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 March 31, 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
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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)
(Dollars in millions)
Three Months Ended
March 31,
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1999 1998
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Operating Revenues:
Electric $360 $497
Natural gas 101 109
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Total operating revenues 461 606
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Operating Expenses:
Purchased power - net 66 96
Electric fuel 35 31
Natural gas purchased for resale 47 52
Maintenance 27 21
Depreciation and decommissioning 67 199
Property and other taxes 13 11
General and administrative 46 45
Other 42 45
Income taxes 47 29
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Total 390 529
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Operating Income 71 77
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Other Income and (Deductions):
Allowance for equity funds used
during construction 1 1
Taxes on nonoperating income (7) (3)
Other - net 17 6
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Total 11 4
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Income Before Interest Charges 82 81
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Interest Charges:
Long-term debt 21 27
Short-term debt and other interest 4 3
Amortization of debt discount and
expense, less premium 2 1
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Total 27 31
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Net Income 55 50
Preferred Dividend Requirements 2 2
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Earnings Applicable to Common Shares $ 53 $ 48
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See notes to Consolidated Financial Statements.
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
Balance at
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March 31, December
31,
1999 1998
(Unaudited)
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ASSETS
Utility plant - at original cost $4,916 $4,903
Less accumulated depreciation and decommissioning (2,646) (2,603)
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Utility plant - net 2,270 2,300
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Nuclear decommissioning trust 495 494
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Current assets:
Cash and temporary investments 194 284
Accounts receivable 203 199
Due from affiliates 189 110
Inventories 67 77
Regulatory balancing accounts undercollected - net -- 9
Other 19 17
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Total current assets 672 696
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Deferred taxes recoverable in rates 188 194
Regulatory assets 526 511
Deferred charges and other assets 65 62
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Total $4,216 $4,257
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CAPITALIZATION AND LIABILITIES
Capitalization:
Common equity $1,177 $1,124
Preferred stock not subject to mandatory redemption 78 78
Preferred stock subject to mandatory redemption 25 25
Long-term debt 1,534 1,548
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Total capitalization 2,814 2,775
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Current liabilities:
Long-term debt due within one year 72 72
Accounts payable 114 165
Dividends payable 2 102
Interest accrued 12 9
Regulatory balancing accounts overcollected - net 69 --
Other 217 185
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Total current liabilities 486 533
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Customer advances for construction 41 41
Deferred income taxes - net 382 397
Deferred investment tax credits 80 89
Deferred credits and other liabilities 413 422
Commitments and contingent liabilities (Note 3)
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Total $4,216 $4,257
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See notes to Consolidated Financial Statements.
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS (Unaudited)
(Dollars in millions)
Three Months Ended
March 31,
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1999 1998
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Cash Flows from Operating Activities
Net income $ 55 $ 50
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and decommissioning 67 199
Allowance for equity funds used during construction (1) (1)
Deferred income taxes and investment tax credits (24) 69
Application of balancing accounts to stranded costs -- (86)
Other - net (31) (19)
Net change in other working capital components (7) (23)
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Net cash provided by operating activities 59 189
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Cash Flows from Investing Activities:
Utility construction expenditures (42) (41)
Proceeds from sale of assets 7 --
Contributions to decommissioning funds (5) (5)
Other - net 7 (1)
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Net cash used by investing activities (33) (47)
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Cash Flows from Financing Activities:
Dividends paid (102) (46)
Issuance of long-term debt 9 --
Payment on long-term debt (23) (20)
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Net cash used by financing activities (116) (66)
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Increase (decrease) in cash and temporary investments (90) 76
Cash and temporary investments, January 1 284 536
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Cash and temporary investments, March 31 $194 $ 612
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Supplemental Disclosure of Cash Flow Information:
Income tax payments (refunds) $ 70 $ (13)
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Interest payments, net of amounts capitalized $ 24 $ 25
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Dividend to parent of intercompany receivable $ -- $ 100
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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 or the Company), a subsidiary of Enova Corporation (Enova). Enova is a
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 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, which includes the Consolidated Financial Statements and notes
thereto, and the annual "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 has not resulted in a write-off of SDG&E's
generation assets, since the 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.)
2. BUSINESS COMBINATIONS
PE/Enova
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 Company's 1998 Annual Report.
Expenses incurred in connection with the business combination were $0.2
million, after tax, and $0.9 million, after tax, for the three-month periods
ended March 31, 1999 and 1998, respectively. These costs consisted primarily of
employee-related costs, and investment banking, legal, regulatory and
consulting fees.
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. If the
transaction is approved, holders of KN Energy common stock will receive 1.115
shares of Sempra Energy common stock or $25 in cash, or some combination
thereof, for each share of KN Energy common stock. In the aggregate, the cash
portion of the transaction will constitute not more than 30 percent of the
total consideration. The transaction will be treated as a purchase for
accounting purposes. On March 30, 1999, Sempra Energy was notified that the
U.S. Federal Trade Commission had granted the Company's request for early
clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as
amended, with respect to the proposed merger.
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. 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. 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 March 31, 1999 is $600 million, consisting of
$400 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).
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 March 31, 1999 of
$400 million ($300 million for SONGS and $100 million for the 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 an interim decision approving
the commencement of the fossil fuel assets' auction.
On December 11, 1998 contracts were executed for the sale of SDG&E's South Bay
Power Plant, Encina Power Plant and 17 combustion-turbine generators. In early
1999, the CPUC issued its final approvals of these transactions. 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 Encina Power Plant
and the combustion-turbine generators are being sold to a special-purpose
entity owned equally by Dynegy Power Corp. and NRG Energy, Inc. for $350
million. This transaction is expected to close by mid 1999. SDG&E will
continue to operate the facilities for the next two years.
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 could stay in
place until January 1, 2002. However, SDG&E recently filed with the CPUC for an
interim mechanism to deal with electric rates after the rate freeze ends,
noting the possibility that the SDG&E rate freeze could end in 1999. A
subsequent SDG&E filing requests expedited treatment from the CPUC to end the
rate freeze and to set interim rates effective July 1, 1999, as well as a
request for adoption of final rates. 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 by an additional five
percent to 15 percent, depending on the customer class, 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. Once the rate freeze is
lifted, except for the interim protection mechanism described below, customers
will no longer be protected from commodity price spikes. The request to end the
rate freeze is based on a projection of SDG&E's recovering all applicable
electric restructuring transition costs before July 1, 1999.
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
the rate freeze lifting. 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. An interim CPUC decision
is expected no later than June 24, 1999.
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 three of
the suppliers. One of the three is delivering natural gas under the terms of
the settlement agreement through 2003; the other two have ceased deliveries and
the contracts were terminated. The fourth supplier has ceased deliveries
pending legal resolution. 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 three-month periods ended
March 31, 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 three months ended March 31, 1999. See Note 3 concerning the sale of
SDG&E's power plants.
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Three months ended
March 31,
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(Dollars in millions) 1999 1998
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Revenues:
Transmission and distribution $ 258 $ 269
Electric generation 102 228
Natural gas 101 109
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Total $ 461 $ 606
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Segment Income:
Transmission and distribution $ 88 $ 72
Electric generation 9 10
Natural gas 21 24
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Total segment income 118 106
Interest expense (27) (31)
Income tax expense (54) (32)
Nonoperating income 18 7
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Net income $ 55 $ 50
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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 KN Energy proposed merger.
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. Cash requirements primarily 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 March 31,
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 payments on
behalf of affiliated companies and greater payments on accounts payable.
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.
CASH FLOWS FROM FINANCING ACTIVITIES
The increase in net cash used in financing activities was primarily due to an
increase in dividends paid on common stock during the three-month period ended
March 31, 1999, compared to the same period in 1998.
RESULTS OF OPERATIONS
The table below summarizes the components of electric and natural gas volumes
and revenues by customer class for the three months ended March 31, 1999 and
1998.
Electric Distribution
(Dollars in millions, volumes in millions of Kwhrs)
1999 1998
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Volumes Revenue Volumes Revenue
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Residential 1,685 $ 170 1,631 $ 167
Commercial 1,518 125 1,632 134
Industrial 489 31 814 48
Direct access 657 21 - -
Street and highway lighting 19 2 22 2
Off-system sales 26 - 595 13
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4,394 349 4,694 364
Balancing and other 11 133
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Total 4,394 $ 360 4,694 $ 497
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Gas Sales, Transportation & Exchange
(Dollars in millions, volumes in billion cubic feet)
Gas Sales Transportation & Exchange Total
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Throughput Revenue Throughput Revenue Throughput
Revenue
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1999:
Residential 15 $ 105 - $ - 15 $ 105
Commercial and industrial 7 34 4 4 11 38
Utility electric generation 12 5 - - 12 5
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34 $ 144 4 $ 4 38 148
Balancing accounts and other ( 47)
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Total $ 101
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1998:
Residential 13 $ 100 - $ - 13 $ 100
Commercial and industrial 6 33 5 5 11 38
Utility electric generation 10 2 - - 10 2
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29 $ 135 5 $ 5 34 140
Balancing accounts and other ( 31)
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Total $ 109
- ------------------------------------------------------------------------------------------
Electric revenues decreased 28 percent in 1999 primarily due to the January
1998 application to stranded cost recovery of the $130 million balance in the
Interim Transition Cost Balancing Account (ITCBA), which had been transferred
from the then-discontinued ECAC and ERAM balancing accounts at December 31,
1997. In addition, there was a decrease in retail 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 decreased 7 percent for the three-month period ended March
31, 1999 compared to the same period in 1998. The decrease was primarily 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 decreased 10 percent for the three-month period
ended March 31, 1999. The decrease was primarily due to the decrease in the
average cost 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 decreased 66 percent for the three-month
period ended March 31, 1999, compared to the same period in 1998 due to the
January 1998 application to stranded cost recovery of the ITCBA as discussed
above.
Operating income decreased 8 percent for the three-month period ended March 31,
1999, compared to the same period in 1998, primarily due to the decrease in
electric revenues discussed above.
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 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 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.
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 $40
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
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. These
contingency plans are well underway and the Company plans to be completed by
June 30, 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 below.
KN Energy Acquisition
See discussion of the KN Energy acquisition in Note 2 of the notes to
Consolidated Financial Statements.
Industry Restructuring
See discussion of industry restructuring in Note 3 of the notes to Consolidated
Financial Statements.
Electric-Generation Assets and Electric Rates
In November 1997 SDG&E adopted a plan to auction its power plants and other
electric-generation assets, so that it could continue to concentrate its
business on the transmission and distribution of electricity and natural gas as
California opens its electric-utility industry to competition. 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 required, among other things, the divestiture by SDG&E of its
fossil-fueled generation units. The proceeds from the sales will be applied
directly to SDG&E's transition costs.
As described in Note 3 of the notes to Consolidated Financial Statements, AB
1890 requires a 10-percent reduction of residential and small commercial
customers' rates beginning in January 1998, as well as a rate freeze for all
customers. The rate freeze could stay in place until January 1, 2002. However,
SDG&E recently filed with the CPUC for an interim mechanism to deal with
electric rates after the rate freeze ends, noting the possibility that the
SDG&E rate freeze could end in 1999. If approved, base electric rates (the
portion of the rate that SDG&E controls) will decrease by an additional five
percent to 15 percent, depending on the customer class, 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. Once the rate freeze is
lifted, except for the interim protection mechanism described in Note 3 of the
notes to Consolidated Financial Statements, customers will no longer be
protected from commodity price spikes.
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 and natural gas
distribution business. During early 1998 SDG&E filed an application with the
CPUC proposing a new distribution PBR mechanism since the base rate PBR
mechanism would terminate at the end of 1998. The results of SDG&E's 1999 Cost
of Service study form the basis for the new mechanism's starting-point rates.
In December 1998, the Cost of Service settlement agreement among SDG&E, ORA and
UCAN was approved by the CPUC, 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. Also in
January 1999, an administrative law judge's proposed decision was released on
the PBR design issues of SDG&E's distribution PBR application. The proposed
decision recommends a revenue-per-customer indexing mechanism rather than the
rate-indexing mechanism proposed by SDG&E. Revenue or base margin per customer
would be indexed based on inflation less an estimated productivity factor. The
proposed decision also recommends much tighter earnings sharing bands than
previously in effect for SDG&E. In March 1999, a CPUC commissioner issued an
alternate decision which, among other things, would approve the rate-indexing
proposal. On May 13, 1999 the CPUC adopted a decision incorporating 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 seeks to establish new, separate
rates of return for SDG&E's electric distribution and natural gas businesses.
The application proposes a 12.00 percent ROE, which would produce an overall
ROR of 9.33 percent. The ORA, UCAN and other intervenors have filed testimony
recommending significantly lower RORs. A final CPUC decision is expected by mid
1999.
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.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Except for the matters referred to in the Company's 1998 Annual Report or
referred to elsewhere in this Quarterly Report on Form 10-Q for the three
months ended March 31, 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 10 - Material Contracts - Compensation
10.1 Form of Sempra Energy Severance Pay Agreement
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 three months ended
March 31, 1999.
(b) Reports on Form 8-K
None.
SIGNATURE
Pursuant to the requirement of the Securities Exchange Act of 1934,
SDG&E has duly caused this quarterly report to be signed on its
behalf by the undersigned thereunto duly authorized.
SAN DIEGO GAS & ELECTRIC COMPANY
(Registrant)
Date: May 14, 1999 By: /s/ E.A. Guiles
-----------------------------
E.A. Guiles
President