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, 2000
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Commission file number 1-14201
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Sempra Energy
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(Exact name of registrant as specified in its charter)
California 33-0732627
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
101 Ash Street, San Diego, California 92101
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(Address of principal executive offices)
(Zip Code)
(619) 696-2034
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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 on October 31, 2000: 204,509,392
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PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS.
<TABLE>
SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED INCOME
Dollars in millions, except per share amounts
<CAPTION>
Three Months Ended
September 30,
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2000 1999
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<S> <C> <C>
Revenues and Other Income
California utility revenues
Natural gas $ 799 $ 618
Electric 645 437
Other operating revenues 366 166
Other income 48 33
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Total 1,858 1,254
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Expenses
Cost of natural gas distributed 382 203
Electric fuel and net purchased power 444 180
Operating expenses 609 440
Depreciation and amortization 142 140
Other taxes and franchise payments 47 40
Preferred dividends of subsidiaries 2 3
Trust preferred distributions by subsidiary 5 --
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Total 1,631 1,006
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Income Before Interest and Income Taxes 227 248
Interest 67 73
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Income Before Income Taxes 160 175
Income Taxes 50 67
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Net Income $ 110 $ 108
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Weighted-average number of shares outstanding (Basic)* 201,338 237,353
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Weighted-average number of shares outstanding (Diluted)* 201,497 237,794
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Net Income Per Share of Common Stock (Basic and Diluted) $0.55 $0.45
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Common Dividends Declared Per Share $0.25 $0.39
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*In thousands of shares
See notes to Consolidated Financial Statements.
</TABLE>
<TABLE>
SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED INCOME
Dollars in millions, except per share amounts
<CAPTION>
Nine Months Ended
September 30,
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2000 1999
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<S> <C> <C>
Revenues and Other Income
California utility revenues
Natural gas $2,336 $2,022
Electric 1,467 1,443
Other operating revenues 936 429
Other income 121 68
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Total 4,860 3,962
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Expenses
Cost of natural gas distributed 1,088 769
Electric fuel and net purchased power 841 391
Operating expenses 1,637 1,313
Depreciation and amortization 420 749
Franchise payments and other taxes 138 126
Preferred dividends of subsidiaries 8 9
Trust preferred distributions by subsidiary 11 --
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Total 4,143 3,357
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Income Before Interest and Income Taxes 717 605
Interest 216 185
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Income Before Income Taxes 501 420
Income Taxes 167 131
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Net Income $ 334 $ 289
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Weighted-average number of shares outstanding (Basic)* 210,303 237,192
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Weighted-average number of shares outstanding (Diluted)* 210,405 237,556
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Net Income Per Share of Common Stock (Basic and Diluted) $1.59 $1.22
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Common Dividends Declared Per Share $0.75 $1.17
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*In thousands of shares
See notes to Consolidated Financial Statements.
</TABLE>
<TABLE>
SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
Dollars in millions
<CAPTION>
Balance at
------------------------
September 30, December 31,
2000 1999
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<S> <C> <C>
ASSETS
Current assets
Cash and cash equivalents $ 378 $ 487
Accounts receivable 756 552
Income taxes receivable -- 144
Deferred income taxes 8 --
Energy trading assets 3,408 1,539
Inventories 195 147
Other 285 146
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Total current assets 5,030 3,015
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Investments and other assets
Regulatory assets 956 606
Nuclear decommissioning trusts 578 551
Investments 1,195 1,164
Other assets 471 460
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Total investments and other assets 3,200 2,781
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Property, plant and equipment
Property, plant and equipment 11,673 11,127
Less accumulated depreciation and amortization (6,101) (5,733)
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Total property, plant and equipment - net 5,572 5,394
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Total assets $13,802 $11,190
===========================
See notes to Consolidated Financial Statements.
</TABLE>
<TABLE>
SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
Dollars in millions
<CAPTION>
Balance at
------------------------
September 30, December 31,
2000 1999
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<S> <C> <C>
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term debt $ 303 $ 182
Accounts payable 941 546
Income taxes payable 123 --
Deferred income taxes -- 67
Energy trading liabilities 3,007 1,365
Dividends and interest payable 118 154
Regulatory balancing accounts - net 435 346
Customer refunds payable 254 --
Current portion of long-term debt 118 155
Other 480 421
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Total current liabilities 5,779 3,236
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Long-term debt 3,300 2,902
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Deferred credits and other liabilities
Customer advances for construction 62 72
Post-retirement benefits other than pensions 198 204
Deferred income taxes 679 615
Deferred investment tax credits 102 106
Deferred credits and other liabilities 800 865
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Total deferred credits and other liabilities 1,841 1,862
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Preferred stock of subsidiaries 204 204
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Mandatorily redeemable trust preferred securities 200 --
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Commitments and contingent liabilities (Note 3)
SHAREHOLDERS' EQUITY
Common stock 1,414 1,966
Retained earnings 1,117 1,101
Deferred compensation relating to ESOP (39) (42)
Accumulated other comprehensive income (14) (39)
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Total shareholders' equity 2,478 2,986
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Total liabilities and shareholders' equity $13,802 $11,190
===========================
See notes to Consolidated Financial Statements.
</TABLE>
<TABLE>
SEMPRA ENERGY
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
Dollars in millions
<CAPTION>
Nine Months Ended September 30,
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2000 1999
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<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 334 $ 289
Adjustments to reconcile net income to
net cash provided by operating activities
Depreciation and amortization 420 749
Customer refunds paid (378) --
Portion of depreciation arising from
sales of generating plants -- (295)
Application of balancing accounts to stranded costs -- (66)
Deferred income taxes and investment tax credits (7) (189)
Equity in (income) losses of unconsolidated subs and
joint ventures (42) 10
Non-cash rate reduction bond expense (revenue) 16 (50)
Other - net 9 (115)
Net changes in other working capital components 323 550
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Net cash provided by operating activities 675 883
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CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (492) (401)
Investment in Chilquinta Energia and Luz del Sur -- (528)
Net proceeds from sale of generating plants -- 466
Other (38) (121)
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Net cash used in investing activities (530) (584)
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CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends (195) (281)
Repurchase of common stock (725) --
Issuance of trust preferred securities 200 --
Issuance of long-term debt 512 176
Payments on long-term debt (158) (188)
Increase in short-term debt - net 121 42
Other (9) 2
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Net cash used in financing activities (254) (249)
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Increase (decrease) in Cash and Cash Equivalents (109) 50
Cash and Cash Equivalents, January 1 487 424
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Cash and Cash Equivalents, September 30 $ 378 $ 474
========================
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized $ 233 $ 242
========================
Income tax payments (refunds) - net $ (58) $ 168
========================
Real estate investments acquired $ -- $ 38
Cash paid -- (4)
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Liabilities assumed $ -- $ 34
========================
See notes to Consolidated Financial Statements.
</TABLE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. GENERAL
This Quarterly Report on Form 10-Q is that of Sempra Energy (the
Company), a California-based Fortune 500 energy services company.
Sempra Energy's principal subsidiaries are San Diego Gas & Electric
Company (SDG&E), Southern California Gas Company (SoCalGas)
(collectively referred to herein as the California utilities), Sempra
Energy Trading and Sempra Energy International. The financial
statements herein are the Consolidated Financial Statements of Sempra
Energy and its subsidiaries.
The accompanying Consolidated Financial Statements have been prepared
in accordance with the interim-period-reporting requirements of Form
10-Q. Results of operations for interim periods are not necessarily
indicative of results for the entire year. In the opinion of
management, the accompanying statements reflect all adjustments
necessary for a fair presentation. These adjustments are only of a
normal recurring nature. Certain changes in classification have been
made to prior presentations to conform to the current financial
statement presentation.
The Company's significant accounting policies are described in the
notes to Consolidated Financial Statements in the Company's 1999
Annual Report. The same accounting policies are followed for interim
reporting purposes.
Information in this Quarterly Report is unaudited and should be read
in conjunction with the Company's 1999 Annual Report.
As described in the notes to Consolidated Financial Statements in the
Company's 1999 Annual Report, the California utilities account for
the economic effects of regulation on utility operations (excluding
generation operations) in accordance with Statement of Financial
Accounting Standards No. 71, "Accounting for the Effects of Certain
Types of Regulation" (SFAS No. 71).
2. MAJOR FINANCIAL TRANSACTIONS
Common Stock Repurchase
On February 25, 2000, the Company completed a self tender offer,
purchasing 36.1 million shares of its outstanding common stock at $20
per share. The Company issued $500 million of long-term 7.95% notes
due 2010 and $200 million of 8.9% mandatorily redeemable trust
preferred securities to finance substantially all of the repurchase.
Additional Common Stock Repurchases Authorized
On March 9, 2000, the Company's Board of Directors authorized the
expenditure of up to $100 million to repurchase additional shares of
common stock from time to time in the open market or in privately
negotiated transactions. Authorization of the stock repurchase does
not obligate the Company to acquire any particular amount of common
stock or within any specific timeframe. Through November 12, 2000, the
Company acquired 162,000 shares under this authorization (all in July
2000).
Common Dividends
Dividends currently are paid quarterly to shareholders. The payment
of future dividends is within the discretion of the board of
directors. In January 2000 the Company reduced the quarterly dividend
on shares of its common stock to $0.25 per share ($1.00 annualized
rate) from its previous level of $0.39 per share ($1.56 annualized
rate) commencing with the dividend payable in the second quarter of
2000.
Investments in South America
On June 10, 1999, Sempra Energy International (SEI) and Public
Service Enterprise Group (PSEG) purchased (on a 50/50 basis)
Chilquinta Energia S.A. (Energia), primarily a Chilean electric
distribution company, for $840 million. SEI invested $260 million for
the purchase of stock and refinanced $160 million of Energia's
outstanding long-term debt. In September 1999, SEI and PSEG completed
their acquisition of 47.5 percent of the outstanding shares of Luz
del Sur S.A.A., a Peruvian electric distribution company. SEI's share
of the transaction was $108 million in cash. This acquisition,
combined with the 37 percent already owned through Energia, increased
the companies' total joint ownership to 84.5 percent of Luz del Sur
S.A.A.
On October 12, 2000 the Company completed the purchase, for
approximately $140 million, of an additional 21.5-percent interest in
two Argentine natural gas utility holding companies (Sodigas Pampeana
S.A. and Sodigas Sur S.A.). The transaction increased the Company's
investment in the two Argentine companies from 21.5 percent to 43
percent.
KN Energy
On June 21, 1999, Sempra Energy and KN Energy, Inc. (KN) announced
that they had agreed to terminate an agreement for the acquisition of
KN by Sempra Energy. Expenses incurred in connection with the
proposed acquisition were $11 million, after tax, for the nine-month
period ended September 30, 1999. There were no such expenses incurred
in the three-month period ended September 30, 1999.
3. MATERIAL CONTINGENCIES
ELECTRIC INDUSTRY RESTRUCTURING
Background
In September 1996, the State of California enacted a law
restructuring California's electric utility industry (AB 1890). The
legislation adopted the December 1995 policy decision of the
California Public Utility Commission (CPUC) that was intended to
restructure 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.
California's investor-owned utilities (IOUs) are obligated to sell
their power supply, including owned generation and purchased-power
contracts, to the PX. The IOUs may purchase from the PX or any other
"qualified exchange" the power that they distribute or may utilize
any of the available tools (i.e., block forward market and bilateral
contracts as described below) to make these purchases. A "qualified
exchange" is defined as one that provides continuous trading in
either a bid/ask or second price auction type market, equal
nondiscriminatory access and a mechanism for timely, anonymous price
transparency. An Independent System Operator (ISO) schedules power
transactions and access to the transmission system.
The local utility continues to provide distribution service
regardless of the source from which the customer chooses to purchase
electricity. Purchases by SDG&E from the PX/ISO are included in
electric fuel and net purchased power expenses, and revenues from
sales to the PX/ISO have been netted therein on the Statements of
Consolidated Income. Revenues from the PX/ISO reflect sales to the
PX/ISO at market prices of energy from SDG&E's power plants and from
its long-term purchased-power contracts.
As discussed in the notes to Consolidated Financial Statements
contained in the Company's 1999 Annual Report, AB 1890 allowed the
IOUs a reasonable opportunity to recover their stranded costs via a
competition transition charge (CTC) to customers through December 31,
2001. In June 1999, SDG&E completed the recovery of its stranded
costs, other than the future above-market portion of qualifying
facilities and other purchased-power contracts that were in effect at
December 31, 1995, and San Onofre Nuclear Generating Station (SONGS)
costs as described below, both of which will continue to be collected
in rates. Recovery of the other stranded costs was effected by, among
other things, the sale of SDG&E's South Bay and Encina fossil power
plants and combustion turbines during the quarter ended June 30,
1999. SDG&E will operate and maintain both plants for the new owners
until April 2001 and May 2001, respectively.
SDG&E's stranded costs included the cost of SONGS as of December 31,
1995. SDG&E retains its 20-percent ownership interest in SONGS. SONGS
costs subsequent to December 31, 1995, are recoverable only from the
sales to the PX of power produced from SONGS, at rates previously
fixed by the CPUC through December 31, 2003 and at market rates
thereafter. Subsequent to December 31, 2003, any benefits associated
with the operation of SONGS would be shared equally with customers.
These benefits may be defined as one of the following: profits from
continued operations (shareholders would bear any losses), any gain
on plant sale, a third party appraisal or some other valuation
approach. SDG&E must notify the CPUC no later than July 1, 2002 as to
its preferred valuation approach. SDG&E's request for CPUC approval
to auction its interest in SONGS has been withdrawn, with the CPUC
reserving the right to approve any future ratemaking or divestiture
request.
AB 1890 also required a 10-percent reduction of residential and small
commercial customers' rates, beginning in January 1998, and provided
for the issuance of rate-reduction bonds by an agency of the State of
California to enable the IOUs to achieve this rate reduction. In
December 1997, $658 million of rate-reduction bonds were issued on
SDG&E's behalf at an average interest rate of 6.26 percent. These
bonds are being repaid over 10 years by SDG&E's residential and small
commercial customers via a non-bypassable charge on their electric
bills. In 1997, SDG&E formed a subsidiary, SDG&E Funding LLC, to
facilitate the issuance of the bonds. In exchange for the bond
proceeds, SDG&E sold to SDG&E Funding LLC all of its rights to the
revenue streams collected from such customers related to the non-
bypassable charge. Consequently, the transaction is structured to
cause such revenue streams not to be the property of SDG&E nor to be
available to satisfy any claims of SDG&E's creditors.
The sizes of the rate-reduction bond issuances were set so as to make
the IOUs neutral as to the 10-percent rate reduction, and were based
on a four-year period to recover stranded costs. Because SDG&E
recovered its stranded costs in only 18 months (due to the greater-
than-anticipated plant-sale proceeds), the bond sale proceeds were
greater than needed. Accordingly, during the third quarter of 2000
SDG&E returned to its customers, via a combination of cash refunds
and billing credits, $388 million of surplus bond proceeds in
accordance with a June 8, 2000 CPUC decision.
AB 1890 also included a rate freeze for all IOU customers. The rate
freeze was to have stayed in place until January 1, 2002. However, in
connection with completion of its stranded cost recovery, SDG&E filed
with the CPUC and received approval to reduce base rates (the non-
commodity portion of rates) to all electric customers, effective July
1, 1999. The portion of the electric rate representing the commodity
cost was to be passed through to customers with no markup and would
fluctuate with the price of electricity from the ISO/PX.
Recent Developments Concerning Commodity Prices
Recently, a number of factors, including recent supply/demand
conditions, resulted in abnormally high commodity prices, which
caused SDG&E's monthly customer bills to be substantially higher than
normal. Responses to these high rates have resulted in a temporary
ceiling on the commodity portion of electric rates, as described
below.
On June 28, 2000 the ISO Board of Governors approved the reduction of
the wholesale price cap for electricity in California from $750 per
megawatt hour (MWh) to $500 per MWh. Subsequently, on August 1, 2000,
it approved an additional reduction of the price cap from $500 per
MWh to $250 per MWh. On November 1, 2000 the FERC reported its
findings from its formal investigation of the electric rates and
structure of the ISO/PX, as well as of market-based sellers in the
California market. The investigation found no specific abuse of
market power by individual generators and determined that constraints
within the market structure, such as hedging restrictions imposed by
the CPUC, and a long-term shortage of power in the state resulted in
the high electric commodity prices. Federal regulators proposed
several remedies to fix California's flawed market, but stated that
past profits from generators and traders could not be ordered
refunded to customers. The FERC did state that the high short-term
energy rates during the summer of 2000 were "unjust and unreasonable"
and left the door open to future customer refunds should specific
instances of market abuses be uncovered. The report proposes a
temporary modification (for the next two years) of how prices are set
in the PX, so that bids higher than $150 per MWh cannot set the
market clearing price paid to all participants. Companies can receive
prices higher than the $150 per MWh "soft cap," but only if they can
demonstrate they are justified and fulfill extensive reporting
requirements. In addition, the FERC proposes to allow the California
IOUs to buy and sell power outside the PX to afford the IOUs better
deals, to replace the ISO/PX stakeholder governing boards with
independent boards, and to require market buyers to schedule 95
percent of their transactions in the day-ahead markets to reduce the
over-reliance on the real-time market to meet supply. The FERC
ordered that the $250 per MWh ISO/PX price cap, as described above,
will remain in place until the new FERC pricing mechanism is
finalized. The FERC proposal will be open to industry and public
comment before implementation. A final order is expected by the end
of 2000.
On August 3, 2000 the CPUC approved a proposal by SDG&E to accelerate
the refund to its electric customers of $100 million of certain
balancing account overcollections to partially offset the high
monthly bills. This refund is in addition to the $388 million of
surplus bond proceeds (see above) returned to residential and small
commercial customers.
Also on August 3, 2000 the CPUC granted SDG&E expanded authority to
participate in the PX's block forward market which allows SDG&E to
utilize futures contracts to hedge electricity prices and purchase
electricity for extended periods at fixed prices. In addition, it
ordered SDG&E not to disconnect the service of any customers who do
not pay their high bills through October 31, 2000. SDG&E recently
requested the CPUC to extend this policy through December 31, 2000
for customer classes covered by AB 265 (see below). The CPUC also
directed SDG&E to expand its level pay plan to all customers who
request it. This allows a customer to level out payments over a year.
Subsequently, in September 2000 the California governor signed two
bills (AB 265 and AB 970) passed by the California Legislature with
respect to electricity pricing and power plant construction. AB 265
contains a commodity rate ceiling and stabilization plan that imposes
a ceiling on the commodity rate for electricity that SDG&E can pass on
to residential and small business customers on a current basis. The
ceiling is retroactive to June 1, 2000, extends through December 31,
2002, and may be extended through December 31, 2003 if the CPUC
determines that it is in the public interest. AB 265 also requires the
CPUC to initiate a proceeding to assess alternatives for recovering
undercollections (the cost of electricity purchased by SDG&E that
cannot be passed on to customers on a current basis) resulting from
the commodity rate ceiling. The legislation provides for the recovery
of such undercollections (in excess of net revenues associated with
sales of energy from utility-owned or managed generation assets)
resulting from the reasonable and prudent costs of procuring the
commodity. It also directs the CPUC to examine the prudence and
reasonableness of SDG&E's procurement of wholesale energy on behalf of
its customers. In October 2000, the CPUC commenced a thorough review
of SDG&E's energy procurement practices for the period July 1999
through August 2000. A decision is expected in the third quarter of
2001. AB 970 speeds up the licensing and review of new power plants to
increase supply and meet growing demand. The bill also encourages
energy conservation, establishing new programs to reduce demand.
To implement AB 265, on September 7, 2000, the CPUC unanimously
approved a cap on electric rates. The ceiling on the electricity
commodity portion of customers' bills is set at 6.5 cents/kWh. This
is a "floating cap" that can float downward as prices decrease, but
cannot exceed actual commodity costs without the permission of the
CPUC. An interest-bearing balancing account would be established to
record related undercollections resulting from the commodity rate
ceiling with undercollected amounts to be recovered in a manner (not
specified in the decision) intended to make SDG&E whole for the
reasonable and prudent costs of procuring the electric commodity.
This balancing account is classified as a regulatory asset on the
Consolidated Balance Sheets due to its long-term nature. The
undercollection is $254 million at September 30, 2000, is estimated
to amount to $375 million by December 31, 2000, and grow to $550
million and $750 million at December 31, 2001 and 2002, respectively,
based on NYMEX Palo Verde futures prices. If the CPUC later adopts
the option granted it by the legislation to extend the ceiling for an
additional year, the balance at December 31, 2003 is estimated to be
$950 million. These amounts are higher than those recently discussed
by the Company due to balancing-account treatment of contracts with
Qualified Facilities and changes in NYMEX Palo Verde futures prices.
These amounts could increase or decrease significantly due to
variations between the forward prices used in the estimation process
and the actual costs incurred, and could decrease to the extent that
regulators permit overcollections in other balancing accounts to be
applied against this undercollection and/or take actions to correct
the California market, such as by adopting the $150 per MWh "soft
cap" recently proposed by the FERC. In October 2000 SDG&E requested
that the CPUC freeze the commodity rate at 6.5 cents/kWh instead of
capping the rate at that amount. Under a rate freeze, in those months
when the electric commodity cost is less than 6.5 cents/kWh, SDG&E
would be able to collect more revenue than its current cost of
electricity to offset the undercollection incurred when wholesale
power prices are above that rate.
Customers covered under the commodity rate ceiling plan include
residential, small-commercial and lighting customers, as well as
general acute-care hospitals, K-12 public and private schools and
other small usage customers. Based on 6.5 cents/kWh, the average
customer's electric bill is expected to be $53 a month for
residential customers and $220 a month for small-commercial
customers. Because the legislation is retroactive to June 1, 2000,
customers will receive credits on their bills for the amounts paid in
excess of the 6.5-cents cap from June through August of 2000. During
the summer of 2000, the average electric commodity cost was 13.95
cents/kWh (compared to 4.34 cents/kWh the prior summer). The
legislation also charges the CPUC with setting up a voluntary program
for large-commercial, agricultural and industrial customers that
would allow such customers the option of the 6.5-cents cap during the
year with a true-up at year end. The CPUC is in the initial stages of
designing a program to implement this part of the legislation.
On September 21, 2000, the CPUC granted SDG&E authority to purchase
up to 1,900 megawatts of power through bilateral contracts. These
contracts are transactions between SDG&E and a third-party power
supplier (other than the PX) that require the third party to provide
a specific amount of power at a specific future time and price.
Subsequent to September 30, 2000, SDG&E began signing multi-year
contracts for fixed-price power. The current intention is not to
contract for a large portion of its requirements.
A third bill (AB 1165) addressed utility revenue shortfalls from the
commodity rate ceiling by allocating $150 million of state funds to
provide most customers with rate relief from the high cost of
wholesale energy incurred during the commodity rate ceiling period.
The bill was vetoed by the California governor on September 29, 2000.
The FERC continues to investigate the electric bulk power markets and
California's attorney general is investigating whether there has been
market manipulation. Ongoing investigations are also in process by
the CPUC and the U.S. Attorney General's office. Various proposals
have included application of any refunds from power suppliers,
arising from such investigations, to help defray any billings
deferred as a result of adoption of the commodity price ceiling. The
California Joint Legislative Audit Committee recently approved an
audit of the PX/ISO.
AB 265 and related CPUC decisions to respond to the high electricity
rates will adversely affect the timing of revenue collections by
SDG&E and related cash flows. However, the legislation and related
decisions affirm SDG&E's right to recover all of its prudently
incurred costs of purchasing electricity for its customers. As noted
above, a decision is expected in the third quarter of 2001 on the
CPUC's review of SDG&E's recent energy procurement practices. During
the third quarter of 2000, SDG&E recorded an aftertax charge of $30
million related to the recent legislative and regulatory actions
associated with power acquisition costs. However, SDG&E will
vigorously oppose, through regulatory proceedings and otherwise, any
proposal that does not assure the ultimate collectibility of its full
costs of providing electric service.
California regulatory uncertainties have led Moody's Investors
Service to change its rating outlook on SDG&E's securities from
positive to negative. Moody's also changed the rating outlook on
Sempra Energy's securities from stable to negative. Fitch IBCA,
another major credit rating agency, also lowered its outlook on
SDG&E's securities from stable to negative due to the uncertainty
over the recovery of high wholesale energy prices not included in
customer bills. Another major credit rating agency, Standard &
Poor's, did not change the Company's rating outlook and believes the
Company's long-term prognosis to be stable. Although some of the
rating outlooks have changed, the Company's actual credit ratings
have not. As of November 7, 2000, the Company's credit ratings are as
follows:
S&P Moody's Fitch IBCA
-------------------------------------
Sempra Energy
Unsecured debt A A2 A
Commercial paper A-1 P-1 D-1
SDG&E
Secured debt AA- Aa3 AA
Unsecured debt A+ A1 AA-
Preferred stock A+ a1 A+
Commercial paper A1+ P1 D1+
The ratings and outlook can affect the Company's ability to finance
other projects and can increase its incremental costs of borrowing.
Other
On December 20, 1999, the Federal Energy Regulatory Commission (FERC)
issued "Order 2000". As described in the Company's 1999 Annual
Report, the rule discusses the formation of Regional Transmission
Organizations (RTO), grid management, transmission pricing reform and
related matters. The identification of RTO regions and formation of
the RTOs are subject to a collaborative process. The impact of Order
2000 on SDG&E depends on the results of this process and other
implementation issues.
On March 31, 2000, the ISO filed with the FERC a transmission access
charge (TAC) which separates the transmission systems in California
into two groups (high and low voltage) as the basis for allocating
the costs of maintaining the transmission systems among the various
transmission owners. SDG&E opposed the TAC and filed a protest with
the FERC in April 2000. In June 2000, the FERC approved the TAC
subject to refund and settlement agreement. Settlement efforts among
all parties are ongoing. Resolution is not expected before 2001. The
TAC will go into effect in January 2001. The estimated impact on
SDG&E is to increase transmission costs by $1 million annually. In
addition, once the TAC is in effect, Internal Revenue Service (IRS)
regulations may require SDG&E to refinance the industrial development
bonds that support its transmission facilities, the principal amount
of which totals $168 million. If this occurs, SDG&E's estimated
annual pretax cost of replacing the bonds with debt, the interest on
which is taxable to the holders, would be $4 million, most of which
would be recovered in rates. SDG&E recently submitted a request for a
private letter ruling from the IRS. In addition, pending federal
legislation related to municipalities seeking to preserve tax-exempt
status could resolve this issue.
Thus far, the CPUC's electric-industry restructuring 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 2000, the CPUC will consider whether any changes
should be made in electric distribution regulation. A CPUC staff
report on this issue was submitted to the CPUC in July 2000, with
dissenting opinions recommending against changing electric
distribution regulation at this time due to the current state of
electric-industry restructuring.
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 July 1999, after hearings, the CPUC issued a decision stating
which natural gas regulatory changes it found most promising,
encouraging parties to submit settlements addressing those changes,
and providing for further hearings if necessary.
In October 1999, the State of California enacted a law (AB 1421)
which requires that natural gas utilities provide "bundled basic gas
service" (including transmission, storage, distribution, purchasing,
revenue-cycle services and after-meter services) to all core
customers, unless the customer chooses to purchase natural gas from a
non-utility provider. The law prohibits the CPUC from unbundling most
distribution-related natural gas services (including meter reading)
and after-meter services (including leak investigation, inspecting
customer piping and appliances, pilot relighting and carbon monoxide
investigation) for core customers. The objective is to preserve both
customer safety and customer choice.
Between late 1999 and April 2000, several conflicting settlement
proposals were filed by various groups of parties that addressed the
changes the CPUC found promising in July 1999. Hearings were held in
May and June of 2000, and a CPUC decision is expected in 2001. The
principal issues in dispute include: whether firm, tradable rights to
capacity on SoCalGas' major gas transmission lines should be created,
with SoCalGas at risk for market demand for the recovery of the cost
of these facilities; the extent to which SoCalGas' storage services
should be further unbundled and SoCalGas be put at greater risk for
recovery of storage costs; the manner in which interstate pipeline
capacity held by SoCalGas to serve core markets should be allocated
to core customers who purchase gas from energy service providers
other than SoCalGas; and the recovery of the utilities' costs to
implement whatever regulatory changes are adopted. Additional
proposals include improving the access of energy service providers to
sell natural gas supply to core customers of SoCalGas and SDG&E.
Consistent with Sempra Energy's corporate policies favoring the
unbundling of commodity and nonessential services, the California
utilities are supporting changes that they believe will provide
greater customer choice in utility services and greater access to gas
supply service from energy service providers in the core market.
However, a coalition of gas-fired electric generators and consumer
groups has also proposed the CPUC require SoCalGas to absorb 25
percent of the above-market cost of some capacity SoCalGas has
contracted for on interstate pipelines. SoCalGas is actively opposing
this proposal, contending that regulatory changes developed after the
capacity was committed should not be considered in evaluating the
propriety of the commitment.
Certain parties contend that the restructuring process is an
appropriate venue for addressing whether SoCalGas should refund
retroactively to September 1999 the cost in rates of ownership and
operation of one SoCalGas storage field. SoCalGas is also actively
opposing this proposal and the propriety of this venue for its
resolution.
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 $9.3 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 $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 these coverages are 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 and six weeks, after a waiting period of 12 weeks.
Coverage is provided through a mutual insurance company 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 $5
million.
QUASI-REORGANIZATION
In 1993, PE divested its merchandising operations and most of its oil
and gas exploration and production business. In connection with the
divestitures, PE effected a quasi-reorganization for financial
reporting purposes effective December 31, 1992. Unitary tax issues
and certain other liabilities established in connection with the
quasi-reorganization were favorably resolved in November 1999. Excess
reserves of $80 million resulting from the favorable resolution of
these issues were added to shareholders' equity at that time. Other
liabilities established in connection with discontinued operations
and the quasi-reorganization will be resolved in future years.
Management believes the provisions for these matters are adequate.
4. COMPREHENSIVE INCOME
The following is a reconciliation of net income to comprehensive
income.
Three-month Nine-month
periods ended periods ended
September 30, September 30,
(Dollars in millions) 2000 1999 2000 1999
--------------------------------------------------------------------
Net income $ 110 $ 108 $ 334 $ 289
Change in unrealized gain
on marketable securities (14) -- 7 --
Foreign currency adjustments 7 (28) 16 (28)
Minimum pension liability
adjustments 2 -- 3 --
------------------------------------
Comprehensive income $ 105 $ 80 $ 360 $ 261
--------------------------------------------------------------------
5. SEGMENT INFORMATION
The Company is primarily an energy-services company and has three
reportable segments comprised of SDG&E, SoCalGas and Sempra Energy
Trading (SET). The two utilities operate in essentially separate
service territories under separate regulatory frameworks and rate
structures set by the CPUC. As described in the notes to Consolidated
Financial Statements in the Company's 1999 Annual Report, SDG&E
provides electric and natural gas service to San Diego County and
electric service to southern Orange County. SoCalGas is a natural gas
distribution utility, serving customers throughout most of southern
California and part of central California. SET is based in Stamford,
Connecticut and is engaged in the wholesale trading and marketing of
natural gas, power and petroleum in the U.S. and in other countries.
The accounting policies of the segments are the same as those
described in the notes to Consolidated Financial Statements in the
Company's 1999 Annual Report, and segment performance is evaluated by
management based on reported net income. Intersegment transactions
are generally recorded in the same manner as sales or transactions
with third parties. Utility transactions are based primarily on rates
set by the CPUC and FERC. There were no significant changes in
segment assets during the nine-month period ended September 30, 2000
except for the increase in trading assets, as shown on the
Consolidated Balance Sheets.
---------------------------------------------------------------------
Three-month periods Nine-month periods
ended September 30, ended September 30,
----------------------------------------
(Dollars in millions) 2000 1999 2000 1999
---------------------------------------------------------------------
Operating Revenues:
San Diego Gas & Electric $ 731 $ 520 $1,776 $1,720
Southern California Gas 722 562 2,050 1,793
Sempra Energy Trading 213 116 605 298
Intersegment revenues (10) (22) (24) (45)
Other 154 45 332 128
----------------------------------------
Total $1,810 $1,221 $4,739 $3,894
---------------------------------------------------------------------
Net Income:
San Diego Gas & Electric* $ 15 $ 59 $ 107 $ 159
Southern California Gas* 53 48 150 141
Sempra Energy Trading 45 5 102 9
Other (3) (4) (25) (20)
----------------------------------------
Total $ 110 $ 108 $ 334 $ 289
---------------------------------------------------------------------
* after preferred dividends
6. SEMPRA ENERGY GLOBAL ENTERPRISES (formerly Sempra Energy Holdings)
In September 2000, Sempra Energy Global Enterprises (Global), a
wholly owned subsidiary of Sempra Energy, replaced a $500 million
credit agreement with a $1.2 billion credit agreement that expires in
September 2001 and is available to support commercial paper.
Borrowings under the agreement would bear interest at various rates
based on market rates and Sempra Energy's credit rating. At September
30, 2000, Global had no outstanding borrowings under the credit
agreement and $303 million in commercial paper obligations.
Borrowings and the commercial paper are guaranteed by Sempra Energy.
On May 5, 1999, Global and certain affiliates filed a shelf
registration for the issuance of up to $1.1 billion of securities,
guaranteed by Sempra Energy, to be offered on a delayed or continuous
basis pursuant to Rule 415 under the Securities Act of 1933. At
September 30, 2000, other affiliates had issued $700 million of
securities under this registration statement; Global has not issued
any securities under the registration statement.
Summarized financial information of Global is provided below.
(Dollars in millions)
At September 30, At December 31,
2000 1999
------------- --------------
Current assets $4,206 $2,271
Non-current assets 1,625 1,317
Current liabilities 4,174 2,124
Non-current liabilities 540 502
----------------------------------------
Three-month periods Nine-month periods
ended September 30, ended September 30,
----------------------------------------
2000 1999 2000 1999
----------------------------------------
Operating revenues $378 $177 $955 $448
Operating expenses 343 175 908 461
Net income (loss) 54 4 108 (3)
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 1999 Annual Report.
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This Quarterly Report on Form 10-Q contains statements that are not
historical fact and constitute forward-looking statements within the
meaning of the Private Securities Litigation Reform Act of 1995. The
words "estimates," "believes," "expects," "anticipates," "plans,"
"intends," "may" and "should" or similar expressions, or discussions
of strategy or of plans are intended to identify forward-looking
statements that involve risks, uncertainties and assumptions. Future
results may differ materially from those expressed in the forward-
looking statements.
These statements are necessarily based upon various assumptions
involving judgments with respect to the future and other risks,
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; exchange rates; energy markets,
including the timing and extent of changes in commodity prices;
weather conditions; legislative activities; business, regulatory and
legal decisions; the pace of deregulation of retail natural gas and
electricity delivery; 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.
Readers are cautioned not to rely unduly on any forward-looking
statements and 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.
See also "Factors Influencing Future Performance" below.
MAJOR FINANCIAL TRANSACTIONS
See Note 2 of the notes to Consolidated Financial Statements
concerning common stock repurchases, a reduction in common dividends,
South American investments and the agreement to terminate the KN
Energy acquisition.
The self-tender stock repurchase, which did not affect the number of
common shares outstanding until March 9, 2000, and the subsequent
stock repurchases increased earnings per share for both the three-
month period and the nine-month period ended September 30, 2000. The
impact of this repurchase on future periods is dependent on the
amount of future net income and cannot be predicted, and could even
be negative if net income were to fall to the level where the cost of
the financing for the repurchase had a greater impact on earnings per
share than the reduction in the number of shares. However, if the
repurchase had taken place on January 1, 1999 and been financed at
the cost of the actual repurchase in 2000, the impact would have been
to increase 1999's earnings per share by $0.12.
CAPITAL RESOURCES AND LIQUIDITY
The Company's California utility operations have been the major
source of liquidity. However, recent events in electric industry
restructuring, in particular the commodity rate ceiling and resulting
undercollections, will reduce SDG&E's ability to make funds available
to Sempra Energy in 2000 and in the next two or three years. Working
capital requirements can be met through the issuance of short-term
and long-term debt. Cash and cash equivalents at September 30, 2000
are available for investment in utility plant, the retirement of
debt, energy-related domestic and international projects and other
corporate purposes. Approximately $290 million of the cash and cash
equivalents at September 30, 2000 is that of the California
utilities. Major changes in cash flows not described elsewhere are
described below.
CASH FLOWS FROM OPERATING ACTIVITIES
For the nine-month period ended September 30, 2000, the decrease in
cash flows from operations compared to the corresponding period in
1999 is primarily due to SDG&E's refund to customers of surplus rate
reduction bond proceeds (see Note 3 of the notes to Consolidated
Financial Statements), increased accounts receivable, increased net
energy trading assets and a decrease in overcollections on regulatory
balancing accounts. These factors are partially offset by increased
accounts payable and lower income tax payments as a result of income
tax refunds.
The $100 million accelerated refund to customers of certain balancing
account overcollections, as discussed in Note 3 of the notes to
consolidated financial statements, has been returned to customers as
a credit on their bills.
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment by the
California utilities are estimated to be $500 million for the full
year 2000 and are being 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. Capital
expenditures for property, plant and equipment by the Company's other
business are estimated to be $100 million for the full year 2000.
CASH FLOWS FROM FINANCING ACTIVITIES
For the nine-month period ended September 30, 2000, cash flows from
financing activities were relatively unchanged from the corresponding
period in 1999 due to various offsetting factors described below.
As described in Note 2 of the notes to Consolidated Financial
Statements, the Company repurchased 36.1 million shares of its
outstanding common stock at $20.00 per share. The Company issued $500
million of notes and $200 million of preferred securities to finance
substantially all of the repurchase.
As described in Note 2 of the notes to Consolidated Financial
Statements, the Company announced a reduction of its quarterly
dividend per share to $0.25 from its previous level of $0.39,
commencing with the dividend payable in the second quarter of 2000.
In May 2000, SDG&E redeemed its 9-5/8 percent First Mortgage Bonds
due in 2020 at a cost of $104.04 per bond, or $10 million including
accrued interest. In addition, during the nine months ended September
30, 2000, payments on rate reduction bonds and nuclear fuel capital
leases were $48 million and $11 million, respectively. In July 2000,
SoCalGas repaid $30 million of 8.75 percent medium-term notes upon
maturity.
In September 2000, Sempra Energy Global Enterprises (Global) replaced
a $500 million credit agreement with a $1.2 billion credit agreement
that expires in September 2001. At September 30, 2000, Global had
increased its commercial paper obligations supported by the credit
agreement to $303 million. In addition, PE's $300 million credit
agreement was cancelled and SoCalGas' $400 million credit agreement
was decreased to $200 million.
RESULTS OF OPERATIONS
Net income increased 2 percent and 16 percent for the three-month and
nine-month periods ended September 30, 2000, respectively, compared
to the same periods in 1999, primarily due to higher earnings at
Sempra Energy Trading and Sempra Energy International. Net income per
share increased 22 percent and 30 percent for the same periods due to
the increased net income and the effects of the Company's common
stock purchases described in Note 2 of the notes to Consolidated
Financial Statements. Results for the three-month and nine-month
periods ended September 30, 2000 reflect a $30 million aftertax
charge at SDG&E for a potential regulatory disallowance related to
the acquisition to date of wholesale power in the deregulated
California market (see Note 3 of the notes to Consolidated Financial
Statements) and a $10 million decrease in net income during the third
quarter of 2000 from the effect of seasonal variations in income from
sales of natural gas, which in prior years were eliminated by a
balancing account. The effect of these seasonal variations on the
nine-month period ended September 30, 2000, was negligible because
earlier timing differences reversed during the three-month period
ended September 30, 2000.
UTILITY OPERATIONS
The tables below summarize the natural gas and electric volumes and revenues
by customer class for the nine-month periods ended September 30, 2000 and
1999.
<TABLE>
Sempra Energy
Gas Sales, Transportation and Exchange
For the nine-month periods ended September 30
(Volumes in billion cubic feet, dollars in millions)
<CAPTION>
Gas Sales Transportation & Exchange Total
----------------------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
----------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
2000:
Residential 197 $1,564 2 $ 9 199 $1,573
Commercial and industrial 78 503 257 174 335 677
Utility electric generation -- -- 272 96 272 96
Wholesale -- -- 19 14 19 14
---------------------------------------------------------------
275 $2,067 550 $293 825 2,360
Balancing accounts and other (24)
--------
Total $2,336
--------------------------------------------------------------------------------------------
1999:
Residential 231 $1,529 2 $ 6 233 $1,535
Commercial and industrial 81 416 240 184 321 600
Utility electric generation 18 7* 143 56 161 63
Wholesale -- -- 16 6 16 6
---------------------------------------------------------------
330 $1,952 401 $252 731 2,204
Balancing accounts and other (182)
---------
Total $2,022
--------------------------------------------------------------------------------------------
* For the months prior to the sale of its electric plants, the portion of revenue
related to SDG&E's sales to the plants includes margin only.
</TABLE>
Natural gas revenues increased 16 percent for the nine-month period
ended September 30, 2000 compared to the same period in 1999. The
increase is primarily due to higher natural gas prices.
<TABLE>
Sempra Energy
Electric Distribution and Transmission
For the nine-month periods ended September 30
(Volumes in millions of Kwhrs, dollars in millions)
<CAPTION>
2000 1999
------------------------------------------
Volumes Revenue Volumes Revenue
------------------------------------------
<S> <C> <C> <C> <C>
Residential 4,778 $ 654 4,753 $ 491
Commercial 4,740 643 4,733 446
Industrial 1,822 206 1,523 116
Direct access 2,579 82 2,304 88
Street and highway lighting 51 5 57 5
Off-system sales 561 20 290 7
------------------------------------------
14,531 1,610 13,660 1,153
Balancing and other (143) 290
------------------------------------------
Total 14,531 $1,467 13,660 $1,443
------------------------------------------
</TABLE>
Electric revenues increased two percent for the nine-month period
ended September 30, 2000 compared to the same period in 1999. The
increase is primarily due to the effect of higher pass-through
electric commodity costs, partially offset by the charge at SDG&E for
a potential regulatory disallowance related to the acquisition to
date of wholesale power in the deregulated California market and the
decrease in base electric rates (the non-commodity portion) from the
completion of stranded cost recovery (described in Note 3 of the
notes to Consolidated Financial Statements).
Cost of natural gas distributed increased 41 percent for the nine-
month period ended September 30, 2000 compared to the corresponding
period in 1999. The increase was primarily due to higher natural gas
prices. Under the current regulatory framework, changes in core-
market natural gas prices do not affect net income since, as
explained more fully in the 1999 Annual Report, current or future
core customer rates normally recover the actual cost of natural gas.
Electric fuel and net purchased power expense increased 115 percent
for the nine-month period ended September 30, 2000 compared to the
corresponding period in 1999. The increase was primarily due to the
higher price of electricity from the PX, reflecting the recent
supply/demand conditions described in Note 3 of the notes to
Consolidated Financial Statements. Under the current regulatory
framework, changes in on-system prices normally do not affect net
income, as explained in the 1999 Annual Report. However, the recent
supply/demand conditions referred to above resulted in a $50 million
pretax charge to income in September 2000.
Operating expenses increased 25 percent for the nine-month period
ended September 30, 2000 compared to the same period in 1999. The
increase is primarily due to increased activity at Sempra Energy
Trading, partially offset by reduced operating expenses at SoCalGas
and SDG&E.
Depreciation and amortization expense decreased 44 percent for the
nine-month period ended September 30, 2000, compared to the
corresponding period in 1999 due to the 1999 sale of SDG&E's fossil
power plants and combustion turbines.
Net income at SoCalGas increased for the three-month and nine-month
periods ended September 30, 2000, respectively, compared to the same
periods in 1999, primarily due to reduced operating and maintenance
expenses. Net income at SDG&E decreased for the three-month and nine-
month periods ended September 30, 2000, compared to the same periods
in 1999, primarily due to a $30 million aftertax charge for a
potential regulatory disallowance related to the acquisition to date
of wholesale power in the deregulated California market. Also
contributing to the decrease in net income were decreased rate base
and authorized rate of return on equity and increased interest
expense on customer refunds. In addition, with the elimination of the
Gas Fixed Cost Adjustment balancing account at the end of 1999,
SDG&E's net income now fluctuates with changes in natural gas demand,
due to seasonal and other factors. During the three-month period
ended September 30, 2000, this resulted in a $10 million decrease in
net income. The effect on the nine-month period ended September 30,
2000, was negligible because earlier timing differences had reversed.
FACTORS INFLUENCING FUTURE PERFORMANCE
Base results of the Company in the near future will depend primarily
on the results of the California utilities. Earnings growth and
fluctuations will depend on changes in the utility industry and
activities at SEI, SET and other businesses. "Other Operations" below
notes the volatility in the earnings of SET. As SET and/or similar
operations become increasingly more significant to the Company's
results, it is likely that consolidated results will be more volatile
than in prior periods. In addition, the ratemaking and regulatory
process, electric- and natural gas-industry restructuring, changing
energy marketplace, developments in the businesses other than the
California utilities, and other factors will influence future
financial performance. These factors are summarized below.
As discussed in more detail in Note 3 of the notes to Consolidated
Financial Statements, a number of factors, including recent
supply/demand conditions, have resulted in abnormally high electric
commodity prices. This has caused SDG&E's monthly customer bills to
be substantially higher than normal. Responses to these high rates
have resulted in a temporary ceiling on electric rates, as described
briefly below and in more detail in the Note.
In September 2000 the California governor signed two bills (AB 265 and
AB 970) passed by the California Legislature with respect to
electricity pricing and power plant construction. AB 265 contains a
commodity rate ceiling and stabilization plan that imposes a ceiling
on the commodity rate for electricity that SDG&E can pass on to
residential and small business customers on a current basis. The
ceiling is retroactive to June 1, 2000, extends through December 31,
2002, and may be extended through December 31, 2003 if the CPUC
determines that it is in the public interest. AB 265 also requires the
CPUC to initiate a proceeding to assess alternatives for recovering
undercollections (the cost of electricity purchased by SDG&E that
cannot be passed on to customers on a current basis) resulting from
the commodity rate ceiling. The legislation provides for the recovery
of such undercollections (in excess of net revenues associated with
sales of energy from utility-owned or managed generation assets)
resulting from the reasonable and prudent costs of procuring the
commodity. It also directs the CPUC to examine the prudence and
reasonableness of SDG&E's procurement of wholesale energy on behalf of
its customers. In October 2000, the CPUC commenced a thorough review
of SDG&E's energy procurement practices for the period July 1999
through August 2000. A decision is expected in the third quarter of
2001. AB 970 speeds up the licensing and review of new power plants to
increase supply and meet growing demand. The bill also encourages
energy conservation, establishing new programs to reduce demand.
To implement AB 265, on September 7, 2000, the CPUC unanimously
approved a cap on electric rates. The ceiling on the electricity
commodity portion of customers' bills is set at 6.5 cents/kWh. This
is a "floating cap" that can float downward as prices decrease, but
cannot exceed actual commodity costs without the permission of the
CPUC. An interest-bearing balancing account would be established to
record related undercollections resulting from the commodity rate
ceiling with undercollected amounts to be recovered in a manner (not
specified in the decision) intended to make SDG&E whole for the
reasonable and prudent costs of procuring the electric commodity.
This balancing account is classified as a regulatory asset on the
Consolidated Balance Sheets due to its long-term nature. The
undercollection is $254 million at September 30, 2000, is estimated
to amount to $375 million by December 31, 2000, and grow to $550
million and $750 million at December 31, 2001 and 2002, respectively,
based on NYMEX Palo Verde futures prices. If the CPUC later adopts
the option granted it by the legislation to extend the ceiling for an
additional year, the balance at December 31, 2003 is estimated to be
$950 million. These amounts are higher than those recently discussed
by the Company due to balancing-account treatment of contracts with
Qualified Facilities and changes in NYMEX Palo Verde futures prices.
These amounts could increase or decrease significantly due to
variations between the forward prices used in the estimation process
and the actual costs incurred, and could decrease to the extent that
regulators permit overcollections in other balancing accounts to be
applied against this undercollection and/or take actions to correct
the California market, such as by adopting the $150 per MWh "soft
cap" recently proposed by the FERC. In October 2000 SDG&E requested
that the CPUC freeze the commodity rate at 6.5 cents/kWh instead of
capping the rate at that amount. Under a rate freeze, in those months
when the electric commodity cost is less than 6.5 cents/kWh, SDG&E
would be able to collect more revenue than its current cost of
electricity to offset the undercollection incurred when wholesale
power prices are above that rate.
California regulatory uncertainties have led Moody's Investors
Service to change its rating outlook on SDG&E's securities from
positive to negative. Moody's also changed the rating outlook on
Sempra Energy's securities from stable to negative. Fitch IBCA,
another major credit rating agency, also lowered its outlook on
SDG&E's securities from stable to negative due to the uncertainty
over the recovery of high wholesale energy prices not included in
customer bills. Another major credit rating agency, Standard &
Poor's, did not change the Company's rating outlook and believes the
Company's long-term prognosis to be stable. Although some of the
rating outlooks have changed, the Company's actual credit ratings
have not. The Company's actual credit ratings are detailed in Note 3
of the notes to Consolidated Financial Statements.
South American Acquisitions
See Note 2 of the notes to Consolidated Financial Statements and
"International Operations" below for a discussion of the 1999
acquisitions of Chilquinta Energia S.A. and Luz del Sur S.A.A. and
the recent increase in the Company's Argentine investments.
Industry Restructuring
See discussion of industry restructuring in Note 3 of the notes to
Consolidated Financial Statements.
Electric-Generation Assets and Electric Rates
Note 3 of the notes to Consolidated Financial Statements describes
regulatory and legislative actions that affect SDG&E's electric
rates.
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 the California
utilities. 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 plant in a market where a utility already
has a highly developed infrastructure. Each utility's PBR mechanism
is scheduled to be updated at December 31, 2002, to reflect, among
other things, changes in costs and volumes.
Key elements of the mechanisms include an initial reduction in base
rates, an indexing mechanism that limits future rate increases to the
inflation rate less a productivity factor, a sharing mechanism with
customers if earnings exceed the authorized rate of return on rate
base, and rate refunds to customers if service quality deteriorates
or awards if service quality exceeds set standards. Specifically, the
key elements of the mechanisms include the following:
-- Earnings up to 25 basis points in excess of the authorized rate of
return on rate base are retained 100 percent by shareholders.
Earnings that exceed the authorized rate of return on rate base by
greater than 25 basis points are shared between customers and
shareholders on a sliding scale that begins with 75 percent of the
additional earnings being given back to customers and declining to 0
percent as earned returns approach 300 basis points above authorized
amounts. There is no sharing if actual earnings fall below the
authorized rate of return. In 1999, SDG&E and SoCalGas were
authorized to earn 9.05 percent and 9.49 percent, respectively, on
rate base. For 2000, the authorized return is 8.75 percent for SDG&E
and 9.49 percent for SoCalGas.
-- Base rates are indexed based on inflation less an estimated
productivity factor.
-- SDG&E would be authorized to earn or be penalized up to a maximum
of $14.5 million annually as a result of its performance related to
employee safety, electric reliability, customer satisfaction, and
call-center responsiveness. The SoCalGas mechanism authorizes
penalties of up to $4 million annually, or more in certain, limited
situations.
-- SoCalGas' mechanism allows for pricing flexibility for residential
and small-commercial customers, with any shortfalls in revenue being
borne by shareholders and with any increase in revenue shared between
shareholders and customers.
-- Annual cost of capital proceedings are replaced by an automatic
adjustment mechanism. If changes in certain indices exceed
established tolerances, there would be an automatic adjustment of
rates for the change in the cost of capital according to a formula
which applies a percentage of the change to various capital
components.
Cost of Capital
For 2000, SoCalGas is authorized to earn a rate of return on common
equity (ROE) of 11.6 percent and a 9.49 percent return on rate base
(ROR), the same as in 1999, unless interest-rate changes are large
enough to trigger an automatic adjustment as discussed in the
Company's 1999 Annual Report. For SDG&E, electric-industry
restructuring has changed the method of calculating the utility's
annual cost of capital. In June 1999, the CPUC adopted a 10.6 percent
ROE and an 8.75 percent ROR for SDG&E's electric-distribution and
natural gas businesses. The electric-transmission cost of capital is
determined under a separate FERC proceeding.
Biennial Cost Allocation Proceeding (BCAP)
The BCAP determines how a utility's natural gas transportation costs
are allocated among various customer classes (residential,
commercial, industrial, etc.). In October 1998, the California
utilities filed 1999 BCAP applications requesting that new rates
become effective August 1, 1999, and remain in effect through
December 31, 2002. On April 20, 2000, the CPUC issued a decision
adopting overall decreases in natural gas revenues of $210 million
for SoCalGas and $37 million for SDG&E for transportation rates
effective June 1, 2000. Since the decreases reflect anticipated
changes in corresponding costs, they have no effect on net income.
Gas Cost Incentive Mechanism (GCIM)
This mechanism for evaluating SoCalGas' natural gas purchases
substantially replaced the previous process of reasonableness
reviews. GCIM compares SoCalGas' cost of natural gas with a benchmark
level, which is the average price of 30-day firm spot supplies in the
basins in which SoCalGas purchases natural gas. The mechanism permits
full recovery of all costs within a tolerance band above the
benchmark price and refunds all savings within a tolerance band below
the benchmark price. The costs or savings outside the tolerance band
are shared equally between customers and shareholders.
The CPUC approved the use of natural gas futures for managing risk
associated with the GCIM. SoCalGas enters into natural gas futures
contracts in the open market on a limited basis to mitigate risk and
better manage natural gas costs.
In June 1999, SoCalGas filed its annual GCIM application with the
CPUC, requesting an award of $8 million for the annual period ended
March 31, 1999. On June 8, 2000 the CPUC approved the $8 million
award and deferred its decision regarding extending the GCIM beyond
March 31, 2000 until an evaluation is performed by the Commission
staff. The evaluation report is expected in January 2001.
In June 2000, SoCalGas filed its annual GCIM application with the
CPUC, requesting an award of $10 million for the annual period ended
March 31, 2000. On October 30, 2000 the CPUC's Office of Ratepayer
Advocates recommended approval of the $10 million award and the
extension of the GCIM beyond March 31, 2000, with certain
modifications to the tolerance band and benchmark price. A CPUC
decision is expected during the first quarter of 2001.
INTERNATIONAL OPERATIONS
On July 11, 2000 the Company announced an agreement to purchase, for
approximately $140 million, an additional 21.5-percent interest in
two Argentine natural gas utility holding companies (Sodigas Pampeana
S.A. and Sodigas Sur S.A.). The transaction, completed on October 12,
2000, increased the Company's investment in the two Argentine
companies from 21.5 percent to 43 percent.
As discussed in Note 2 of the notes to Consolidated Financial
Statements, Sempra Energy invested in two additional utility
companies in South America during 1999.
Results for international operations for the three-month and nine-
month periods ended September 30, 2000 were net income of $13 million
and $24 million, respectively, compared to net income of $5 million
and a net loss of $3 million, respectively, for the corresponding
periods in 1999. (The 1999 loss has been restated to reflect the
current configuration of this business unit, which now includes two
small, domestic natural gas utilities.) The increase in net income is
primarily due to higher natural gas and electricity sales in its
South American utilities as a result of more severe winter weather in
the region and increased ownership of the Peruvian operations
beginning in September 1999.
Accounting for international operations has resulted in foreign
currency translation adjustments, as shown in Note 4 of the notes to
Consolidated Financial Statements.
OTHER OPERATIONS
Sempra Energy Trading (SET) is a leading energy trading and marketing
firm headquartered in Stamford, Connecticut. SET engages primarily in
natural gas, petroleum and power marketing (domestic and
international). For the three-month and nine-month periods ended
September 30, 2000, SET recorded net income of $45 million and $102
million, respectively, compared to $5 million and $9 million,
respectively, for the corresponding periods in 1999. The increase in
income was primarily due to increased volatility in energy prices and
increased volumes due to geographic expansion and increased activity
in existing markets and products. During the three-month period ended
September 30, 2000, SET further expanded its international operations
with the opening of new offices in Madrid, Spain, and Geneva,
Switzerland. SET also acquired a majority interest in Atlantic
Electric and Gas, an electric and natural gas marketing company in
England and Wales.
Sempra Energy Financial (SEF) invests as a limited partner in
affordable-housing properties and alternative-fuel projects. SEF's
portfolio includes over 1,250 properties throughout the United
States. These investments are expected to provide income-tax benefits
(primarily from income-tax credits) over 10-year periods. For the
three-month and nine-month periods ended September 30, 2000, SEF
recorded net income of $8 million and $23 million, respectively,
compared to $6 million and $20 million, respectively, for the
corresponding periods in 1999. This is expected to decline as the
various 10-year periods expire, unless SEF makes sufficient new
investments. SEF's future investment policy is dependent on the
Company's future domestic income-tax position.
NEW ACCOUNTING STANDARDS
In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 133
"Accounting for Derivative Instruments and Hedging Activities." As
amended, SFAS 133, which is effective for the company on January
1, 2001, requires that an entity recognize all derivatives as
either assets or liabilities in the statement of financial
position, measure those instruments at fair value and recognize
changes in the fair value of derivatives in earnings in the period
of change unless the derivative qualifies as an effective hedge
that offsets certain exposures. The effect of this standard on the
company's Consolidated Financial Statements has not yet been
determined.
In December 1999, the Securities Exchange Commission (SEC) staff
issued Staff Accounting Bulletin (SAB) 101 - Revenue Recognition.
SABs are not rules issued by the SEC. Rather, they represent
interpretations and practices followed by the SEC's staff in
administering the disclosure requirements of the federal
securities laws. SAB 101 provides guidance on the recognition,
presentation and disclosure of revenue in financial statements; it
does not change the existing rules on revenue recognition. SAB 101
sets forth the basic criteria that must be met before revenue
should be recorded. Implementation of SAB 101 is required by the
fourth quarter of 2000 and will have no effect on the company's
Consolidated Financial Statements.
ITEM 3. MARKET RISK
There have been no significant changes in the risk issues affecting
the Company subsequent to those discussed in the Annual Report on
Form 10-K for 1999. The diversified Value at Risk used to measure
market risk of SET's portfolio increased to $6.1 million at September
30, 2000 as compared to $2.6 million at December 31, 1999 due to
increased natural gas prices, combined with increased price
volatility in the power markets.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Except as otherwise described in this report, neither the Company nor
its subsidiaries are party to, nor is their property the subject of,
any material pending legal proceedings other than routine litigation
incidental to their businesses.
ITEM 5. OTHER INFORMATION
In August 2000 the California utilities announced that E.A. Guiles
was appointed to the position of group president of the regulated
business units, which was left vacant by the retirement of Warren
Mitchell. Guiles has also been named chairman of SDG&E and of
SoCalGas and continues as president of SoCalGas and its Energy
Distribution Services business unit.
In September 2000 Sempra Energy announced the appointment of Stephen
L. Baum as chairman. He succeeds former chairman Richard D. Farman,
who has retired. Baum continues as president and chief executive
officer of Sempra Energy.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
Exhibit 12 - Computation of ratios
12.1 Computation of Ratio of Earnings to Combined Fixed
Charges and Preferred Stock Dividends.
Exhibit 27 - Financial Data Schedules
27.1 Financial Data Schedule for the nine-month period ended
September 30, 2000.
(b) Reports on Form 8-K
The following reports on Form 8-K were filed after June 30, 2000:
Current Report on Form 8-K filed August 2, 2000, filing as an exhibit
the Company's press release of July 27, 2000 giving the financial
results for the three-month period ended June 30, 2000.
Current Report on Form 8-K filed October 26, 2000, filing as an
exhibit the Company's press release of October 26, 2000 giving the
financial results for the three-month period ended September 30,
2000.
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly cause this report to be signed on its behalf
by the undersigned thereunto duly authorized.
SEMPRA ENERGY
-------------------
(Registrant)
Date: November 13, 2000 By: /s/ F. H. Ault
----------------------------
F. H. Ault
Vice President and Controller
