primarily by internally-generated
funds. 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. Among
other things, the level of utility expenditures in the next few
years will depend heavily on the impacts of industry restructuring
and the sale of SDG&E's Encina and South Bay power plants and other
electric-generation assets, as well as the timing and extent of
expenditures to comply with air-quality emission reduction and
other environmental requirements (also see Note 3 of the notes to
consolidated financial statements concerning Proposition 9).
FINANCING ACTIVITIES
The increase in long-term debt repayments in 1998 is due to the
tender offer purchase of $147 million of first mortgage bonds and
repayment of $42 million of rate-reduction bonds. This, coupled
with the $32 million of variable-rate, taxable IDBs retired
previously and the $83 million of debt offset (for regulatory
purposes) by temporary assets, completes the anticipated debt-
related use of rate-reduction bond proceeds. SDG&E does not
anticipate the need for additional long-term or short-term debt
during the remainder of 1998.
RESULTS OF OPERATIONS
UTILITY OPERATIONS
The decreases in earnings in 1998 are primarily due to business
combination costs, partially offset by the favorable resolution of
income-tax matters and rewards reflecting SDG&E's performance under
the Gas Procurement Performance-Based Regulation (PBR) mechanism.
The table below compares SDG&E's throughput and revenues by
customer class for the nine-month periods ended September 30, 1998
and 1997.
Electric Sales
1998 1997
------------------ ----------------
Volumes Revenue Volumes Revenue
(Volumes in millions of Kwhrs, revenue in millions of dollars)
------- ------- ------- -------
Nine Months Ended September 30
Residential 4,766 $ 484 4,588 $ 512
Commercial 5,195 500 5,255 525
Industrial 2,496 190 2,699 207
Direct access 438 30 - -
Street lighting 64 6 62 5
Off-system sales 661 14 2,951 69
------------------ ----------------
Total in rates 13,620 1,224 15,555 1,318
Balancing accounts and other 230* (43)
----- -----
Total operating revenues $1,454 $1,275
===== =====
* See discussion below regarding electric
operating revenues.
Gas Sales, Transportation and Exchanges
Transportation
Gas Sales and Exchanges Total
------------------- ------------------ -------------------
Throughput Revenue Throughput Revenue Throughput Revenue
(Throughput in billion cubic feet, revenue in millions of dollars)
------------------- ------------------ -------------------
Nine Months Ended
September 30, 1998
Residential 26 $ 198 26 $ 198
Commercial/industrial 15 80 15 $ 13 30 93
Utility electric generation 45 93* 45 93*
Wholesale
------------------- ------------------ -------------------
Total in rates 86 $ 371 15 $ 13 101 384
Balancing accounts and other (100)
------
Total operating revenues $ 284
======
Nine Months Ended
September 30, 1997
Residential 23 $ 172 23 $ 172
Commercial/industrial 16 86 13 $ 14 29 100
Utility electric generation 40 117 40 117
------------------- ------------------ -------------------
Total in rates 79 $ 375 13 $ 14 92 389
Balancing accounts and other (111)
------
Total operating revenues $ 278
======
* Represents margin only
The increase in electric operating revenues for the nine-month
period ended September 30, 1998 compared to the corresponding
period in 1997 is primarily due to stranded costs that are being
recovered via the competition transition charge (CTC), and to
alternate costs incurred (including fuel and short-term purchased-
power) due to the delay from January 1 to March 31, 1998 in the
startup of operations of the California Power Exchange and
Independent System Operator. The alternate costs incurred as a
result of the delay have been deferred and did not impact 1998
earnings. Stranded costs being recovered include the January 1998
application of the $130-million balance in the Interim Transition
Cost Balancing Account at December 31, 1997.
Revenues from the ISO/PX reflect sales at market prices of energy
from SDG&E's power plants and from long-term purchased-power
contracts to the California Power Exchange and Independent System
Operator commencing April 1, 1998.
Purchased power from long-term contracts decreased for the three-
month and nine-month periods ended September 30 1998 compared to
the corresponding periods in 1997, primarily as a result of
purchases' from the ISO/PX replacing short-term energy sources.
Electric fuel expenses increased for the three-month and nine-month
periods ended September 30 1998 compared to the corresponding
periods in 1997, primarily due to increases in volumes resulting
from record power usage in August and September of 1998. SDG&E
reported an all-time record for electricity usage on August 31,
1998 of 3,960 MW.
Depreciation and decommissioning expense increased for the three-
month and nine-month periods ended September 30 1998 compared to
the corresponding periods in 1997 due to the recovery of stranded
costs via the CTC. The increases in depreciation and amortization
are offset by CTC revenue (see above).
Income tax expense decreased for the three-month and nine-month
periods ended September 30 1998 compared to the corresponding
periods in 1997 due to changes in the treatment and timing of the
recognition of certain items due to electric-industry
restructuring. This results in income taxes associated with certain
regulatory items being deferred rather than recorded as current tax
expense.
Nonoperating income increased for the three-month and nine-month
periods ended September 30 1998 compared to the corresponding
periods in 1997 primarily due to higher interest income from short-
term investments.
Interest expense related to long-term debt increased for the three-
month and nine-month periods ended September 30 1998 compared to
the corresponding periods in 1997, due to the rate reduction bonds
that were issued in December 1997, partly offset by the affects of
repayments.
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 is identifying all 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 is currently evaluating 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 is prioritizing so that 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 and the
company estimates that all critical systems will be Year 2000 Ready
by June 30, 1999. The Company defines "Year 2000 Ready" as suitable
for continued use into the year 2000 with no significant
operational problems.
Critical IT and non-IT applications have been inventoried and
assessed for Year 2000 Readiness, and detailed plans are in place
for required system modifications or replacements. Remediation and
testing activities are well underway with approximately 58 percent
of the systems currently Year 2000 Ready and are expected to be 100
percent by June 30, 1999. Inventory, assessment and testing
activities for embedded systems are well underway with
approximately 38 percent of the systems currently Year 2000 Ready.
Inventory and assessment for all Company systems are in progress
and expected to be completed by December 31, 1998.
Sempra Energy's current schedule for Year 2000 testing, readiness
and development of contingency plans is subject to change depending
upon the remediation and testing phases of the Company's compliance
effort and upon developments that may arise as the Company
continues to assess its computer-based systems and operations. In
addition, 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.
The Costs to Address the Company's Year 2000 Issues
Sempra Energy's budget for the Year 2000 program is $48 million, of
which $33 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 natural gas or electrical 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 is in the process of contacting 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 non-IT systems.
The Company's Contingency Plans
Sempra Energy's contingency plans for Year-2000-related
interruptions are being incorporated in the Company's existing
overall emergency preparedness plans. To the extent appropriate,
such plans will include emergency backup and recovery procedures,
remediation of existing systems parallel with installation of new
systems, replacing electronic applications with manual processes,
identification of alternate suppliers and increasing inventory
levels. The Company expects these contingency plans to be completed
by the end of the second quarter in 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
California Public Utilities Commission's Industry Restructuring
See discussion of industry restructuring, and particularly the
discussion of Proposition 9, in Note 3 of the notes to consolidated
financial statements.
Auction Of Electric Generation Assets
In November 1997 SDG&E announced a plan to auction its power plants
and other electric-generation assets, enabling it to continue to
concentrate on the transmission and distribution of electricity and
natural gas in a competitive marketplace. This is described in Note
3 of the notes to consolidated financial statements. In addition,
the March 1998 CPUC decision approving the Enova/PE business
combination requires, among other things, the divestiture by SDG&E
of its gas-fired generation units. Further, in March 1998, Enova
and PE reached an agreement with the U.S. Department of Justice
(DOJ) to gain clearance for the business combination under the
Hart-Scott-Rodino Antitrust Act. Under such agreement, Enova
committed to follow through on its plan to divest SDG&E's fossil-
fuel power plants, and Sempra is required to obtain DOJ's approval
prior to acquiring or controlling any existing California
generation facilities in excess of 500 megawatts. The plan includes
the divestiture of SDG&E's fossil plants - the Encina (Carlsbad,
California) and South Bay (Chula Vista, California) plants. The
proceeds from the sales will be applied directly to SDG&E's
transition costs. The fossil-fuel assets auction is being separated
from the auction of SONGS and the purchased-power contracts. In
October 1998 the CPUC issued a draft decision approving the
commencement of the fossil-fuel assets auction. SDG&E expects the
sale of its fossil plants to be completed in the first quarter of
1999.
Performance-Based Regulation (PBR)
To promote efficient operations and improved productivity and to
move away from reasonableness reviews and disallowances, the CPUC
has been encouraging 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 allow future income
potential to be tied to achieving or exceeding specific performance
and productivity measures, rather than relying solely on expanding
utility rate base in a market where the company already has a
highly developed infrastructure.
SDG&E continues to participate in a PBR process for base rates for
its electric and natural-gas distribution business. In conjunction
therewith, SDG&E is currently involved in a Cost of Service rate
proceeding, with revised rates expected to be effective January 1,
1999. SDG&E's application requests an increase in revenue
requirements for electric-distribution and natural-gas operations.
The electric distribution increase does not affect rates and,
therefore, if approved, reduces the amount available for transition
cost recovery. In August 1998 a signed settlement agreement among
SDG&E, the ORA and the Utility Consumers' Action Network (UCAN) was
submitted to the CPUC requesting a combined increase of $12 million
(an electric distribution increase of $18 million and a natural-gas
decrease of $6 million). A CPUC decision is expected by year end
1998.
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. SDG&E's electric and natural-gas
distribution operations are authorized to earn a rate of return on
common equity of 11.6 percent and a rate of return on rate base of
9.35 percent, unchanged from 1997. In addition, the authorized
rates of return on nuclear and non-nuclear generating assets are
7.14 percent and 6.75 percent, respectively. However, electric
industry restructuring is changing the method of calculating
SDG&E's annual cost of capital. In May 1998 SDG&E filed with the
CPUC its unbundled Cost of Capital application for 1999 rates. The
application seeks approval to establish new, separate rates of
return for SDG&E's electric-distribution and natural-gas
businesses. The application proposes a 12.00% ROE, which would
produce an overall ROR of 9.33%. The ORA, UCAN and other
intervenors have filed testimony recommending significantly lower
RORs. The ORA is recommending an electric ROR of 7.68% and a gas
ROR of 8.01%. A CPUC decision is expected by early 1999.
Biennial Cost Allocation Proceeding (BCAP)
In October 1998 SDG&E filed its 1999 BCAP application requesting
that new rates become effective August 1, 1999 and remain in effect
through December 31, 2002. The application seeks an overall
decrease in gas rate revenues of $9 million.
Demand Side Management (DSM) Programs
In May 1998 SDG&E filed an application for 1997 shareholder rewards
totaling $4 million for its DSM programs. The rewards will be
collected and recorded in earnings over ten years and are subject
to CPUC approval. The revenue requirement increase is effective on
January 1, 1999, but, due to the rate cap, there will be no rate
increase. If, during the industry-restructuring transition period,
SDG&E is able to recover its transition costs and has revenue
available under the rate cap, SDG&E will be able to recover these
DSM earnings. SDG&E's earnings potential from DSM programs will be
reduced when the transition to the competitive markets is complete.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Other than as discussed in SDG&E's Quarterly Reports on Form 10-Q
for the three-month periods ended March 31 and June 30, 1998, there
have been no significant subsequent developments in litigation
proceedings that were outstanding at December 31, 1997 and there
have been no significant new litigation proceedings since that
date.
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 as required under
SDG&E's August 1993 registration of 5,000,000 shares of
Preference Stock (Cumulative).
Exhibit 27 - Financial Data Schedules
27.1 Financial Data Schedule for the nine months ended
September 30, 1998.
(b) Reports on Form 8-K
A Current Report on Form 8-K filed on June 30, 1998 announced
the completion of the business combination between Enova
Corporation and Pacific Enterprises, and the related changes
in control.
A Current Report on Form 8-K filed on July 15, 1998 discussed
the Voter Initiative which qualified for the November 1998
ballot (seeking to amend or repeal California electric
industry restructuring legislation in various respects) and
disclosed the potential impact on SDG&E.
A Current Report on Form 8-K filed on July 27, 1998 discussed
the California Supreme Court denial of the petition which
sought to overturn the Third District Court of Appeal's
denial to remove the Voter Initiative from the November 1998
ballot.
SIGNATURE
Pursuant to the requirement of the Securities Exchange Act of 1934,
SDG&E has duly caused this quarterly report to be signed on its
behalf by the undersigned thereunto duly authorized.
SAN DIEGO GAS & ELECTRIC COMPANY
(Registrant)
Date: October 30, 1998 By: /s/ E.A. Guiles
-----------------------------
E.A. Guiles
President