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, 2001
-------------------------------------
Commission file number 1-14201
---------------------------------------------
Sempra Energy
----------------------------------------------------------
(Exact name of registrant as specified in its charter)
California 33-0732627
- ------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
101 Ash Street, San Diego, California 92101
- -------------------------------------------------------------------
(Address of principal executive offices)
(Zip Code)
(619) 696-2034
----------------------------------------------------------
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the registrant was required to file such reports),
and (2) has been subject to such filing requirements for the past 90
days.
Yes X No
----- -----
Common stock outstanding on October 31, 2001: 207,195,968
---------------------
PART I FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
SEMPRA ENERGY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
Dollars in millions, except per share amounts
Three Months Ended
September 30,
---------------
2001 2000
------ ------
Revenues and Other Income
California utility revenues:
Natural gas $ 605 $ 799
Electric 399 645
Other operating revenues 623 362
Other income (expense) (5) 26
------ ------
Total 1,622 1,832
------ ------
Expenses
Cost of natural gas distributed 171 382
Electric fuel and net purchased power 151 444
Operating expenses 873 583
Depreciation and amortization 146 142
Franchise payments and other taxes 41 47
Preferred dividends of subsidiaries 3 3
Trust preferred distributions by subsidiary 4 4
------ ------
Total 1,389 1,605
------ ------
Income before interest and income taxes 233 227
Interest 80 67
------ ------
Income before income taxes 153 160
Income taxes 57 50
------ ------
Net income $ 96 $ 110
====== ======
Weighted-average number of shares outstanding:
Basic* 204,180 201,338
------- -------
Diluted* 206,586 201,497
------- -------
Net income per share of common stock (basic) $ 0.47 $ 0.55
======= =======
Net income per share of common stock (diluted) $ 0.46 $ 0.55
======= =======
Common dividends declared per share $ 0.25 $ 0.25
======= =======
*In thousands of shares
See notes to Consolidated Financial Statements.
SEMPRA ENERGY AND SUBSIDARIES
STATEMENTS OF CONSOLIDATED INCOME
Dollars in millions, except per share amounts
Nine Months Ended
September 30,
---------------
2001 2000
------ ------
Revenues and Other Income
California utility revenues:
Natural gas $3,598 $2,336
Electric 1,635 1,467
Other operating revenues 1,711 955
Other income 90 64
------ ------
Total 7,034 4,822
------ ------
Expenses
Cost of natural gas distributed 2,230 1,088
Electric fuel and net purchased power 939 841
Operating expenses 2,343 1,598
Depreciation and amortization 428 420
Franchise payments and other taxes 149 138
Preferred dividends of subsidiaries 9 9
Trust preferred distributions by subsidiary 13 11
------ ------
Total 6,111 4,105
------ ------
Income before interest and income taxes 923 717
Interest 260 216
------ ------
Income before income taxes 663 501
Income taxes 253 167
------ ------
Net income $ 410 $ 334
====== ======
Weighted-average number of shares outstanding:
Basic* 203,296 210,303
------- -------
Diluted* 205,123 210,405
------- -------
Net income per share of common stock (basic) $ 2.02 $ 1.59
======= =======
Net income per share of common stock (diluted) $ 2.00 $ 1.59
======= =======
Common dividends declared per share $ 0.75 $ 0.75
======= =======
*In thousands of shares
See notes to Consolidated Financial Statements.
SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
Dollars in millions
Balance at
--------------------------
September 30, December 31,
2001 2000
------------- ------------
ASSETS
Current assets:
Cash and cash equivalents $ 945 $ 637
Accounts receivable - trade 466 994
Accounts and notes receivable - other 112 213
Income taxes receivable -- 24
Energy trading assets 2,894 4,083
Fixed price contracts and other derivatives 96 --
Regulatory assets arising from fixed price contracts
and other derivatives 145 --
Inventories 191 145
Other 321 329
------- -------
Total current assets 5,170 6,425
------- -------
Investments and other assets:
Fixed price contracts and other derivatives 86 --
Regulatory assets arising from fixed price contracts
and other derivatives 759 --
Regulatory assets 870 1,174
Nuclear-decommissioning trusts 524 543
Investments in unconsolidated affiliates 1,290 1,288
Other assets 537 456
------- -------
Total investments and other assets 4,066 3,461
------- -------
Property, plant and equipment:
Property, plant and equipment 12,416 11,889
Less accumulated depreciation and amortization (6,475) (6,163)
------- -------
Property, plant and equipment - net 5,941 5,726
------- -------
Total assets $15,177 $15,612
======= =======
See notes to Consolidated Financial Statements.
SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS (CONTINUED)
Dollars in millions
Balance at
--------------------------
September 30, December 31,
2001 2000
------------- ------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Short-term debt $ 633 $ 568
Accounts payable - trade 645 1,162
Accounts payable - other 103 117
Income taxes payable 59 --
Deferred income taxes 66 110
Energy trading liabilities 2,035 3,619
Dividends and interest payable 139 124
Regulatory balancing accounts - net 353 830
Current portion of long-term debt 358 368
Fixed price contracts and other derivatives 145 --
Other 796 569
------- -------
Total current liabilities 5,332 7,467
------- -------
Long-term debt 3,583 3,268
------- -------
Deferred credits and other liabilities:
Due to unconsolidated affiliate 160 --
Customer advances for construction 61 56
Post-retirement benefits other than pensions 149 152
Deferred income taxes 938 826
Deferred investment tax credits 96 101
Fixed price contracts and other derivatives 760 --
Regulatory liabilities arising from fixed price
contracts and other derivatives 85 --
Deferred credits and other liabilities 854 844
------- -------
Total deferred credits and other liabilities 3,103 1,979
------- -------
Preferred stock of subsidiaries 204 204
------- -------
Mandatorily redeemable trust preferred securities 200 200
------- -------
Commitments and contingent liabilities (Note 2)
SHAREHOLDERS' EQUITY
Common stock 1,456 1,420
Retained earnings 1,419 1,162
Deferred compensation relating to ESOP (36) (39)
Accumulated other comprehensive income (loss) (84) (49)
------- -------
Total shareholders' equity 2,755 2,494
------- -------
Total liabilities and shareholders' equity $15,177 $15,612
======= =======
See notes to Consolidated Financial Statements.
SEMPRA ENERGY AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
Dollars in millions
Nine Months Ended
September 30,
-------------------
2001 2000
---- ----
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 410 $ 334
Adjustments to reconcile net income to net cash
provided by operating activities:
Depreciation and amortization 428 420
Customer refunds paid -- (378)
Deferred income taxes and investment tax credits 101 (7)
Equity in income of unconsolidated
subsidiaries and joint ventures (7) (42)
Gain on sale of Energy America (32) --
Loss from surrender of Novia Scotia franchise 30 --
Other - net 73 25
Net change in other working capital components (465) 323
------ ------
Net cash provided by operating activities 538 675
------ ------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (673) (492)
Net proceeds from sale of Energy America 52 --
Other - net 24 (38)
------ ------
Net cash used in investing activities (597) (530)
------ ------
CASH FLOWS FROM FINANCING ACTIVITIES
Increase in short-term debt - net 65 121
Issuance of long-term debt 675 512
Payment on long-term debt (391) (158)
Loan from unconsolidated affiliate 160 --
Common dividends paid (152) (195)
Repurchase of common stock -- (725)
Issuance of trust preferred securities -- 200
Other - net 10 (9)
------ ------
Net cash provided by (used in) financing
activities 367 (254)
------ ------
Change in cash and cash equivalents 308 (109)
Cash and cash equivalents, January 1 637 487
------ ------
Cash and cash equivalents, September 30 $ 945 $ 378
====== ======
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Income tax payments (refunds) - net $ 45 $ (58)
====== ======
Interest payments, net of amounts capitalized $ 246 $ 233
====== ======
See notes to Consolidated Financial Statements.
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 2000
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 2000 Annual Report and March 31,
2001 and June 30, 2001 Quarterly Reports on Form 10-Q.
As described in the notes to Consolidated Financial Statements in the
Company's 2000 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 (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation."
2. MATERIAL CONTINGENCIES
ELECTRIC INDUSTRY RESTRUCTURING
The restructuring of California's electric utility industry has
significantly affected the Company's electric utility operations. The
background of this issue is described in the Company's 2000 Annual
Report. Various developments since January 1, 2001 are described
herein.
In February 2001, the California Department of Water Resources (DWR)
began to purchase power from generators and marketers, who had
previously sold their power to the California Power Exchange (PX) and
Independent System Operator (ISO), and has entered into long-term
contracts for the purchase of a portion of the power requirements of
the state's population that is served by investor-owned utilities
(IOUs). SDG&E and the DWR entered into an agreement under which, as
amended, the DWR will continue to purchase power for SDG&E's customers
until December 31, 2002, subject to earlier termination upon six-
months' prior notice and the satisfaction of certain regulatory and
other conditions intended to assure SDG&E's timely recovery of costs
incurred in resuming power procurement for its customers (see MOU
discussion below).
The DWR is now purchasing SDG&E's full net short position (the power
needed by SDG&E's customers, other than that provided by SDG&E's
nuclear generating facilities or its previously existing purchase
power contracts). Therefore, increases in SDG&E's undercollections
from the June 30, 2001 balance of $786 million would result only from
these contracts and interest, offset by nuclear generation, the cost
of which is below the 6.5-cent customer rate cap. Any increases are
not expected to be material. The increase during the six-month period
ended June 30, 2001 was greater than expected in the future because
nuclear generation was reduced from February 2001 through May 2001 due
to a fire and the DWR agreement was not in effect until February 2001.
However, during the three-month period ended September 30, 2001, the
balance decreased to $684 million, primarily due to the application of
overcollections in certain other balancing accounts as further
discussed below.
On June 18, 2001 representatives of California Governor Davis, the
DWR, Sempra Energy and SDG&E entered into a Memorandum of
Understanding (MOU) contemplating the implementation of a series of
transactions and regulatory settlements and actions to resolve many of
the issues affecting SDG&E and its customers arising out of the
California energy crisis. The principal provisions of the MOU are
briefly mentioned below. This summary only highlights selected
provisions of the MOU and readers are urged to read the full text of
the MOU which was filed as Exhibit 99.1 to the Company's Current
Report on Form 8-K filed on June 19, 2001.
- -- The MOU contemplates, subject to requisite approvals of the
California Public Utilities Commission (CPUC), the elimination from
SDG&E's rate-ceiling balancing account of the above-mentioned
undercollected costs that otherwise would be recovered in future rates
charged to SDG&E customers; settlement of reasonableness reviews,
electricity purchase contract issues and various other regulatory
matters affecting SDG&E; the sale to the DWR of power purchased by
SDG&E under certain intermediate-term contracts; and various related
matters.
- -- The effective date of revised base rates for SDG&E and for SoCalGas
is delayed to 2004 from 2003. On October 10, 2001, the CPUC issued a
decision approving the delay to 2004. However, the decision also
denies the utilities' request to continue 50/50 allocation between
ratepayers and shareholders of estimated savings stemming from the
1998 merger between Pacific Enterprises (parent company of SoCalGas)
and Enova Corporation (parent company of SDG&E). Instead, the CPUC
ordered that 100 percent of the estimated 2003 merger benefits go to
ratepayers. The portion to be refunded to electric ratepayers will be
credited to the Transition Cost Balancing Account, based on the net
present value (NPV) in 2001 of the savings for 2003. Merger savings
related to 2001 and 2002 also will be so credited. The combined NPV is
estimated to be $39 million. Merger savings allocable to gas
ratepayers will be refunded through once-a-year bill credit, as has
been the case.
- -- Sempra Energy would make capital investments in SDG&E and SoCalGas
aggregating at least $3.0 billion during 2001 through 2006. The
utilities would receive their authorized rate of return on these
investments.
- -- The MOU also contemplates the sale of SDG&E's transmission system
to the DWR or other state agency for a purchase price of 2.3 times
SDG&E's net book value (purchase price of approximately $1.2 billion),
plus the discharge or assumption of related long-term debt. The sale
of the transmission system is not a condition to the implementation of
the other elements of the MOU, but the implementation of the other
elements is a condition to the transmission sale. SDG&E has no
compelling financial need to sell its transmission assets. In
addition, as the State of California will not be purchasing Southern
California Edison's or Pacific Gas & Electric's transmission systems,
it is unlikely that the state will pursue the purchase of SDG&E's
transmission system.
On August 2, 2001, the CPUC approved a $75 million reduction of the
rate-ceiling balancing account, as contemplated by the MOU, by the
application thereto of overcollections in certain other balancing
accounts. On October 10, 2001, as noted above, the CPUC approved a
delay in the effective date of revised base rates for both SDG&E and
SoCalGas, as contemplated by the MOU. On November 8, 2001, the CPUC
approved a $100 million reduction of the rate-ceiling balancing
account, as contemplated by the MOU, in settlement of the
reasonableness of SDG&E's electric procurement practices between July
1, 1999 through February 7, 2001.
The CPUC has deferred consideration of the remaining elements of the
MOU until a later meeting. Its next scheduled meeting is November 29,
2001. If the remaining elements of the MOU are approved substantially
as contemplated by the MOU, there will be no charge to SDG&E's
earnings associated with the MOU.
The agreement between SDG&E and DWR obligating the DWR to purchase
power for SDG&E's customers has been amended as to the conditions that
would result in the resumption by SDG&E of the procurement of the
residual net power requirements for its retail customers. This
procurement resumption shall occur upon the earlier of a date
determined by the DWR upon six months' prior written notice (once at
least one of the other two major California-based investor-owned
electric utilities has resumed procurement of its residual net short
(net short consists of the power and ancillary services required by a
utility's customers that are not provided by its previously existing
generation and purchase power contracts) and certain CPUC approvals,
including adoption of a satisfactory procurement cost recovery
mechanism, have occurred) or January 1, 2003. These conditions are
intended to assure SDG&E's timely recovery of costs incurred in
resuming power procurement for its customers.
SDG&E's prior request for a temporary 2.3 cents/kWh electric-rate
surcharge that SDG&E requested begin on March 1, 2001 has been
deferred pending the CPUC's action on the MOU. If the MOU is approved
by the CPUC, no rate increase will be necessary, except as required to
pass through, without markup, the rates to repay the DWR for its
purchases of power. In order to provide sufficient revenues for the
collection of the DWR revenue requirement, on September 20, 2001 the
CPUC issued a decision establishing rate increases for SDG&E's
electric customers in an average amount of approximately 1.46
cents/kWh. Residential customers whose electric power consumption does
not exceed 130 percent of baseline quantities, and certain low income
and medical customers are exempt from the increases.
Also on September 20, 2001, the CPUC suspended the ability of retail
electricity customers to choose their power provider ("direct access")
until at least the end of 2003 in order to improve the probability
that enough revenue would be available to the DWR to cover the state's
power purchases. The decision forbids new direct access contracts as
of September 20, 2001 and going forward. The decision defers action on
direct access contracts entered into prior to September 20, 2001.
On April 12, 2001, California law AB 43X took effect, extending the
temporary 6.5-cent rate cap to include SDG&E's large customers (the
only customer class not previously covered by the rate cap)
retroactive to February 7, 2001. The reduced future bills did not add
to the undercollection nor will the fourth quarter refunds of past
charges above 6.5 cents, since the purchases for these customers are
covered by the agreement between SDG&E and the DWR.
On June 18, 2001, the Federal Energy Regulatory Commission (FERC)
approved an expansion of its April 25, 2001 order which adopted
certain price restrictions during Stage 1, 2 and 3 shortage
situations, limiting prices to all generators to the cost of the
least-efficient plant whose generation is required at that time. The
order expanded price restrictions to 24 hours a day, seven days a week
through September 2002. Prices are linked to the price the least
efficient gas-fired plant was allowed to charge during Stage 1
emergencies under the April order. During non-emergency times, the
ceiling price will drop to 85 percent of the emergency price cap.
Critics have responded that this mechanism will be ineffective since,
among other things, it does not cover power brokers and marketers, and
the resultant price will still be relatively high. However, the
combination of successful conservation efforts, reduced air
conditioning load due to mild summer weather, additional power plants'
coming on line and lower prices for the natural gas that fuels most
power plants has currently caused wholesale energy prices to drop and
eased the California electric energy crisis. No rolling blackouts have
been ordered since May 8, 2001.
As discussed in the Company's 2000 Annual Report, the FERC has been
investigating prices charged to the California IOUs by various
electric suppliers. The FERC appears to be proceeding in the direction
of awarding to the California IOUs a partial refund of the amounts
charged. Any such refunds would reduce SDG&E's rate-ceiling balancing
account and could result in a payment by the Company's non-utility
affiliates. Such payment, if any, is not expected to be material to
the Company's financial position or liquidity. A FERC decision is not
expected before March 2002.
NATURAL GAS INDUSTRY RESTRUCTURING
The Company's 2000 Annual Report discusses various proposals and
actions related to natural gas industry restructuring. As discussed
therein, no significant impacts on the Company are expected when the
various issues are finalized. Various developments since January 1,
2001 are described herein.
A settlement agreement between SoCalGas and certain parties settling
the issue of retroactive refunding of costs in rates of ownership and
operation of one of SoCalGas' storage fields was approved by the CPUC
in June 2001. The settlement provides for no retroactive refund of the
costs in rates of this field.
In October 2001, a CPUC commissioner issued a revised Proposed
Decision (PD) which adopts, with some modification, many of the
provisions of the settlement proposal that SoCalGas and SDG&E were
parties to (one of several that arose during 1999 and 2000). On the
SoCalGas system these provisions include, among other things, the
unbundling of intrastate transmission and the implementation of a
system of firm, tradable intrastate transmission rights that are
viewed to be in the public interest. The revised PD also would
increase SoCalGas shareholder risks and rewards for unbundled storage
service, while at the same time granting SoCalGas greater flexibility
in charges for unbundled storage service. A CPUC decision could be
issued at any time, but there is no deadline for CPUC action and the
provisions of a final CPUC decision are uncertain.
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 the public-liability limit stated above is insufficient,
the Price-Anderson Act provides for Congress to enact further revenue-
raising measures to pay claims, possibly including 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 $6.7 million.
Both the public-liability and property insurance (including
replacement power coverage) include coverage for losses resulting from
acts of terrorism. This includes the risk-sharing arrangement with
other nuclear facilities.
LITIGATION
Lawsuits filed in 2000 and currently consolidated at the Federal Court
in Las Vegas seek class-action certification and allege that Sempra
Energy, SoCalGas, SDG&E and El Paso Energy Corp. acted to drive up the
price of natural gas for Californians by agreeing to stop a pipeline
project that would have brought new and less-expensive natural gas
supplies into California. Management believes the allegations are
without merit. On October 30, 2001, the Federal Court ruled that the
State Court is the appropriate jurisdiction for these lawsuits.
Various 2000 lawsuits, which seek class-action certification and which
are expected to be consolidated, allege that Company subsidiaries
unlawfully manipulated the electric-energy market. Management believes
the allegations are without merit.
Sempra Energy Trading (SET) has been involved in a contractual dispute
with Pacific Gas and Electric (PG&E) relating to SET's obligations to
deliver certain quantities of natural gas to PG&E. A settlement of
this matter has been concluded subject to approval by the court having
jurisdiction over PG&E's bankruptcy proceeding. The settlement will
not result in a charge to earnings.
Except for the above, 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.
Management believes that these matters will not have a material
adverse effect on the Company's results of operations, financial
condition or liquidity.
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. Management believes
the remaining balances of the liabilities established in connection
with the quasi-reorganization are adequate.
SHARE REPURCHASES
In February 2000, the Company completed a self-tender offer,
purchasing 36.1 million shares of its outstanding common stock at $20
per share. This was financed by the issuance of $500 million of long-
term notes and $200 million of mandatorily redeemable trust preferred
securities. In March 2000, the Company's board of directors authorized
the optional 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. Through September 30, 2001,
the Company acquired 162,000 shares under this authorization (all in
July 2000).
3. 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) 2001 2000 2001 2000
- ---------------------------------------------------------------
Net income $ 96 $ 110 $ 410 $ 334
Change in unrealized gain
on marketable securities -- (14) -- 7
Foreign currency adjustments (15) 7 (28) 16
Minimum pension liability
adjustments -- 2 (8) 3
Financial instruments (Note 5) 2 -- 1 --
-------------------------------
Comprehensive income $ 83 $ 105 $ 375 $ 360
- ---------------------------------------------------------------
4. SEGMENT INFORMATION
The Company is primarily an energy-services company and has three
reportable segments comprised of SDG&E, SoCalGas and 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 2000 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 2000 Annual Report.
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 the
FERC. There were no significant changes in segment assets during the
nine-month period ended September 30, 2001, except for the increase
due to the adoption of SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities" (as described in Note 5) and the
decrease in energy trading assets, both as shown on the Consolidated
Balance Sheets.
- ---------------------------------------------------------------------
Three-month periods Nine-month periods
ended September 30, ended September 30,
----------------------------------------
(Dollars in millions) 2001 2000 2001 2000
- ---------------------------------------------------------------------
Operating Revenues:
San Diego Gas & Electric $ 450 $ 731 $2,216 $1,776
Southern California Gas 561 722 3,036 2,050
Sempra Energy Trading 211 213 885 605
Intersegment revenues (5) (10) (18) (24)
Other 410 150 825 351
----------------------------------------
Total $1,627 $1,806 $6,944 $4,758
- ---------------------------------------------------------------------
Net Income:
San Diego Gas & Electric* $ 43 $ 15 $ 132 $ 107
Southern California Gas* 57 53 156 150
Sempra Energy Trading 31 45 186 102
Other (35) (3) (64) (25)
----------------------------------------
Total $ 96 $ 110 $ 410 $ 334
- ---------------------------------------------------------------------
* after preferred dividends
- --------------------------------------------------
Balance at
--------------------
September 30, December 31,
2001 2000
- --------------------------------------------------
Assets:
San Diego Gas & Electric $ 5,380 $ 4,734
Southern California Gas 3,763 4,116
Sempra Energy Trading 3,619 4,689
Other 2,415 2,073
--------------------
Total $15,177 $15,612
- --------------------------------------------------
5. FINANCIAL INSTRUMENTS
Adoption of SFAS 133
Effective January 1, 2001, the Company adopted SFAS 133, as amended by
SFAS 138 "Accounting for Certain Derivative Instruments and Certain
Hedging Activities." As amended, SFAS 133 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.
$1.1 billion in current assets, $1.1 billion in noncurrent assets, $6
million in current liabilities, and $238 million in noncurrent
liabilities were recorded as of January 1, 2001, in the Consolidated
Balance Sheet as fixed-priced contracts and other derivatives. Due to
the regulatory environment in which SoCalGas and SDG&E operate,
regulatory assets and liabilities were established to the extent that
derivative gains and losses are recoverable or payable through future
rates. The effect on earnings was minimal. The ongoing effects will
depend on future market conditions and on the Company's hedging
activities.
Market Risk
The Company's policy is to use derivative financial instruments to
manage exposure to fluctuations in interest rates, foreign-currency
exchange rates and energy prices. The Company also uses and trades
derivative financial instruments in its energy trading and marketing
activities. Transactions involving these financial instruments are
with credit-worthy firms and major exchanges. The use of these
instruments exposes the Company to market and credit risk which may at
times be concentrated with certain counterparties, although
counterparty nonperformance is not anticipated.
Energy Derivatives
SoCalGas and SDG&E utilize derivative financial instruments to reduce
exposure to unfavorable changes in energy prices which are subject to
significant and often volatile fluctuation. Derivative financial
instruments are comprised of futures, forwards, swaps, options and
long-term delivery contracts. These contracts allow SoCalGas and SDG&E
to predict with greater certainty the effective prices to be received
and to be charged to their customers.
If gains and losses are not recoverable or payable through future
rates, SoCalGas and SDG&E will apply hedge accounting if certain
criteria are met.
In instances where hedge accounting is applied to energy derivatives,
cash flow hedge accounting is elected and, accordingly, changes in
fair values of the derivatives are included in other comprehensive
income. The entire balance of $2 million, currently included in
accumulated other comprehensive income, is expected to be reclassified
into income within the next 12 months. In instances where energy
derivatives do not qualify for hedge accounting, gains and losses are
recorded in the Statement of Consolidated Income.
Interest-Rate Swap Agreements
The Company periodically enters into interest-rate swap and cap
agreements to moderate exposure to interest-rate changes and to lower
the overall cost of borrowing. At September 30, 2001, the Company had
two interest-rate swap agreements: a floating-to-fixed-rate swap
associated with $45 million of SDG&E's variable-rate bonds maturing in
2002 and a fixed-to-floating-rate swap associated with $500 million of
Sempra Energy's fixed-rate bonds maturing in 2004. The swap associated
with the $45 million of variable-rate bonds does not qualify for hedge
accounting and therefore the gains and losses associated with the
change in fair value are recorded in the Statement of Consolidated
Income. For the nine months ended September 30, 2001, the impact to
income was a $2.0 million loss. Although this financial instrument
does not meet the hedge accounting criteria of SFAS 133, it continues
to be effective in achieving the risk management objectives for which
it was intended.
With regard to the rate swap associated with the $500 million of fixed
rate debt, the Company assumes it is fully effective in its purpose of
converting the fixed rate stated in the debt to a floating rate since
the swap meets the criteria for accounting under the short-cut method
defined in SFAS No. 133 for fair value hedges of debt instruments.
Accordingly, no net gains or losses were recorded in income relative
to the $500 million of fixed rate notes and the interest rate swap.
Accounting for Derivative Activities
At September 30, 2001, $96 million in current assets, $86 million in
noncurrent assets, $145 million in current liabilities and $782
million in noncurrent liabilities were recorded in the Consolidated
Balance Sheet for fixed-priced contracts and other derivatives.
Regulatory assets and liabilities were established to the extent that
derivative gains and losses are recoverable or payable through future
rates. As such, $145 million in current regulatory assets, $759
million in noncurrent regulatory assets, $62 million in regulatory
balancing account liabilities, $85 million in noncurrent regulatory
liabilities, $7 million in current regulatory liabilities (included in
other current liabilities) and $2 million of accumulated other
comprehensive income were recorded in the Consolidated Balance Sheet
as of September 30, 2001. For the nine-month period ended September
30, 2001, $2 million was recorded in other operating income in the
Statement of Consolidated Income.
Sempra Energy Trading
SET derives a substantial portion of its revenue from market making
and trading activities, as a principal, in natural gas, electricity,
petroleum and petroleum products. At September 30, 2001, substantially
all of SET's derivative transactions were held for trading and
marketing purposes. SET marks these derivatives to market each month,
with gains and losses recognized in earnings in accordance with the
Financial Accounting Standards Board's Emerging Issues Task Force
Issue No. 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities." As such, the Company's adoption of
SFAS 133 on January 1, 2001, had no impact on SET's earnings.
Fair Value
The fair value of the Company's derivative financial instruments
(fixed-price contracts and other derivatives) is not materially
different from their carryings amounts. The fair values of fixed-price
contracts and other derivatives were estimated based on quoted market
prices. Information regarding the fair value of the Company's non-
derivative financial instruments is provided in Note 10 of the notes
to Consolidated Financial Statements in the 2000 Annual Report on Form
10-K.
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 2000 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," "would" and "should" or similar expressions, or
discussions of strategy or of plans are intended to identify forward-
looking statements. Forward-looking statements are not guarantees of
performance. They involve risks, uncertainties and assumptions. Future
results may differ materially from those expressed in these forward-
looking statements.
Forward-looking 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, legislative and
regulatory conditions and developments; actions by the CPUC, the
California Legislature, the DWR, and the FERC; the financial condition
of other investor-owned utilities; capital market conditions,
inflation rates, interest rates and exchange rates; energy markets,
including the timing and extent of changes in commodity prices;
weather conditions and conservation efforts; 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.
EVENTS OF SEPTEMBER 11, 2001
The terrorist attacks of September 11 have not affected the Company's
operations and are not expected to have an effect on the Company's
future operations, except to the extent that they significantly affect
the general economy, or the businesses or geographic areas in which
the Company operates.
CAPITAL RESOURCES AND LIQUIDITY
The Company's California utility operations are a major source of
liquidity. However, beginning in the third quarter of 2000 and
continuing into the first quarter of 2001, SDG&E's liquidity and its
ability to make funds available to Sempra Energy were adversely
affected by the undercollections that resulted from the price cap on
electric rates. Significant growth in these undercollections has
ceased as a result of an agreement with the DWR, under which the DWR
is obligated to purchase SDG&E's full net short position consisting of
the power and ancillary services required by SDG&E's customers that
are not provided by SDG&E's nuclear generating facilities or its
previously existing purchase power contracts. The agreement extends
through December 31, 2002 and can be terminated earlier only upon the
satisfaction of regulatory and other conditions intended to assure
SDG&E's timely recovery of costs incurred in resuming power
procurement for its customers. Note 2 of the notes to Consolidated
Financial Statements provides additional information concerning this
agreement.
Cash and cash equivalents at September 30, 2001 are available for
investment in utility plant, the retirement of debt, energy-related
domestic and international projects and other corporate purposes.
Major changes in cash flows not described elsewhere are described
below.
CASH FLOWS FROM OPERATING ACTIVITIES
For the nine-month period ended September 30, 2001, the decrease in
cash flows from operations compared to the corresponding period in
2000 was primarily due to the decrease in overcollected regulatory
balancing accounts due to a decrease in the spot gas price compared to
the average cost of gas, the decrease in trade accounts payable due to
lower September 2001 gas prices, and the increase in net trading
assets, partially offset by the decrease in SoCalGas' trade accounts
receivable due to the lower September 2001 gas prices passed on to its
customers and to customer refunds paid in 2000.
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures for property, plant and equipment by the
California utilities are estimated to be $600 million for the full
year 2001 and are being financed primarily by internally generated
funds. Capital expenditures for property, plant and equipment by the
Company's other business are estimated to be $700 million for the full
year 2001. 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. For the nine
months ended September 30, 2001, the increase in cash flows used in
investing activities compared to the corresponding period in 2000 was
primarily due to an increase in expenditures for property, plant and
equipment at SoCalGas and SEI, partially offset by the net proceeds
from the sale of Energy America. These activities and transactions are
discussed elsewhere in this report.
During the second quarter of 2001, SoCalGas announced plans to add 11
percent more capacity to its transmission system by the end of the
year. The expansion will help meet increased demand for natural gas
from new and existing electric generation projects in Southern
California.
Sempra Energy Resources (SER) is planning to develop approximately
3,000 megawatts of generation by 2004, including a 570-megawatt power
plant near Bakersfield, California; a 1,250-megawatt project located
near Phoenix, Arizona; a 600-megawatt plant near Mexicali, Mexico; and
a 600-megawatt expansion of the El Dorado Energy facility near Las
Vegas, Nevada. In addition, SER is in the development process for a
550-megawatt power plant in Escondido, California and a 1,200-megawatt
power plant in La Place, Louisiana.
On August 21, 2001, SER obtained a syndicated $400 million, three-year
revolving credit facility for its contemplated power projects. This
agreement, guaranteed by the Company, bears interest at various rates
based on market rates and the Company's credit rating.
In October 2001, Sempra Energy International (SEI) and its joint
venture partner, CMS Energy Corporation, signed an agreement to
develop a liquefied natural gas (LNG) receiving terminal on the
Pacific Coast north of Ensenada, Baja California, Mexico. The joint
venture will develop, finance, build and own the LNG facility and
related port infrastructure. Capital expenditures for this project are
estimated at $400 million. The facility, which is scheduled to begin
commercial operations in late 2005, will have a send-out capacity of
approximately one billion cubic feet per day of natural gas. The
natural gas will flow north into Baja California and the southwestern
United States via a 40-mile pipeline between the facility and existing
pipelines in the region.
CASH FLOWS FROM FINANCING ACTIVITIES
For the nine-month period ended September 30, 2001, cash flows from
financing activities increased from the corresponding period in 2000
due primarily to the issuance of $500 million of three-year notes in
June 2001.
In September 2001, Sempra Energy, Sempra Energy Global Enterprises and
other affiliates jointly filed a shelf registration for the public
offering of up to an additional $2.0 billion of debt and equity
securities. Any securities issued by other than Sempra Energy will be
guaranteed by Sempra Energy. SoCalGas also filed a shelf registration
for the public offering of up to an additional $350 million of debt
securities. Any securities under these shelf registrations are offered
on a delayed or continuous basis pursuant to Rule 415 under the
Securities Act of 1933. At September 30, 2001, no debt securities had
been issued under these registration statements.
On June 29, 2001 the Company issued $500 million of three-year notes
due July 1, 2004 at an interest rate of 6.80 percent. Also on June 29,
2001, the Company entered into a fixed-to-floating-rate swap
associated with the notes. Under the swap, the interest rate on the
underlying fixed-rate debt varies (weighted-average rate of LIBOR plus
1.329 percent). The swap expires on July 1, 2004.
In October 2001, $120 million of 6.38-percent, SoCalGas medium-term
notes matured. On November 7, 2001, SoCalGas called its $150 million,
8.75-percent, first mortgage bonds at a premium of 3.59 percent.
On June 6, 2001 the Company remarketed $81 million of variable-rate
debt of the Company's Employee Stock Ownership Plan (ESOP) as 7.375
percent fixed-rate debt due May 3, 2004.
During the first quarter of 2001, SDG&E remarketed $150 million of
variable-rate debt and $25 million of variable-rate unsecured bonds as
7.0 percent and 6.75 percent fixed-rate debt, respectively. At SDG&E's
option, the interest rate may resume floating at various dates between
December 1, 2003 and December 1, 2005. All other terms remain the
same.
On February 9, 2001, SoCalGas' $200 million credit line expired and
was replaced on February 27, 2001, with a $170 million, one-year
agreement. This agreement bears interest at various rates based on
market rates and SoCalGas' credit rating. On April 18, 2001, PE
entered into a $500 million two-year revolving line of credit which
bears interest at various rates based on market rates and PE's credit
rating. In June and July 2001, SDG&E's one-year credit lines totaling
$250 million were renewed and bear interest at various rates based on
market rates and SDG&E's credit rating. SDG&E did not renew a $35
million credit line that expired in June 2001. In September 2001, the
Company replaceded its $1.2 billion one-year revolving credit line
with a similar credit line, which bears interest at various rates
based on market rates and the Company's credit rating.
In connection with the common stock repurchase, the Company reduced
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.
RESULTS OF OPERATIONS
Net income increased for the nine-month period ended September 30,
2001, compared to the same period in 2000 primarily due to higher
earnings at SET arising from expanded markets and product lines, and
from increased volatility in the U.S. natural gas and electric power
markets during the nine months. Also contributing to the increase in
net income for the nine-month period was the sale of the Company's
72.5-percent ownership interest in Energy America for a gain of $20
million, after tax, in January 2001. The 2000 results included a
nonrecurring $30-million, after-tax charge for a potential regulatory
disallowance related to the acquisition of wholesale power in the
deregulated California market. These factors were partially offset by
2001 losses at SER associated with the DWR contract described below
and the one-time, after-tax charge of $25 million following the
surrender of Sempra Atlantic Gas's natural gas distribution franchise
in Nova Scotia. Net income per share increased for the same period due
to the increased net income and the effects of the Company's 2000
common stock purchases described above.
Net income decreased for the three-month period ended September 30,
2001, compared to the same period in 2000. The decrease was primarily
due to lower earnings at SET arising from lower operating profits in
Europe and Asia during the three-month period ended September 30,
2001, losses at SER associated with the DWR contract described below
and the one-time, after-tax charge of $25 million following the
surrender of the natural gas franchise in Nova Scotia. These factors
were partially offset by the third quarter 2000 $30-million charge for
a potential regulatory disallowance.
Other operating revenues increased for the three-month and nine-month
periods ended September 30, 2001, compared to the corresponding
periods in 2000, primarily due to higher revenues at the non-utility
subsidiaries, including Sempra Energy Solutions (SES) due to higher
average natural gas prices, and SER due to the DWR contract previously
discussed and, for the nine-month period, SET due to increased
volatility in the U.S. natural gas and electric power markets.
Other income increased for the nine-month period ended September 30,
2001, compared to the corresponding period in 2000, primarily due to
the gain on the sale of Energy America and higher interest income
resulting from increased cash balances and increased undercollected
regulatory balances at SDG&E, partially offset by the one-time charge
following the surrender of the natural gas franchise in Nova Scotia.
Other income decreased for the three-month period ended September 30,
2001, compared to the corresponding period in 2000, due to the $25-
million charge referred to above.
Interest expense increased for the three-month and nine-month periods
ended September 30, 2001, compared to the same periods in 2000,
primarily due to higher long-term debt and commercial paper balances
in 2001.
Income tax expense increased for the three-month and nine-month
periods ended September 30, 2001, compared to the same periods in
2000, primarily due to higher income before taxes and, for the nine-
month period, an additional expense recorded in the first quarter of
2001 related to the position of the Internal Revenue Service on a
prior year's deduction.
The Company's operating expenses increased for the three-month and
nine-month periods ended September 30, 2001, compared to the same
periods in 2000, primarily due to this increased activity at SET, SES
and SER.
UTILITY OPERATIONS
Seasonality
SDG&E's electric sales volume generally is higher in the summer due to
air-conditioning demands. Both California utilities' natural gas sales
volumes generally are higher in the winter due to heating demands,
although that difference is lessening as the use of natural gas to
fuel electric generation increases. Sales volumes of the Company's
South American affiliates (not included in the following table, since
they are not majority owned) are also affected by seasonality, but the
timing of its increases and decreases is opposite of those in
California since the seasons are reversed in the Southern Hemisphere.
The tables below summarize the natural gas and electric volumes and
revenues by customer class for the nine-month periods ended September
30, 2001 and 2000.
Gas Sales, Transportation and Exchange
(Volumes in billion cubic feet, dollars in millions)
Gas Sales Transportation & Exchange Total
----------------------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
----------------------------------------------------------------------
2001:
Residential 212 $2,263 2 $ 4 214 $2,267
Commercial and industrial 82 748 207 140 289 888
Electric generation plants -- -- 358 89 358 89
Wholesale -- -- 17 8 17 8
---------------------------------------------------------------
294 $3,011 584 $241 878 3,252
Balancing accounts and other 346
--------
Total $3,598
- --------------------------------------------------------------------------------------------
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
- --------------------------------------------------------------------------------------------
The increases in natural gas revenue and the cost of natural gas
distributed were 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 2000 Annual
Report, current or future core customer rates normally recover the actual
cost of natural gas on a substantially concurrent basis.
Electric Distribution and Transmission
(Volumes in millions of Kwhrs, dollars in millions)
2001 2000
------------------------------------------
Volumes Revenue Volumes Revenue
------------------------------------------
Residential 4,474 $ 606 4,778 $ 654
Commercial 4,597 664 4,740 643
Industrial 2,282 342 1,822 206
Direct access 1,656 61 2,579 82
Street and highway lighting 65 8 51 5
Off-system sales 1,391 332 561 20
------------------------------------------
14,465 2,013 14,531 1,610
Balancing accounts and other (378) (143)
------------------------------------------
Total 14,465 $1,635 14,531 $1,467
------------------------------------------
The increase in electric revenues was primarily due to the effect of
higher electric commodity costs, which are passed on to customers
without markup, and increased off-system sales, partially offset by
the downward effect of the DWR's purchases of SDG&E's net short. DWR's
purchases of SDG&E's net short and the corresponding sale to SDG&E's
customers are excluded from SDG&E's income statement. Also partly
offsetting the increase are reductions in customer demand, arising
from conservation efforts encouraged by the State of California
program to give bill credits (funded by the DWR) to customers who
significantly reduce usage. It is uncertain when SDG&E's electric
volumes will return to levels of prior years.
The increase in electric fuel and net purchased power expense was
primarily due to the higher price of electricity as described in Note
2 of the notes to Consolidated Financial Statements and the increased
off-system sales. Under the current regulatory framework, changes in
on-system prices normally do not affect net income, as explained in
the 2000 Annual Report.
FACTORS INFLUENCING FUTURE PERFORMANCE
Since the operating results of the California utilities, subject to
regulatory actions, are usually fairly stable, earnings growth and
fluctuations will depend primarily on activities at SET, SEI, SER and
other businesses. The factors influencing future performance are
summarized below.
Note 2 of the notes to Consolidated Financial Statements describes
events in the deregulation of California's electric utility industry
and the effects thereof on SDG&E, including the suspension of direct
access.
Latin American Investments
As described in the Company's 2000 Annual Report, in 1999 and 2000
Sempra Energy International expanded its investments in South America,
acquiring interests in Chilquinta Energia S.A. and Luz del Sur S.A.A.,
and increasing its interest in Sodigas Pampeana S.A. and Sodigas Sur
S.A. It also increased its plant investment in three natural gas
distribution utilities in northern Mexico during 1997 through 2001,
constructed a 23-mile natural gas pipeline in northern Baja California
in 2000 and announced plans to construct a 215-mile natural gas
pipeline in Northern Mexico in 2002, in conjunction with its
construction of a natural gas fired electric generation plant in
northern Baja California, and jointly develop a major LNG receiving
terminal in Baja California. Additional information about this joint
project is provided below.
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.
In April 2001, SDG&E filed its 2000 PBR report with the CPUC. For
2000, SDG&E exceeded all six performance indicator benchmarks,
resulting in a request for a total net reward of $11.7 million. The
CPUC has not yet approved this report and these awards have not been
recorded. In addition, SDG&E achieved an actual 2000 rate of return of
8.70 percent which is below the authorized 8.75 percent. This results
in no sharing of earnings in 2000 under the PBR sharing mechanism (as
described in the Company's 2000 Annual Report).
The utilities' PBR mechanisms are in effect through December 31, 2002,
at which time the mechanisms will be updated. That update is described
in the Company's 2000 Annual Report. The PBR and Cost of Service (COS)
cases for SoCalGas and SDG&E were both due to be filed on December 21,
2001. However, both SoCalGas' and SDG&E's PBR/COS cases were delayed
by an October 10, 2001 CPUC decision such that the resulting rates
would be effective in 2004 instead of 2003. The decision also denies
the utilities' request to continue 50/50 allocation between ratepayers
and shareholders of the estimated merger savings discussed above and,
instead, orders that 100 percent of the estimated 2003 merger benefits
go to ratepayers. The portion to be refunded to electric ratepayers
will be credited to the Transition Cost Balancing Account, based on
the net present value (NPV) in 2001 of the savings for 2003. Merger
savings related to 2001 and 2002 also will be so credited. The
combined NPV is estimated to be $39 million. Merger savings allocable
to gas ratepayers will be refunded through once-a-year bill credits,
as has been the case.
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.
In May 2001 the CPUC approved a $10 million shareholder award for the
year ended March 31, 2000. In June 2001 SoCalGas filed its annual
GCIM application with the CPUC, requesting a shareholder award of
$106 million for the year ended March 31, 2001. Notwithstanding this
request, SoCalGas stated that it would retroactively reduce the award
request to $31 million if the CPUC approves the settlement agreement
entered into in June 2001 between SoCalGas, the CPUC's Office of
Ratepayer Advocates and The Utilities Reform Network, a consumer-
based intervenor, on modifying the GCIM. A final CPUC decision is
expected in the first quarter of 2002.
Biennial Cost Allocation Proceeding (BCAP)
Rates to recover the changes in the cost of natural gas transportation
services are determined in the BCAP. The BCAP adjusts rates to reflect
variances in customer demand from estimates previously used in
establishing customer natural gas transportation rates. The mechanism
substantially eliminates the effect on income of variances in market
demand and natural gas transportation costs. SoCalGas filed its 2003
BCAP on September 21, 2001 and SDG&E filed its 2003 BCAP on October 5,
2001.
Cost of Capital
For 2001, 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 2000 and 1999, unless interest-rate changes are
large enough to trigger an automatic adjustment as discussed in the
companies' 2000 Annual Reports. 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. These rates will remain in effect through
2002. An application is required to be filed by May 8, 2002,
addressing ROE, ROR and capital structure for 2003. The electric-
transmission cost of capital is determined under a separate FERC
proceeding.
Utility Integration
On September 20, 2001 the CPUC approved Sempra Energy's request to
integrate the management teams of SoCalGas and SDG&E. Utility
operations/management was not, and is not expected to be, shifted to
the parent company. CPUC approval would be required if such a shift
were contemplated. The decision retains the separate identities of
both utilities and is not a merger. Instead, utility integration is a
reorganization that consolidates senior management functions of the
two utilities and returns to the utilities a significant portion of
shared support services currently provided by Sempra Energy's
centralized corporate center. Once implemented, the integration is
expected to result in more efficient and effective operations.
RELATIONSHIP WITH NON-UTILITY SUBSIDIARIES
The Company continues to believe that several of its non-utility
subsidiaries may not be properly valued by the equity market at this
time, as a result of their inclusion within Sempra Energy.
Accordingly, the Company has considered strategies to increase the
value of one or more of these subsidiaries. These strategies could
include, for example, a public offering, a spin-off, a split-off or
other sale of stock or assets involving one or more of these
businesses. However, recent, continuing declines in price/earnings
multiples of businesses similar to these subsidiaries have put further
consideration of such transactions on hold.
CPUC Investigation of Energy-Utility Holding Companies
The CPUC has initiated an investigation into the relationship between
California's investor-owned utilities and their parent holding
companies. Among the matters to be considered in the investigation are
utility dividend policies and practices and obligations of the holding
companies to provide financial support for utility operations. The
investigation is currently on hold while certain jurisdictional issues
are being resolved.
TRADING OPERATIONS
SET, a leading natural gas, petroleum and power marketer headquartered
in Stamford, Connecticut, was acquired on December 31, 1997. In
addition to the transactions described below in "Market Risk," SET
also enters into long-term structured transactions. For the three-
month and nine-month periods ended September 30, 2001, SET recorded
net income of $31 million and $186 million, respectively, compared to
net income of $45 million and $102 million, respectively, for the
corresponding periods of 2000. The increase in net income for the nine
months ended September 30, 2001, compared with the same period in
2000, was primarily due to increased volatility in the U.S. natural
gas and electric power markets that resulted in higher trading volumes
and growing demand for structured price-risk-management products. The
decrease in net income for the three-month period ended September 30,
2001, compared with the same period in 2000, was primarily due to
lower operating profits in Europe and Asia.
INTERNATIONAL OPERATIONS
Results for SEI were a net loss of $7 million and net income of $11
million, respectively, for the three-month and nine-month periods
ended September 30, 2001, compared to net income of $13 million and
$24 million, respectively, for the corresponding periods of 2000. The
decreases in net income were primarily due to the one-time, after-tax
charge of $25 million following the surrender of Sempra Atlantic Gas'
natural gas distribution franchise in Nova Scotia.
In October 2001, SEI and its joint venture partner, CMS Energy
Corporation, signed an agreement to develop a LNG receiving terminal
on the Pacific Coast north of Ensenada, Baja California, Mexico. The
joint venture will develop, finance, build and own the LNG facility
and related port infrastructure. Capital expenditures for this project
are estimated at $400 million. The facility, which is scheduled to
begin commercial operations in late 2005, will have a send-out
capacity of approximately one billion cubic feet per day of natural
gas.
Accounting for international operations has resulted in foreign
currency translation adjustments, as shown in Note 3 of the notes to
Consolidated Financial Statements.
SEMPRA ENERGY RESOURCES
SER develops power plants for the competitive market, as well as
owning natural gas storage, production and transportation assets. SER
recorded net losses of $9 million and $14 million, respectively, for
the three-month and nine-month periods ended September 30, 2001,
compared to net income of $14 million and $16 million, respectively,
for the corresponding periods of 2000. The losses in 2001 are
primarily due to early power sales to California at a discount (under
the DWR contract described below) with the expectation that gains in
later years of the contract will more than offset the early losses.
The discount ended September 30, 2001. Also contributing to the losses
for the nine-month period were lower earnings from the El Dorado
Energy plant due to an extended outage at the plant from March 2001
through the first week of June 2001 and lower electric power prices in
2001.
On May 4, 2001, SER entered into a ten-year agreement with the DWR to
supply the DWR with up to 1,900 megawatts during peak-usage periods.
SER intends to deliver most of this electricity from its projected
portfolio of plants in the western United States and Baja California,
Mexico, which are expected to generate approximately 3,000 megawatts
by 2004. SER can also deliver energy from various market sources to
meet its sales obligations. Sales to the DWR are expected to comprise
more than half of the projected capacity of these facilities. SER may
reduce the amount of power it is required to deliver to the DWR if it
does not build one or more of the generation plants. SER began
providing 250 megawatts of discounted summer capacity to the DWR on
June 1, 2001. This electricity was supplied through market purchases
and SER's 240-megawatt share of the El Dorado generating facility
which began commercial operation in May 2000. In accordance with the
contract, sales to the DWR cease from October 1, 2001 through March
31, 2002, the period during which expected demands for energy are
lower due to cooler weather. Certain pricing issues related to the
deliveries made prior to October 1, 2001 are in the process of
resolution and could result in a small, unfavorable effect on earnings
subsequent to September 30, 2001. Deliveries under the contract
recommence on April 1, 2002 and end on September 30, 2011. There has
been significant discussion in the media concerning the possibility of
the DWR's attempting to renegotiate some or all of its electric supply
contracts. In early November 2001, SER received a request for a
meeting with the California governor's office concerning this
contract. A preliminary meeting was held, during which representatives
of the California governor's office and SER discussed the contract.
Representatives of the governor's office did not request renegotiation
of the contract nor did they make any proposals to restructure current
arrangements. The parties are expected to meet one or more times to
discuss the contract further. SER has no intention to initiate any
form of renegotiation.
In December 2000, SER obtained regulatory approvals to construct a
570-megawatt power plant near Bakersfield, California, and a 1,250-
megawatt power plant near Phoenix, Arizona. Additional projects
contemplated include a 600-megawatt power plant near Mexicali, Mexico
and a 600-megawatt expansion of the El Dorado Energy plant.
OTHER OPERATIONS
SES provides integrated energy-related products and services to
commercial, industrial, government, institutional and consumer
markets. SES recorded net losses of $0.1 million and $4 million in the
three-month and nine-month periods ended September 30, 2001, compared
to net losses of $3 million and $12 million, respectively, for the
corresponding periods of 2000. The reductions in the losses are
primarily attributable to the sale of emission credits and higher
earnings at one of SES's ongoing energy-management installations,
offset by ongoing costs of expanding SES's customer base.
SES's revenues increased in the three-month period ended September 30,
2001 due to customers' anticipating the CPUC's suspension of direct
access, as discussed in Note 2 of the notes to Consolidated Financial
Statements. If the CPUC decides to make that suspension retroactive,
and the retroactivity is not overturned as a result of court action
(which has been discussed by direct-access providers), many of SES's
sales contracts entered into during or prior to that period could be
nullified.
Sempra Energy Financial (SEF) invests as a limited partner in
affordable-housing properties and alternative-fuel projects. SEF's
portfolio includes 1,300 properties throughout the United States.
These investments are expected to provide income-tax benefits
(primarily from income-tax credits) over 10-year periods. SEF recorded
net income of $7 million and $20 million, respectively, for the three-
month and nine-month periods ended September 30, 2001, compared to net
income of $8 million and $23 million, respectively, for the
corresponding periods of 2000. SEF's future investment policy is
dependent on the Company's future domestic income-tax position.
NEW ACCOUNTING STANDARDS
Effective January 1, 2001, the Company adopted SFAS 133 "Accounting
for Derivative Instruments and Hedging Activities" as amended by SFAS
138 "Accounting for Certain Derivative Instruments and Certain Hedging
Activities." The adoption of this new standard on January 1, 2001, did
not have a material impact on earnings. For further information
regarding the implementation of SFAS 133, see Note 5 of the notes to
Consolidated Financial Statements.
In July 2001 the Financial Accounting Standards Board (FASB) approved
three statements, SFAS 141 "Business Combinations," SFAS 142 "Goodwill
and Other Intangible Assets" and SFAS 143 "Accounting for Asset
Retirement Obligations."
- -- SFAS 141 provides guidance on the accounting for a business
combination at the date the combination is completed. It requires
the use of the purchase method of accounting for all business
combinations initiated after June 30, 2001. The pooling-of-interest
method is eliminated.
- -- SFAS 142 provides guidance on how to account for goodwill and other
intangible assets after the acquisition is complete. Goodwill and
certain other intangible assets will no longer be amortized and
will be tested in the aggregate for impairment at least annually.
Goodwill will not be tested on an acquisition-by-acquisition basis.
SFAS 142 applies to existing goodwill and other intangible assets,
beginning with fiscal years starting after December 15, 2001.
- -- SFAS 143 requires entities to record the fair value of a liability
for an asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity
capitalizes a cost by increasing the carrying amount of the related
long-lived asset. Over time, the liability is accreted to its
present value, and the capitalized cost is depreciated over the
useful life of the related asset. Upon settlement of the liability,
an entity either settles the obligation for its recorded amount or
incurs a gain or loss upon settlement.
In August 2001 the FASB approved SFAS 144 "Accounting for the
Impairment or Disposal of Long-Lived Assets" that replaces SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." SFAS 144 applies to all long-lived assets,
including discontinued operations. SFAS 144 requires that those long-
lived assets be measured at the lower of carrying amount or fair value
less cost to sell. Therefore, discontinued operations will no longer
be measured at net realizable value or include amounts for operating
losses that have not yet occurred. SFAS 144 also broadens the
reporting of discontinued operations to include all components of an
entity with operations that can be distinguished from the rest of the
entity and that will be eliminated from the ongoing operations of the
entity in a disposal transaction. The provisions of SFAS 144 are
effective for fiscal years beginning after December 15, 2001.
The Company has not yet determined the effect on its financial
statements of SFASs 141-144 or of the various subsequent guidance
concerning SFAS 133/138.
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 for
2000. As noted in that report, the California utilities may, at times,
be exposed to limited market risk in their natural gas purchase, sale
and storage activities as a result of activities under SDG&E's gas PBR
or SoCalGas' Gas Cost Incentive Mechanism. The risk is managed within
the parameters of the Company's market-risk management and trading
framework. However, to lessen the impact on customers from the
unprecedented natural gas price volatility at the California border
during the first quarter of 2001, the California utilities began
hedging a larger portion of their customer natural gas requirements
than in the past. As of March 31, 2001, the Value at Risk (VaR) of the
SDG&E and SoCalGas hedges was $7.5 million and $1.8 million,
respectively. During the second and third quarters of 2001, the gas
hedging activity at the California utilities was sharply reduced and,
as of September 30, 2001, the VaR of the SDG&E and SoCalGas hedges was
$200,000 each. This represents the 50-percent shareholder portion
under the PBR mechanism and excludes the 50-percent portion subject to
rate recovery. In addition, certain fixed price contracts that
traditionally have not been considered derivatives, but now meet the
derivative definition under SFAS 133 (see "New Accounting Standards"
above), are excluded from the VaR amounts due to the offsetting
regulatory asset or liability. SET's VaR as of September 30, 2001, was
$5.9 million.
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Except as otherwise described in this report, the Company's 2000
Annual Report, or its March 31, 2001 or June 30, 2001 Quarterly
Reports on Form 10-Q, 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 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.
(b) Reports on Form 8-K
The following reports on Form 8-K were filed after June 30, 2001:
Current Report on Form 8-K filed July 16, 2001 reported the current
status of California Public Utilities Commission review of the
Memorandum of Understanding with the State of California.
Current Report on Form 8-K filed July 27, 2001, filing as an exhibit
Sempra Energy's press release of July 26, 2001, giving the financial
results for the three-month period ended June 30, 2001.
Current Report on Form 8-K filed October 26, 2001, filing as an
exhibit Sempra Energy's press release of October 25, 2001, giving the
financial results for the three-month period ended September 30, 2001.
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, 2001 By: /s/ F. H. Ault
----------------------------
F. H. Ault
Sr. Vice President and Controller
EXHIBIT 12.1
SEMPRA ENERGY
COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES
AND PREFERRED STOCK DIVIDENDS
(Dollars in millions)
For the nine
months ended
September 30,
1996 1997 1998 1999 2000 2001
-------- -------- -------- -------- -------- --------
Fixed Charges and Preferred
Stock Dividends:
Interest $ 205 $ 209 $ 210 $ 233 $ 305 $ 279
Interest Portion of
Annual Rentals 28 25 20 10 8 6
Preferred dividends
of subsidiaries (1) 37 31 18 16 18 15
-------- -------- -------- -------- -------- --------
Total Fixed Charges
and Preferred Stock
Dividends For Purpose
of Ratio $ 270 $ 265 $ 248 $ 259 $ 331 $ 300
======== ======== ======== ======== ======== ========
Earnings:
Pretax income from
continuing operations $ 727 $ 733 $ 432 $ 573 $ 699 $ 663
Add:
Fixed charges
(from above) 270 265 248 259 331 300
Less:
Fixed charges
capitalized 5 3 3 5 5 6
Equity income (loss) of
unconsolidated subsidiaries
and joint ventures - - - - 62 7
-------- -------- -------- -------- -------- --------
Total Earnings for
Purpose of Ratio $ 992 $ 995 $ 677 $ 827 $ 963 $ 950
======== ======== ======== ======== ======== ========
Ratio of Earnings
to Combined Fixed Charges
and Preferred Stock
Dividends 3.67 3.75 2.73 3.19 2.91 3.17
======== ======== ======== ======== ======== ========
(1) In computing this ratio, "Preferred dividends of subsidiaries" represents the
before-tax earnings necessary to pay such dividends, computed at the effective tax
rates for the applicable periods.
