SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act
of 1934
Date of Report
(Date of earliest event reported): June 26, 1998
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SEMPRA ENERGY
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(Exact name of registrant as specified in its charter)
CALIFORNIA 1-14201 33-0732627
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(State of incorporation (Commission (I.R.S. Employer
or organization) File Number) Identification No.
101 ASH STREET, SAN DIEGO, CALIFORNIA 92101
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(Address of principal executive offices) (Zip Code)
(619) 696-2000
Registrant's telephone number, including area code-------------------
MINERAL ENERGY COMPANY
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(Former name or former address, if changed since last report.)
FORM 8-K
Item 2. Acquisition or Disposition of Assets
Sempra Energy, on June 26, 1998, acquired all of the outstanding
Common Stock of Pacific Enterprises and Enova Corporation in a tax-
free reorganization accounted for as a pooling of interests for
financial reporting purposes.
The acquisition was effected in connection with a business
combination of Pacific Enterprises and Enova Corporation. Sempra
Energy was formed to serve as a holding company for the two
corporations in connection with the combination and has not
conducted any business activities other than those incidental to
the combination.
The business combination was approved by the respective
shareholders of Pacific Enterprises and Enova Corporation on March
11, 1997 and was effected on June 26, 1998 following the receipt of
requisite regulatory approvals. In the combination each of the
83,917,664 outstanding shares of Pacific Enterprises Common Stock
was converted into 1.5038 shares of Sempra Energy Common Stock and
each of the 113,614,942 outstanding shares of Enova Corporation
Common Stock was converted into one share of Sempra Energy Common
Stock. Shares of Sempra Energy Common Stock are traded on the New
York and Pacific Stock Exchanges under the trading symbol SRE.
For a more complete description of the business combination and
related information, reference is made to the Joint Proxy
Statement/Prospectus of Pacific Enterprises and Enova Corporation
dated February 7, 1997, included as part of the Registration
Statement on Form S-4 (Registration No. 333-21229) of Sempra Energy
(then named Mineral Energy Corporation).
Pacific Enterprises and Enova Corporation are energy services
holding companies whose respective principal subsidiaries are
Southern California Gas Company and San Diego Gas & Electric
Company. For information regarding the business and operations of
Pacific Enterprises and Enova Corporation reference is made to
their respective Annual Reports on Form 10-K for the year ended
December 31, 1997 and their respective Quarterly Reports on Form
10-Q for the quarter ended March 31, 1998.
Board of Directors
Sempra Energy's Board of Directors consists of sixteen members,
eight of whom were directors of Pacific Enterprises and eight of
whom were directors of Enova Corporation at the time of the
business combination. The board is divided into three
approximately equal classes with terms expiring over a staggered
three-year period.
The names and additional information regarding each of Sempra
Energy's sixteen directors is set forth below. Years of service as
a director include service with Pacific Enterprises, Enova
Corporation and San Diego Gas & Electric Company.
Class I (Terms Expiring in 1999)
Hyla. H. Bertea, 58, has been a director since 1988. Mrs. Bertea
is a realtor with Prudential California.
Committees: Compensation Sempra Energy
Corporate Governance (Chair) Shares: 9,805
Ann Burr, 51, has been a director since 1994. Ms. Burr is
President of Time Warner Communications in Rochester, New York.
Committees: Audit Sempra Energy
Corporate Governance Shares: 2,200
Richard A. Collato, 54, has been a director since 1994. Mr. Collato
is President and Chief Executive Officer of the YMCA of San Diego
County.
Committees: Audit (Chair) Sempra Energy
Finance Shares: 3,790
Daniel W. Derbes, 68, has been a director since 1983. Mr. Derbes
is President of Signal Ventures. He is also a director of Oak
Industries, Inc. and WD-40 Co.
Committees: Corporate Governance Sempra Energy
Finance (Chair) Shares: 5,232
Ignacio E. Lozano, Jr., 71, has been a director since 1978.
Mr. Lozano is Chairman of the Board of La Opinion. He is also a
director of The Walt Disney Company and Pacific Mutual Life
Insurance Company.
Committees: Compensation Sempra Energy
Executive Shares: 2,209
Class II (Terms Expiring in 2000)
Herbert L. Carter, 65, has been a director since 1991. Dr. Carter
is Executive Vice Chancellor Emeritus and Trustee Professor of
Public Administration of the California State University System.
He is also a director of Golden State Mutual Insurance Company.
Committee: Executive Sempra Energy
Public Policy (Chair) Shares: 1,492
Wilford D. Godbold, Jr., 60, has been a director since 1990.
Mr. Godbold is President and Chief Executive Officer of ZERO
Corporation. He is also a director of Santa Fe Pacific Pipelines,
Inc.
Committees: Audit Sempra Energy
Finance Shares: 3,006
Robert H. Goldsmith, 68, has been a director since 1992.
Mr. Goldsmith is a Management Consultant.
Committees: Audit Sempra Energy
Corporate Governance Shares: 2,297
William D. Jones, 43, has been a director since 1994. Mr. Jones is
President and Chief Executive Officer of CityLink Investment
Corporation. He is also a director of The Price Real Estate
Investment Trust.
Committees: Finance Sempra Energy
Public Policy Shares: 1,771
Ralph R. Ocampo, 67, has been a director since 1983. Mr. Ocampo is
a San Diego physician and surgeon.
Committees: Compensation Sempra Energy
Public Policy Shares: 14,469
William G. Ouchi, 55, became a director in 1998. Dr. Ouchi is a
Vice Dean and Faculty Director of Executive Education Programs and
Professor of Management in the Anderson Graduate School of
Management at UCLA. He is also co-chair of the UCLA School
Management Program. He is also a director of Allegheny-Teledyne
and First Federal Bank of California.
Committees: Audit Sempra Energy
Public Policy Shares: 10,000
Class III (Terms Expiring in 2001)
Stephen L. Baum, 57, has been a director since 1996. Mr. Baum is
Vice Chairman of the Board, President and Chief Operating Officer
of Sempra Energy. He is also a director of Wright Strategies, Inc.
Committee: Executive Sempra Energy
Shares: 70,781
Richard D. Farman, 62, has been a director since 1992. Mr. Farman
is Chairman of the Board and Chief Executive Officer of Sempra
Energy. He is also a director of Union Bank, Sentinel Group Funds,
Inc. and Catellus Development Corporation.
Committee: Executive (Chair) Sempra Energy
Shares: 479,179
Richard J. Stegemeier, 70, has been a director since 1995.
Mr. Stegemeier is Chairman Emeritus of the Board of Unocal
Corporation. He is also a director of Foundation Health Systems,
Inc.; Halliburton Company; Montgomery Watson, Inc.; Northrop
Grumman Corporation; and Wells Fargo Bank.
Committees: Compensation (Chair) Sempra Energy
Corporate Governance Shares: 1,503
Thomas C. Stickel, 49, has been a director since 1994. Mr. Stickel
is Chairman and Chief Executive Officer of University Venture
Network. He is also a director of Onyx Acceptance Corporation;
Blue Shield of California; O'Connor R.P.T.; and Scripps
International, Inc.
Committees: Compensation Sempra Energy
Executive Shares: 1,995
Diana L. Walker, 57, has been a director since 1989. Mrs. Walker
is a partner in the law firm of O'Melveny & Myers LLP, which, among
other firms, provides legal services to Southern California Gas Company.
Committees: Audit Sempra Energy
Finance Shares: 862
Executive Officers
The executive officers of Sempra Energy are as follows:
Name Age Position
- ---------------------- ----- --------------
Richard D. Farman 62 Chairman of the Board and
Chief Executive Officer
Stephen L. Baum 57 Vice Chairman, President and
Chief Operating Officer
Donald E. Felsinger 50 Group President -
Non-regulated Business Units
Warren I. Mitchell 61 Group President - Regulated
Business Units
John R. Light 57 Executive Vice President and
General Counsel
Neal E. Schmale 51 Executive Vice President and
Chief Financial Officer
Edwin A. Guiles 48 President of San Diego
Gas & Electric Company
Debra L. Reed 42 Senior Vice President of
Southern California Gas
Company and President of
Energy Distribution Services
Lee M. Stewart 52 Senior Vice President of
Southern California Gas
Company and President of
Energy Transmission Services
Frederick E. John 52 Senior Vice President -
External Affairs
Margot A. Kyd 44 Senior Vice President and
Chief Administrative Officer
G. Joyce Rowland 43 Senior Vice President -
Human Resources
Frank H. Ault 54 Vice President and Controller
All of Sempra Energy's executive officers have been employed by
Pacific Enterprises or Enova Corporation or their respective
subsidiaries in management positions for more than five years
except for Messrs. Light and Schmale. Before joining Enova
Corporation in 1998, Mr. Light was a partner in the law firm of
Latham and Watkins. Before joining Pacific Enterprises in 1997,
Mr. Schmale was President of the Petroleum Products and Chemicals
Divisions of Unocal Corporation (1992-1994) and Chief Financial
Officer of Unocal Corporation (1994-1997).
Includes 34,150 shares of restricted common stock.
Includes 449,635 shares issuable upon exercise of employee
stock options currently exercisable or becoming exercisable
prior to September 30, 1998.
Item 7. Financial Statements and Exhibits
(a) Financial statements of businesses acquired
1. Pacific Enterprises 1997 Annual Report on Form
10-K filed under Commission File Number 1-00040 on
March 26, 1998 incorporated by reference herein.
2. Enova Corporation 1997 Annual Report on Form 10-K
filed under Commission File Number 1-11439 on
February 27, 1998 incorporated by reference
herein.
3. Pacific Enterprises Quarterly Report on Form 10-Q
for the three months ended March 31, 1998 filed
under Commission File Number 1-00040 on
May 11, 1998 incorporated by reference herein.
4. Enova Corporation Quarterly Report on Form 10-Q
for the three months ended March 31, 1998 filed
under Commission File Number 1-11439 on
May 7, 1998 incorporated by reference herein.
(b) Sempra Energy
- For the Year Ended December 31, 1997:
1. Management's Discussion and Analysis of Financial
Condition and Results of Operations.
2. Supplemental Selected Financial Data.
3. Supplemental Statements of Consolidated Income for
the years ended December 31, 1997, 1996 and 1995.
4. Supplemental Consolidated Balance Sheets at
December 31, 1997 and 1996.
5. Supplemental Statements of Consolidated Cash Flows
for the years ended December 31, 1997, 1996 and
1995.
6. Supplemental Statements of Consolidated Changes in
Shareholders' Equity for the years ended December
31, 1997, 1996 and 1995.
7. Supplemental Statements of Consolidated Financial
Information by Segments of Business for the years
ended December 31, 1997, 1996 and 1995.
8. Report of Independent Accountants.
9. Notes to Supplemental Consolidated Financial
Statements.
- For the Three Months Ended March 31, 1998:
1. Management's Discussion and Analysis of Financial
Condition and Results of Operations.
2. Supplemental Statements of Consolidated Income
(unaudited) for the three months ended
March 31, 1998 and 1997.
3. Supplemental Consolidated Balance Sheets at
March 31, 1998 (unaudited) and December 31, 1997.
4. Supplemental Statements of Consolidated Cash Flows
(unaudited) for the three months ended March 31,
1998 and 1997.
5. Notes to Supplemental Consolidated Financial
Statements (unaudited).
- Independent Auditors' Consent.
(c) Exhibits
2. Agreement and Plan of Merger and Reorganization dated
as of October 12, 1996 and as amended January 13, 1997 among Enova
Corporation, Pacific Enterprises, Sempra Energy (then named Mineral
Energy Company), G Mineral Energy Sub and B Mineral Energy Sub
(filed as Annex A to the Joint Proxy Statement/Prospectus dated
February 7, 1997 included in the Registration Statement on Form S-4
Registration Statement No. 333-21229) of Sempra Energy (then named
Mineral Energy Company) and incorporated hereby by reference).
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrants have duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
SEMPRA ENERGY
(Registrant)
Date: June 30, 1998 By: /s/ F.H. Ault
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F.H. AULT
Vice President and Controller
SEMPRA ENERGY
FOR THE YEAR ENDED DECEMBER 31, 1997.
ITEM 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations
Introduction
This section includes management's analysis of operating results
from 1995 through 1997, and is intended to provide additional
information about the capital resources, liquidity and financial
performance of Sempra Energy (the Company). This section also
focuses on the major factors expected to influence future operating
results and discusses investment and financing plans. Management's
discussion and analysis should be read in conjunction with the
supplemental consolidated financial statements included in this
Current Report on Form 8-K.
The Company is a California-based Fortune 500 energy-services
company whose primary subsidiaries are San Diego Gas & Electric
(SDG&E), which provides electric and gas service to San Diego and
southern Orange Counties, and Southern California Gas Company
(SoCalGas), the nation's largest natural-gas distribution utility,
serving 4.8 million meters throughout most of southern California
and part of central California. Together, the two utilities serve
approximately 6 million customers. Sempra Energy Trading Corp.
(formerly AIG Trading Corporation) is engaged in the wholesale
trading and marketing of natural gas, power and oil. Sempra
Energy Solutions (formerly Energy Pacific), is engaged in the
buying and selling of natural gas for large users, integrated
energy management services targeted at large governmental and
commercial facilities, and consumer market products and services.
Enova Financial invests in limited partnerships representing 1,200
affordable-housing properties throughout the United States.
Through other subsidiaries the Company owns and operates interstate
and offshore natural gas pipelines and centralized heating and cooling
for large building complexes, and is involved in domestic and
international energy-utility operations, non-utility electric
generation and other energy-related products and services.
Business Combinations
On March 26, 1998, the California Public Utilities Commission
(CPUC) approved the combination of SoCalGas' parent, Pacific
Enterprises (PE) and SDG&E's parent, Enova Corporation (Enova.)
The decision determined that savings from synergies and cost
avoidances be shared between customers and shareholders over a
five-year period, for a total net savings of approximately $340
million.
In its decision, the CPUC found that the combination satisfied
the key criteria that it will benefit the state and local economies
and customers, maintain or improve the financial condition of the
utilities and the quality of management, and be fair to employees
and shareholders. Elements of the CPUC decision include:
Divestiture by SDG&E of its gas-fired generation units, which is
already in progress, and sale by September 1, 1998 of SoCalGas'
options to purchase the California portions of the Kern River and
Mojave Pipeline gas transmission facilities. These options are
not exercisable until the year 2012.
Acknowledgment that the combination will have no significant
effect on the environment under the California Environmental
Quality Act.
Inclusion in the calculation of $340 million of total net savings
of $148 million in costs to achieve the merger, rather than the
$202 million originally sought by the companies. The difference
relates to transaction costs for investment bankers, employee
retention and communications.
In June 1998, final regulatory approvals were received from the
Federal Energy Regulatory Commission (FERC) and the Security
Exchange Commission (SEC). The FERC approved the combination
subject to conditions that the combined company will not unfairly
use any potential market power regarding natural-gas transportation
to gas-fired electric-generation plants. In addition, the FERC
required that the Company adopt specific remedial measures to
alleviate the market power concerns and that the CPUC commit to the
enforcement of these measures. The FERC also specifically noted
that the divestiture of SDG&E's natural-gas-fired generation plants
would eliminate any concerns about vertical market power arising
from transactions between SDG&E and SoCalGas.
The combination, effective June 26, 1998, resulted in PE and
Enova becoming subsidiaries of the Company. The holders of common
stock of each company became the holders of the Company's common
stock. PE's common shareholders received 1.5038 shares of the
Company's common stock for each share of PE common stock, and Enova
common shareholders received one share of the Company's common
stock for each share of Enova common stock. The preferred stock of
PE, SoCalGas and SDG&E remains outstanding. The combination was
approved by the shareholders of both companies on March 11, 1997
and is a tax-free transaction accounted for as a pooling of
interests. Combined operations will commence in July 1998.
In December 1997, PE and Enova jointly acquired Sempra Energy
Trading Corp., a natural-gas and power marketing firm with 90
employees headquartered in Greenwich, Connecticut. The total cost
of the acquisition was approximately $225 million.
In January 1998, Sempra Energy Solutions, then a joint venture
of PE and Enova, acquired CES/Way International, the largest
independent U.S. company providing energy-service performance
contracting. CES/Way International has 125 employees and is
headquartered in Houston, Texas. The total cost of the acquisition
was less than $100 million.
Generally accepted accounting principles proscribe giving
effect to a consummated business combination accounted for by the
pooling of interests methods in financial statements that do not
include the period during which consummation occurred. The
supplemental consolidated financial statements do not extend
through the date of consummation of the business combination;
however, they will become the historical consolidated financial
statements of the Company and its subsidiaries when financial
statements covering the date of consummation of the business
combination are issued.
Capital Resources and Liquidity
The Company's utility operations continue to be a major source of
liquidity. In addition, working capital requirements are met
primarily through the issuance of short-term and long-term debt.
Cash requirements include capital investments in the utility
operations. Nonutility cash requirements include investments in
Sempra Energy Solutions, CES/Way International, and other domestic
and international ventures.
Additional information on sources and uses of cash during the
last three years is summarized in the following condensed statement
of cash flows:
Sources and (Uses) of Cash
Year Ended December 31,
(Dollars in millions) 1997 1996 1995
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Operating Activities $ 918 $ 1,164 $ 1,305
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Investing Activities:
Capital Expenditures (397) (413) (461)
Acquisition of Sempra Energy Trading (206) -- --
Other 1 (101) (11)
---------------------------------
Total Investing Activities (602) (514) (472)
----------------------------------
Financing Activities:
Long-Term Debt 382 (155) (248)
Short-Term Debt 92 29 (133)
Issuance of Common Stock 17 8 6
Repurchase of Common Stock (122) (24) --
Redemption of Preferred Stock -- (225) (30)
Dividends on Common Stock (301) (300) (293)
----------------------------------
Total Financing Activities 68 (667) (698)
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Increase (Decrease) in Cash
and Cash Equivalents $ 384 $ (17) $ 135
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Cash Flows from Operating Activities
The decrease in cash flow from operating activities to $918 million
in 1997 from $1,164 million in 1996 was primarily due to greater
working capital requirements, for gas sales at SoCalGas in 1997.
This was caused by gas costs being higher than amounts collected in
rates, resulting in undercollected regulatory balancing accounts at
year-end 1997. The cash flow from electric operations for 1997 was
consistent with results from 1996.
Cash flow from operating activities decreased to $1,164 million
in 1996 from $1,305 million in 1995. The decrease was primarily
due to lower noncore gas revenues, lower amounts received from
undercollected regulatory balancing accounts in both gas and
electric operations, and higher income-tax payments resulting from
settlements with the Internal Revenue Service, partially offset by
other nonrecurring favorable settlements.
Cash Flows from Investing Activities
Capital expenditures
Capital expenditures primarily represent investment in utility
operations. Capital expenditures were $16 million lower in 1997
than in 1996 due to changes in the scope and timing of several
major capital projects primarily related to information systems.
Capital expenditures for 1996 were $48 million lower than in
1995, primarily due to the completion of various major projects in
1996 and 1995.
Payments to the nuclear-decommissioning trusts are expected to
continue until San Onofre Nuclear Generating Station (SONGS) is
decommissioned, which is not expected to occur before 2013.
Although Unit 1 was permanently shut down in 1992, it is scheduled
to be decommissioned concurrently with Units 2 and 3. However,
this will depend on the outcome of the proposed sale of SDG&E's
electric-generating assets, including its interest in SONGS.
Capital expenditures are estimated to be $442 million in 1998.
They will be financed primarily by internally generated funds and
will largely represent investment in utility operations. The level
of expenditures in the next few years will depend heavily on the
impacts of electric industry restructuring and the sale of SDG&E's
Encina and South Bay power plants and other electric-generating
assets, as well as the timing and extent of expenditures to comply
with environmental requirements.
Investments
As previously discussed, in December 1997, PE and Enova jointly
acquired Sempra Energy Trading Corp.
Investments in 1996 include the acquisition of a 12.5% interest
in two utility holding companies that control natural gas
distribution utilities in Argentina for $48.5 million.
In September 1997, Sempra Energy Solutions formed a joint
venture with Bangor Hydro to build, own and operate a $40 million
natural-gas distribution system in Bangor, Maine. In addition, in
December 1997 Sempra Energy Solutions signed a partnership
agreement with Frontier Utilities to build and operate a $55
million natural-gas distribution system in North Carolina.
In December 1997, Sempra Energy Resources and Houston
Industries Power Generation formed El Dorado Energy, a joint
venture to build, own and operate a natural-gas power plant in
Boulder City, Nevada. The Company invested $2.3 million in El
Dorado Energy in 1997 and expects to invest an additional $37
million in 1998 and $17 in 1999.
Sempra Energy's level of investments in the next few years will
depend primarily on the activities of its subsidiaries other than
SoCalGas and SDG&E, including Sempra Energy Solutions, and domestic
and international investments in natural-gas distribution projects.
Cash Flows from Financing Activities
Cash flow used for financing activities decreased $735 million in
1997 compared to 1996, primarily due to the issuance of Rate
Reduction Bonds at SDG&E, lower repayments of long-term debt and
the redemption of PE's preferred stock in 1996, partially offset by
the redemption of common stock in 1997.
Cash flow used for financing activities decreased $31 million
in 1996 compared to 1995, primarily due to a decrease in long- and
short-term debt repayments, partially offset by the redemption of
preferred stock and the repurchase of common stock.
Long-Term Debt
In 1997 cash was used for the repayment of $96 million of debt
issued to finance the Comprehensive Settlement (see Note 5 of the
notes to supplemental consolidated financial statements) and
repayment of $252 million of First Mortgage Bonds. This was
partially offset by the issuance of $120 million in Medium Term
Notes and short-term borrowings used to finance working capital
requirements at SoCalGas.
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. A portion of the bond proceeds was used to retire $14.9
million of variable-rate, taxable Industrial Development Bonds
(IDBs) in January 1998. Additional retirements are planned.
Additional information concerning the Rate Reduction Bonds is
provided below under "Electric Industry Restructuring."
SDG&E has $83 million of temporary investments that will be
maintained into the future to offset a like amount of long-term
debt. The specific debt series being offset consists of variable-
rate IDBs. The CPUC has approved specific ratemaking treatment
which allows SDG&E to offset IDBs as long as there is at least a
like amount of temporary investments. If and when SDG&E requires
all or a portion of the $83 million of IDBs to meet future needs
for long-term debt, such as to finance new construction, the amount
of investments which are being maintained will be reduced below $83
million and the level of IDBs being offset will be reduced by the
same amount.
In 1996 cash at SoCalGas was used for a $67 million redemption
of Swiss Franc Bonds and repayment of $79 million of debt issued to
finance the Comprehensive Settlement. This was partially offset by
cash provided from the issuance of $75 million in Medium Term
Notes. SDG&E issued $229 million in bonds to retire previously
issued bonds of $255 million. In addition, other subsidiaries
repaid $29 million on long-term debt in the normal course of
business.
Stock Purchases and Redemption
During 1997 and 1996, common stock equivalent to 5.4 million and
1.4 million shares, respectively, of Sempra Energy common stock was
repurchased.
In 1996 PE redeemed $210 million of variable-rate remarketed
preferred stocks, of which $100 million was issued by SoCalGas. In
1995, $30 million of preferred stock was redeemed.
On February 2, 1998, SoCalGas redeemed all outstanding shares
of its 7 3/4% Series Preferred Stock at a cost of $25.09 per share,
or $75.3 million including accrued dividends.
Dividends
Common stock dividends in 1997, 1996 and 1995 amounted to
approximately $300 million each year.
Capitalization
The debt to capitalization ratio was 54% at year-end 1997, up from
50% in 1996. The increase was due to the issuance of SDG&E's Rate
Reduction Bonds.
The debt to capitalization ratio decreased to 50% in 1996 from
52% in 1995 due to the repayment of debt.
Cash and Cash Equivalents
Cash and cash equivalents were $814 million at December 31, 1997.
This cash is available for investment in energy-related domestic
and international projects, the retirement of debt, and other
corporate purposes.
The Company anticipates that cash required in 1998 for capital
expenditures, dividends, debt payments and merger-related costs
will be provided by cash generated from operating activities and
existing cash balances.
In addition to cash from ongoing operations the Company has
credit agreements that permit term borrowing of up to $1.3 billion,
of which none is outstanding. For further discussion, see Note 5
of the notes to supplemental consolidated financial statements.
Results of Operations
1997 Compared to 1996
Net income for 1997 increased to $432 million, or $1.83 per share
of common stock, compared to net income of $427 million, or $1.77
per share, in 1996. The increase in net income per share is due
primarily to the repurchases of common stock, which caused the
weighted average number of shares of common stock outstanding to
decrease 2% in 1997. The increase in net income is primarily due
to increased net income from utility operations partially offset by
costs related to the business combination and the start up of
unregulated operations. Numerous offsetting factors affected the
comparison of the utilities' net income in the two years: lower
than authorized operating and maintenance expenses, performance
awards at SDG&E, increased throughput of natural gas to utility
electric generation (UEG) customers, lower authorized margins, the
implementation of performance-based ratemaking at SoCalGas, and
favorable litigation settlements in 1996.
Book value per share increased to $12.56 from $12.21, due to
net income earned in 1997, net of common dividends and the stock
repurchases.
1996 Compared to 1995
Net income for 1996 increased to $427 million, or $1.77 per share
of common stock, compared to net income of $401 million, or $1.67
per share in 1995.
The increase in net income per share is due to repurchases of
common stock and the increase in net income. The increase in net
income is due to numerous, partially offsetting factors, including
performance awards, lower than authorized operating and maintenance
expenses, reduced interest expense, the favorable litigation
settlements, reductions in authorized rates of return, costs of the
business combination, and increases in certain administrative and
general expenses.
Book value per share increased to $12.21 in 1996 from $11.70 in
1995. The increase primarily was due to net income earned in 1996,
net of common dividends.
Utility Operations
To understand the operations and financial results of SoCalGas and
SDG&E operations, it is important to understand the ratemaking
procedures that SoCalGas and SDG&E follow.
SoCalGas and SDG&E are regulated by the CPUC. It is the
responsibility of the CPUC to determine that utilities operate in
the best interest of their customers and have the opportunity to
earn a reasonable return on investment. In response to utility-
industry restructuring, SoCalGas and SDG&E have received approval
from the CPUC for performance-based regulation (PBR).
PBR replaces the general rate case (GRC) procedure and certain
other regulatory proceedings. Under ratemaking procedures in
effect prior to PBR, SoCalGas and SDG&E typically filed a GRC with
the CPUC every three years. In a GRC, the CPUC establishes a base
margin, which is the amount of revenue to be collected from
customers to recover authorized operating expenses (other than the
cost of fuel, natural gas and purchased power), depreciation, taxes
and return on rate base.
Under PBR, regulators allow income potential to be tied to
achieving or exceeding specific performance and productivity
measures, rather than relying solely on expanding utility rate base
in a market where a utility already has a highly developed
infrastructure. See additional discussion of PBR in Note 13 of the
notes to supplemental consolidated financial statements.
In September 1996 the state of California enacted a law
restructuring California's electric-utility industry. The
legislation adopts the December 1995 CPUC policy decision
restructuring the industry to stimulate competition and reduce
rates. Beginning on March 31, 1998, customers may buy their
electricity through a power exchange that obtains power from
qualifying facilities, nuclear units and, lastly, from the lowest-
bidding suppliers. The power exchange serves as a wholesale power
pool allowing all energy producers to participate competitively.
See additional discussion of electric-industry restructuring in
Note 13 of the notes to supplemental consolidated financial
statements.
1995-1997 Financial Results
Key financial data for utility operations are highlighted in the
following table:
Year Ended December 31,
(Dollars in millions) 1997 1996 1995
- -------------------------------------------------------------------
Operating revenues:
Gas $ 2,964 $ 2,710 $ 2,542
Electric $ 1,769 $ 1,591 $ 1,504
Cost of gas $ 1,168 $ 958 $ 747
Purchased power $ 441 $ 311 $ 342
Operating expenses $ 1,190 $ 1,197 $ 1,225
Income from operations $ 1,038 $ 949 $ 951
- -------------------------------------------------------------------
The table below summarizes the components of utility gas and electric
volumes and revenues by customer class for the past three years.
Gas Sales, Transportation & Exchange
(Dollars in millions, volumes in billion cubic feet)
Gas Sales Transportation & Exchange Total
---------------------------------------------------------------
Throughput Revenue Throughput Revenue Throughput Revenue
---------------------------------------------------------------
1997:
Residential 268 $1,957 3 $ 10 271 $1,967
Commercial/Industrial 102 617 332 273 434 890
Utility Generation 49 14 158 76 207 90
Wholesale 18 12 18 12
--------------------------------------------------------------
419 $2,588 511 $371 930 2,959
Balancing and Other 5
------
Total Operating Revenues $2,964
- --------------------------------------------------------------------------------
1996:
Residential 264 $1,809 3 $ 10 267 $1,819
Commercial/Industrial 104 573 314 257 418 830
Utility Generation 43 9 139 70 182 79
Wholesale 17 10 17 10
--------------------------------------------------------------
411 $2,391 473 $347 884 2,738
Balancing and Other (28)
------
Total Operating Revenues $2,710
- --------------------------------------------------------------------------------
1995:
Residential 268 $1,746 2 $ 7 270 $1,753
Commercial/Industrial 118 637 284 228 402 865
Utility Generation 39 9 205 104 244 113
Wholesale 4 7 17 9 21 16
---------------------------------------------------------------
429 $2,399 508 $348 937 2,747
Balancing and Other (205)
------
Total Operating Revenues $2,542
- --------------------------------------------------------------------------------
Electric Distribution
(Dollars in millions, volumes in millions of Kwhrs)
1997 1996 1995
---------------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
Residential 6,125 $ 684 5,936 $ 647 5,736 $ 635
Commercial 6,940 680 6,467 625 6,248 614
Industrial 3,607 268 3,567 261 3,466 260
Other 4,995 137 725 58 467 (5)
--------------------------------------------------------------
Total 21,667 $1,769 16,695 $1,591 15,917 $1,504
- --------------------------------------------------------------------------------
1997 Compared to 1996
Utility gas revenues increased 9 percent in 1997 compared to 1996
primarily due to an increase in the average unit cost of gas, which
is recoverable in rates. To a lesser extent, the increase was also
due to increased throughput to UEG customers due to increased
demand for electricity. The increase was partially offset by an
increase in customer purchases of gas directly from other
suppliers.
Utility electric revenues increased 11 percent in 1997 compared
to 1996 primarily due to an increase in sales for resale to other
utilities and increased retail sales volume due to weather.
Utility cost of gas distributed increased 22 percent in 1997
compared to 1996 largely due to an increase in the average cost of
gas purchased, excluding fixed pipeline charges, and increases in
sales volume.
Purchased power increased 42 percent in 1997 compared to 1996,
primarily due to increased volume, which resulted from lower
nuclear-generation availability due to refuelings at the San Onofre
Nuclear Generating Station (SONGS) and increased use of purchased
power due to decreased purchased-power prices.
Utility operating expenses decreased 1 percent in 1997 compared
to 1996 primarily due to the Company's continued emphasis on
reducing costs and higher 1996 costs for service to electric
customers. The extent of this reduction was partially offset by
reduced costs in 1996 from favorable litigation settlements.
Income from operations increased 9 percent in 1997 compared to
1996 primarily due to incentive awards for PBR and Demand Side
Management (DSM) programs at SDG&E and increased throughput to
SoCalGas UEG customers, lower operating and maintenance expenses
than amounts authorized in rates, and a nonrecurring non-cash
charge of $26.6 million, after-tax, in 1996, partially offset by a
lower margin established in the SoCalGas PBR decision. The non-cash
charge of $26.6 million at SoCalGas in 1996 was the result of
continuing developments in the CPUC's restructuring of the
electric-utility industry. The charge was due to SoCalGas'
anticipating that throughput to noncore UEG customers would be
below the levels projected in 1993 at the time of the Comprehensive
Settlement (see Note 2 of notes to supplemental consolidated
financial statements). Consequently, SoCalGas believed it would not
realize the remaining revenue enhancements that were applied to
offset the costs of the Comprehensive Settlement. In connection
with the 1992 quasi-reorganization, a liability was recorded at PE
(but not at SoCalGas) for this issue and, therefore, this charge
had no effect on consolidated net income.
1996 Compared to 1995
Utility gas revenues increased 7 percent in 1996 compared to 1995.
The increase was primarily due to an increase in the cost of gas,
which is recoverable in revenues subject to the Gas Cost Incentive
Mechanism (GCIM.) The increase in revenue was also generated by
demand from refinery customers. The increase in revenue was
partially offset by a decrease in UEG revenues due to a reduction
in volumes transported because of abundant, inexpensive hydro-
electricity.
Utility electric revenues increased 6 percent in 1996 compared
to 1995 primarily due to the accelerated recovery of SONGS Units 2
and 3 which commenced in April 1996.
Utility cost of gas distributed increased 28 percent in 1996
compared to 1995, due primarily to an increase in the average unit
cost of gas.
Purchased power decreased 9 percent in 1996 compared to 1995,
reflecting the availability of lower-cost nuclear generation and
decreases in purchased-power capacity charges.
Utility operating expenses decreased 2 percent in 1996 compared
to 1995. The decrease was primarily due to the nonrecurring
favorable settlements from gas producers and environmental
insurance claims, and also reflects savings from continued
improvements in efficiency and management's close control of
expenses. This was partially offset by higher costs for customer
service at SDG&E.
Income from operations decreased less than 1 percent in 1996
compared to 1995, primarily due to the $26.6 million charge
previously mentioned offset by the effects of the nonrecurring
favorable settlements and lower operating costs.
Factors Influencing Future Performance
Performance of the Company in the near future will depend primarily
on the results of SDG&E and SoCalGas. Because of the ratemaking and
regulatory process, electric- and gas-industry restructurings, and
the changing energy marketplace, there are several factors that
will influence future financial performance. These factors are
summarized below.
Electric Industry Restructuring. As discussed above, the state of
California in September 1996 enacted a law restructuring
California's electric utility industry (AB 1890). An Independent
System Operator (ISO) schedules power transactions and access to
the transmission system. Consumers also may choose tariffs or may
enter into private contracts with generators, brokers and others.
The local utility continues to provide distribution service
regardless of which source the consumer chooses.
Transition Costs. Both the CPUC decision and the California
legislation allow utilities, within certain limits, the opportunity
to recover their stranded costs incurred for certain above-market
CPUC-approved facilities, contracts and obligations through the
establishment of a nonbypassable competition transition charge
(CTC). The CPUC's direction is that traditional cost-of-service
regulation will move toward performance-based regulation.
Utilities are allowed a reasonable opportunity to recover their
stranded costs through December 31, 2001. Stranded costs such as
those related to reasonable employee-related costs directly caused
by restructuring and purchased-power contracts (including those
with qualifying facilities) may be recovered beyond 2001. Outside
of those exceptions, stranded costs not recovered through 2001 will
not be collected from customers. Such costs, if any, would be
written off as a charge against earnings.
SDG&E's transition-cost application, filed in October 1996,
identifies costs totaling $2 billion (net present value in 1998
dollars). These identified transition costs were determined to be
reasonable by independent auditors selected by the CPUC, with $73
million requiring further action before being deemed recoverable
transition costs. Of this amount, the CPUC has excluded from
transition cost recovery $39 million in fixed costs relating to gas
transportation to power plants, which SDG&E believes will be
recovered through contracts with the ISO. Total transition costs
include sunk costs, as well as ongoing costs the CPUC finds
necessary to maintain generation facilities through December 31,
2001. Both AB 1890 and the related CPUC policy decision provide
that above-market costs for existing purchased-power contracts may
be recovered over the terms of the contracts or sooner.
Qualifying-facilities purchases include approximately 100 existing
contracts, which extend as far as 2025. Other power purchases
consist of two long-term contracts expiring in 2001 and 2013.
Transition costs also include other items SDG&E has accrued under
cost-of-service regulation. Nuclear decommissioning costs are
nonbypassable until fully recovered, but are not included as part
of transition costs.
Through December 31,1997, SDG&E has recovered transition costs of
$0.2 billion for nuclear generation and $0.1 billion for nonnuclear
generation. Additionally, overcollections of $0.1 billion recorded
in the Energy Cost Adjustment Clause (ECAC) and the Electric
Revenue Adjustment Mechanism (ERAM) balancing accounts as of
December 31, 1997, have been applied to transition cost recovery,
leaving approximately $1.6 billion for future recovery. Included
therein is $0.4 billion for post-2001 purchased-power-contract
payments that may be recovered after 2001, subject to an annual
reasonableness review.
SDG&E has announced a plan to auction its power plants and other
electric-generating assets. This plan includes the divestiture of
SDG&E's fossil power plants and combustion turbines, its 20-percent
interest in SONGS and its portfolio of long-term purchased-power
contracts. The power plants, including the interest in SONGS, have
a net book value as of December 31, 1997, of $800 million ($200
million for fossil and $600 million for SONGS). The proceeds from
the auction will be applied directly to SDG&E's transition costs.
In December 1997, SDG&E filed with the CPUC for its approval of the
auction plan. During the 1998 - 2001 period, recovery of
transition costs is limited by the rate freeze (discussed below).
Management believes that the rates within the rate cap and the
proceeds from the sale of electric-generating assets will be
sufficient to recover all of SDG&E's approved transition costs by
December 31, 2001, not including the post-2001 purchased-power
contracts payments that may be recovered after 2001. However, if
the proceeds from the sale of the power plants are less than
anticipated, SDG&E may be unable to recover all of its approved
transition costs. This would result in a charge against earnings
at the time it becomes probable that SDG&E will be unable to
recover all of the transition costs.
The California legislation provides for a 10-percent reduction of
residential and small commercial customers' rates, which began in
January 1998, as a result of the utilities' receiving the proceeds
of rate-reduction bonds issued by an agency of the state of
California. In December 1997, $658 of rate-reduction bonds were
issued on behalf of SDG&E 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 nonbypassable
charge on their electricity bills. In September 1997, SDG&E and
the other California investor-owned utilities (IOUs) received a
favorable ruling by the Internal Revenue Service on the tax
treatment of the bond transaction. The ruling states, among other
things, that the receipt of the bond proceeds does not result in
gross income to SDG&E at the time of issuance, but rather the
proceeds are taxable over the life of the bonds. The Securities
and Exchange Commission determined that these bonds should be
reflected on the utilities' balance sheets as debt, even though the
bonds are not secured by, or payable from, utility assets, but
rather by the revenue streams collected from customers. SDG&E
formed a subsidiary, SDG&E Funding LLC, to facilitate the issuance
of the rate-reduction bonds. In exchange for the bond proceeds,
SDG&E sold to SDG&E Funding all of its rights to the revenue
streams. Consequently, the revenue streams are not the property of
SDG&E nor are they available to satisfy any claims of SDG&E's
creditors. There was no gain or loss recorded from the issuance of
the bonds, nor from the receipt of the proceeds. SDG&E has begun
to use a portion of the proceeds to redeem its higher-cost debt.
In December 1997, the California Supreme Court dismissed a petition
submitted by a coalition of consumer groups to overturn the CPUC's
Rate-Reduction Bond financing orders. A related coalition of
consumer groups has also put together a California ballot
initiative that, among other things, could result in an additional
10-percent rate reduction, require that this rate reduction be
achieved through the elimination or reduction of CTC payments and
prohibit the collection of the charge on customer bills that would
finance the rate reduction. SDG&E cannot predict the final
outcome of the initiative. If the initiative were to be voted into
law and upheld by the courts, the financial impact on SDG&E could
be substantial. (See Note 14 to the notes to supplemental
consolidated financial statements.)
Electric Rates. AB 1890 included a rate freeze for all customers.
Until the earlier of March 31, 2002, or when transition cost
recovery is complete, SDG&E's average system rate will be frozen at
9.64 cents per kilowatt-hour, except for the impacts of natural-gas
price changes and the mandatory 10-percent rate reduction. As a
result of significant increase in natural-gas prices during the
first quarter of 1997, SDG&E received CPUC authority to increase
rates, but rates could not be increased above 9.985 per kwh. With
the 10-percent rate reduction beginning on January 1, 1998, the
maximum system-average rate became 9.43 cents per kwh. SDG&E's
ability to recover its transition costs is dependent on its total
revenues under the rate freeze exceeding normal cost-of-service
revenues during the transition period by at least the amount of the
CTC less any proceeds from the sale of electric-generating assets
(discussed above and below). During the transition period, SDG&E
will not earn awards from special programs, such as DSM, unless
total revenues are also adequate to cover the awards. Fuel-price
volatility and the outcome of the voter initiative mentioned in the
preceding paragraph are the most significant uncertainties in the
ability of SDG&E to recover its transition costs and program
awards.
Electric Generation Assets. In November 1997, SDG&E's board of
directors approved a plan to auction the Company's power plants and
other electric-generating assets, enabling SDG&E to continue to
concentrate its business on the transmission and distribution of
electricity and natural gas as California opens its electric
utility industry to competition in 1998. The plan includes the
divestiture of SDG&E's fossil power plants - the Encina (Carlsbad,
California) and South Bay (Chula Vista, California) plants - and
its combustion turbines, as well as its 20-percent interest in
SONGS and its portfolio of long-term purchased-power contracts,
including those with qualifying facilities. The power plants,
including the interest in SONGS, have a net book value as of
December 31, 1997, of $800 million ($200 million for fossil and
$600 million for SONGS) and a combined generating capacity of 2,400
megawatts. The proceeds from the auction will be applied directly
to SDG&E's transition costs. In December 1997, SDG&E filed with
the CPUC for its approval of the auction plan. The sale of the
non-nuclear generating assets is expected to be completed by the
end of the first quarter of 1999.
Although the other California IOUs are required by the CPUC to
divest themselves of at least 50 percent of their fossil power
plants as a part of industry restructuring, SDG&E is not under the
same mandate. Other companies in the free market, not bound by the
rules that apply to the state's regulated utilities, are expected
to have a greater opportunity to provide competitive generation
services with SDG&E's plants. The FERC has ruled that it has
jurisdiction over all electricity sales into the California PX,
meaning that the buyers of divested California power plants would
qualify as wholesale power generators. The FERC's ruling has
increased the interest in the nonnuclear plants owned by the other
California IOUs, and is expected to have the same impact on SDG&E's
fossil plants.
As previously discussed, subsidiaries of the Company and of
Houston Industries have formed a joint venture (El Dorado Energy)
to build, own and operate a 480-megawatt natural-gas-fired power
plant in Boulder City, Nevada, 40 miles southeast of Las Vegas.
The joint venture plans to sell the plant's electricity into the
wholesale market to utilities throughout the western United States.
The new plant will employ an advanced combined-cycle gas-turbine
technology, enabling it to become one of the more efficient and
environmentally friendly power plants in the nation. Its proximity
to existing natural gas pipelines and electric transmission lines
will allow El Dorado to actively compete in the deregulated
electric-generation market. Construction on the $280 million
project, which will be funded 50 percent each by the Company and
Houston Industries, began in the first quarter of 1998, with an
expected operational date set for the fourth quarter of 1999.
Performance Based Regulation. Under PBR, regulators allow future
income potential to be tied to achieving or exceeding specific
performance and productivity measures, rather than relying solely
on expanding utility rate base. See additional discussion in Note
13 of the notes to supplemental consolidated financial statements.
Regulatory Accounting Standards. SoCalGas and SDG&E had been
accounting for the economic effects of regulation on all of their
utility operations in accordance with Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation." Under SFAS No. 71, a regulated
entity records a regulatory asset if it is probable that, through
the ratemaking process, the utility will recover the asset from
customers. Regulatory liabilities represent future reductions in
revenues for amounts due to customers.
The SEC indicated a concern that the California IOUs may not
meet the criteria of SFAS No. 71 with respect to their electric-
generation net regulatory assets. SDG&E has ceased the application
of SFAS No. 71 to its generation business, in accordance with the
conclusion by the Emerging Issues Task Force of the Financial
Accounting Standards Board that the application of SFAS No. 71
should be discontinued when legislation is issued that determines a
portion of an entity's business will no longer be regulated.
SDG&E's discontinuance of SFAS No. 71 applied to its generation
business will not result in a write-off of its net regulatory
assets, since the CPUC has approved the recovery of these assets by
the distribution portions of its business, subject to the rate
freeze.
Affiliate Transaction Decision. On December 16, 1997, the CPUC
adopted rules establishing uniform standards of conduct governing
the manner in which California IOUs conduct business with their
affiliates providing energy or energy-related services within
California. The objective of these rules, effective January 1,
1998, is to ensure that the utilities' energy affiliates do not
gain an unfair advantage over other competitors in the marketplace
and that utility customers do not subsidize affiliate activities.
For further discussion of the key elements of the CPUC decision,
see Note 13 of the notes to supplemental consolidated financial
statements.
Although utility-to-utility transactions are also included
under the definition of an affiliate transaction, the CPUC, in the
business-combination proceeding, generally exempted transactions
between SoCalGas and SDG&E from these affiliate transaction rules.
As a result, the affiliate transaction rules will not substantially
impact the Company's ability to achieve anticipated synergy
savings.
Allowed Rate of Return. For 1998, SoCalGas is authorized to earn a
rate of return on rate base of 9.49% and a rate of return on common
equity of 11.60%, which is unchanged from 1997. SDG&E is
authorized to earn a rate of return on rate base of 9.35% and a
rate of return on common equity of 11.60%, also unchanged from
1997.
Management Control of Expenses and Investment. In the past,
management has been able to control operating expenses and
investment within the amounts authorized to be collected in rates.
It is the intent of management to control operating expenses
and investments within the amounts authorized to be collected in
rates in the PBR decision. SoCalGas intends to make the efficiency
improvements, changes in operations and cost reductions necessary
to achieve this objective and earn its authorized rate of return.
However, in view of the earnings-sharing mechanism and other
elements of the PBR, it will be more difficult for SoCalGas to
achieve returns in excess of authorized returns at levels that it
has experienced in 1997 and other recent years.
Gas Industry Restructuring. The gas industry experienced an initial
phase of restructuring during the 1980s by deregulating gas sales
to noncore customers. On January 21, 1998, the CPUC released a
staff report initiating a project to assess the current market and
regulatory framework for California's natural-gas industry. The
general goals of the plan are to consider reforms to the current
regulatory framework emphasizing market-oriented policies
benefiting California natural-gas consumers.
Noncore Bypass. SoCalGas' throughput to enhanced oil recovery (EOR)
customers in the Kern County area has decreased significantly since
1992 because of the bypass of SoCalGas' system by competing
interstate pipelines. The decrease in revenues from EOR customers
did not have a material impact on SoCalGas' earnings.
Bypass of other markets also may occur, and SoCalGas is fully
at risk for a reduction in non-EOR, noncore volumes due to bypass.
However, significant additional bypass would require construction
of additional facilities by competing pipelines. SoCalGas is
continuing to reduce its costs to maintain cost competitiveness to
retain transportation customers.
Noncore Pricing. To respond to bypass, SoCalGas has received
authorization from the CPUC for expedited review of long-term gas-
transportation service contracts with some noncore customers at
lower-than-tariff rates. In addition, the CPUC approved changes in
the methodology that eliminates subsidization of core-customer
rates by noncore customers. This allocation flexibility, together
with negotiating authority, has enabled SoCalGas to better compete
with new interstate pipelines for noncore customers.
Noncore Throughput. SoCalGas' earnings may be adversely impacted if
gas throughput to its noncore customers varies from estimates
adopted by the CPUC in establishing rates. There is a continuing
risk that an unfavorable variance in noncore volumes may result
from external factors such as weather, electric deregulation, the
increased use of hydro-electric power, competing pipeline bypass of
SoCalGas' system and a downturn in general economic conditions. In
addition, many noncore customers are especially sensitive to the
price relationship between natural gas and alternate fuels, as they
are capable of readily switching from one fuel to another, subject
to air-quality regulations. SoCalGas is at risk for the lost revenue.
Through July 31, 1999, any favorable earnings effect of higher
revenues resulting from higher throughput to noncore customers has
been limited as a result of the Comprehensive Settlement (see Note
2 of the notes to supplemental consolidated financial statements).
Excess Interstate Pipeline Capacity. Existing interstate pipeline
capacity into California exceeds current demand by over one billion
cubic feet (Bcf) per day. This situation has reduced the market
value of the capacity well below the Federal Energy Regulatory
Commission's (FERC) tariffs. SoCalGas has exercised its step-down
option on both the El Paso and Transwestern systems, thereby
reducing its firm interstate capacity obligation from 2.25 billion
cubic feet (Bcf) per day to 1.45 Bcf per day.
FERC-approved settlements have resulted in a reduction in the
costs that SoCalGas possibly may have been required to pay for the
capacity released back to El Paso and Transwestern that cannot be
remarketed. Of the remaining 1.45 Bcf per day of capacity,
SoCalGas' core customers use 1.05 Bcf per day at the full FERC
tariff rate. The remaining 0.4 Bcf per day of capacity is marketed
at significant discounts. Under existing regulation in California,
unsubscribed capacity costs associated with the remaining 0.4 Bcf
per day are recoverable in customer rates. While including the
unsubscribed pipeline cost in rates may impact the Company's
ability to compete in highly contested markets, the Company does
not believe its inclusion will have a significant impact on volumes
transported or sold.
Environmental Matters
The Company's operations are conducted in accordance with federal,
state and local environmental laws and regulations governing
hazardous wastes, air and water quality, land use, and solid-waste
disposal. These costs of compliance are normally recovered in
customer rates. Whereas it is anticipated that the environmental
costs associated with the natural-gas operations will continue to
be recoverable in rates, the restructuring of the California
electric utility industry (see "Electric Industry Restructuring"
above) will change the way utility electric rates are set and costs
associated with electric generation are recovered. Capital costs
related to environmental regulatory compliance for electric
generation are intended to be included in transition costs for
recovery through 2001. However, depending on the final outcome of
the electric-industry restructuring and the impact of competition,
the costs of compliance with future environmental regulations
associated with the Company's electric generation operations may
not be fully recoverable in rates.
Capital expenditures to comply with environmental laws and
regulations were $5 million in 1997, $9 million in 1996 and $7
million in 1995, and are expected to aggregate $65 million over the
next five years. These projected expenditures primarily include
the estimated cost of reducing air emissions by retrofitting power
plants, which SDG&E has expressed, in November 1997, an intent to
auction. Additional information on SDG&E's plant to divest its
electric-generating assets is discussed in Note 12 of the notes to
supplemental consolidated financial statements.
Hazardous Wastes. In 1994, the CPUC approved the Hazardous Waste
Collaborative, which allows utilities to recover cleanup costs of
hazardous waste contamination at sites where the utility may have
responsibility or liability under the law to conduct or participate
in any required cleanup. In general, utilities are allowed to
recover 90 percent of their cleanup costs and any related costs of
litigation with responsible parties. SDG&E has asked the CPUC to
exclude, beginning January 1, 1998, cleanup costs related to
electric-generation activities from the hazardous waste memorandum
account since these costs are intended to be eligible for
transition cost recovery. A CPUC decision is still pending.
Because of current and expected rate recovery, management does not
believe that compliance with these laws will significantly impact
the Company's financial statements.
Electric and Magnetic Fields (EMFs). Although scientists continue
to research the possibility that exposure to EMFs causes adverse
health effects, science, to date, has not demonstrated a cause-and-
effect relationship between adverse health effects and exposure to
the type of EMFs emitted by utilities' power lines and other
electrical facilities. Some laboratory studies suggest that such
exposure creates biological effects, but those effects have not
been shown to be harmful. The studies that have most concerned the
public are epidemiological studies, some of which have reported a
weak correlation between childhood leukemia and the proximity of
homes to certain power lines and equipment. Other epidemiological
studies found no correlation between estimated exposure and any
disease. Scientists cannot explain why some studies using
estimates of past exposure report correlations between estimated
EMF levels and disease, while others do not.
To respond to public concerns, the CPUC has directed California
utilities to adopt a low-cost EMF-reduction policy that requires
reasonable design changes to achieve noticeable reduction of EMF
levels that are anticipated from new projects. However, consistent
with the major scientific reviews of the available research
literature, the CPUC has indicated that no health risk has been
identified.
Air Quality. During 1996 and 1997, SDG&E installed equipment on
South Bay Unit 1 to comply with the nitrogen oxide emission limits
that the San Diego Air Pollution Control District imposed on
electric-generating boilers through its Rule 69. The estimated
capital costs for compliance with this rule through 2005 are $60
million. The California Air Resources Board has expressed concern
that Rule 69 does not meet the requirements of the California Clean
Air Act and may advocate or propose more restrictive emissions
limitations which will likely cause SDG&E's Rule 69 compliance
costs to increase.
Water Quality. Increasingly stringent cooling-water and wastewater
discharge limitations may be imposed by the Regional Water Quality
Control Board (RWQCB) upon SDG&E's ability to discharge its cooling
water and certain other wastewaters from its Encina and South Bay
power plants into the Pacific Ocean and the San Diego Bay. As a
result, SDG&E may be required to build additional facilities or
modify existing facilities to comply with these requirements. Such
facilities could include wastewater-treatment facilities, cooling
towers or offshore-discharge pipelines. Any required construction
could involve substantial expenditures, and certain plants or units
may be unavailable for electric generation during construction.
In 1981, SDG&E submitted a demonstration study in support of its
request for two exceptions to certain thermal discharge
requirements imposed by the California Thermal Plan for Encina
power plant Unit 5. In November 1994, the RWQCB issued a new
discharge permit, subject to the results of certain additional
thermal-discharge and cooling-water-related studies, to be used in
considering SDG&E's earlier thermal-discharge exception requests.
The results of these additional studies were submitted to the RWQCB
and the United States Environmental Protection Agency in 1997. If
SDG&E's exception requests are denied, SDG&E could be required to
construct off-shore discharge facilities at a cost of $75 million
to $100 million or to perform mitigation, the costs of which may be
significant.
During 1997, SDG&E evaluated whether any remediation activities may
be required at the power plants based on available records and
other information. In addition, SDG&E evaluated whether
remediation is required at its Silvergate plant, which was shut
down in 1984. As a result of these evaluations, only minor and
localized remediation efforts were required. However, these
evaluations did not include an extensive sampling and analysis of
the property at such sites. Extensive sampling and analysis may
identify additional contamination or other environmental conditions
requiring mediation.
As previously discussed, in December 1997, SDG&E filed an
application with the CPUC to divest its electric-generating assets,
including its Encina and South Bay power plants, gas combustion
turbines and its interest in SONGS. As a part of the sale of any
such facilities, SDG&E will complete an environmental baseline
analysis of such sites, which may identify significant
contamination or other environmental conditions requiring abatement
or remediation.
In connection with the issuance of operating permits, SDG&E reached
agreement with the California Coastal Commission to mitigate the
environmental damage to the marine environment attributed to the
cooling-water discharge from SONGS Units 2 and 3. This mitigation
program includes an enhanced fish-protection system, a 150-acre
artificial reef and restoration of 150 acres of coastal wetlands.
In addition, plant owners must deposit $3.6 million with the state
for the enhancement of marine fish hatchery programs and pay for
monitoring and oversight of the mitigation projects. SDG&E's share
of the cost is estimated to be $23 million. The pricing structure
contained in the CPUC's decision regarding accelerated recovery of
SONGS Units 2 and 3 likely will accommodate most of these added
mitigation costs.
Effect of Increasingly Stringent Environmental Laws On Natural Gas
Customers. The environmental laws and regulations regarding
natural gas affect the operations of customers as well the
Company's regulated natural-gas entities. Increasingly complex
administrative and reporting requirements of environmental agencies
applicable to commercial and industrial customers utilizing natural
gas are not generally required of those using electricity.
However, anticipated advancements in natural-gas technologies are
expected to enable gas equipment to remain competitive with
alternate energy sources. For further discussion of environmental
matters, see Note 6 of the notes to supplemental consolidated
financial statements.
International Operations
The Company has participated in the international natural-gas
infrastructure market since March 1995.
On August 12, 1996, the Company and its partner were awarded
Mexico's first privatization license, allowing the consortium to
build and operate a natural-gas-distribution system in Mexicali,
Baja California. The franchise was awarded to Distribuidora de Gas
Natural de Mexicali S. de R.L. de C.V. (DGN), a Mexican company
formed by the Company and its partner. DGN will invest
approximately $20 million to $25 million during an initial five-
year period to provide service to more than 25,000 commercial,
industrial and residential users. In August 1997, the system began
distributing natural gas primarily to commercial customers in
Mexicali, and by December daily throughput reached 5.3 million
cubic feet.
In 1997, DGN was awarded a license to build and operate a
natural-gas pipeline in Chihuahua, a city of almost 630,000 people
in northern Mexico. DGN began construction in late 1997 and will
invest $50 million in the first five years of operation.
The Company is the majority partner in both ventures. It has
minority partners in other projects in Latin America and the
Pacific Rim and is evaluating additional ventures in these areas.
International operations are not expected to be profitable in 1998.
Other Operations
Other operations include holding company operations, Sempra Energy
Solutions and Pacific Interstate Company.
The holding company provides support services to its
subsidiaries and joint ventures. Its expenses included merger-
related costs of $25 million and $10 million, after-tax, for 1997
and 1996, respectively. Merger costs primarily consist of
investment banking, legal, regulatory and consulting fees. Merger
costs for 1997 include a $4 million after-tax loss on the sale of
the small electric generating facilities. The net investment in
these assets was $77 million at June 30, 1997, the effective date
of the sale.
Sempra Energy Solutions, established in 1997, primarily focuses
on providing new energy products and services, and marketing
natural gas.
Pacific Interstate Company (PIC), an interstate pipeline
subsidiary, purchases gas from producers in Canada and from federal
waters offshore California and transports it for sale to SoCalGas
and others. Of the gas purchased by PIC, 90% was sold to SoCalGas
in 1997. These deliveries accounted for approximately 29% of the
total volume of gas purchased by SoCalGas and approximately 10% of
SoCalGas' throughput.
Other Income, Interest Expense and Income Taxes
Other Income
Other income, which primarily consists of interest income from
short-term investments and regulatory accounts receivable balances,
increased in 1997 to $58 million from $28 million in 1996. The
increase was due to higher interest from short-term investments
during much of 1997 because foreign investments were lower than
anticipated.
Other income decreased in 1996 to $28 million from $35 million
in 1995. Short-term investment income decreased due to unusually
high short-term investments in 1995 as a result of overcollected
gas costs that were refunded to customers in the fourth quarter of
1995, and to cash outflows for a foreign investment and the
preferred stock redemption.
Interest Expense
Interest expense for 1997 increased to $206 million from $200
million in 1996. Interest expense for 1996 decreased to $200
million from $221 million in 1995. Interest expense was reduced
from its 1995 level as a result of the lower long-term debt balance
maintained throughout 1996.
Income Taxes
Income tax expense for 1997 was $301 million, slightly greater than
the $300 million for 1996. The effective income tax rate was 41%
for 1997 and 1996. Income tax expense for 1996 increased to $300
million from $264 million in 1995. The increase was primarily due
to an increase in earnings before taxes. The effective income tax
rate was 39% for 1995.
Derivative Financial Instruments
The Company's policy is to use derivative financial instruments to
reduce exposure to fluctuations in interest rates, foreign currency
exchange rates and natural-gas prices. These financial instruments
are with major investment firms and expose the Company to market
and credit risks. At times, these risks may be concentrated with
certain counterparties, although counterparty nonperformance is not
anticipated.
The Company's regulated operations periodically enter into
interest-rate swap and cap agreements to moderate exposure to
interest-rate changes and to lower the overall cost of borrowing.
These swap and cap agreements generally remain off the balance
sheet as they involve the exchange of fixed- and variable-rate
interest payments without the exchange of the underlying principal
amounts. The related gains or losses are reflected in the income
statement as part of interest expense. The Company would be
exposed to interest-rate fluctuations on the underlying debt should
other parties to the agreement not perform. Such nonperformance is
not anticipated. At December 31, 1997, the swap transactions
associated with the regulated operations totaled $92 million. See
Note 5 of the notes to supplemental consolidated financial
statements for further information regarding these swap
transactions.
SDG&E's pension fund periodically uses foreign-currency forward
contracts to reduce its exposure to exchange-rate fluctuations
associated with certain investments in foreign equity securities.
These contracts generally have maturities ranging from three to six
months. At December 31, 1997, and 1996, there were no foreign-
currency forward contracts outstanding.
The Company's regulated operations manage natural-gas costs and
price risk associated with natural-gas requirements through the use
of energy derivatives. Subject to certain limitations imposed by
established policy, the regulated operations use energy derivatives
for both hedging and trading purposes. These derivative financial
instruments include forward contracts, futures, swaps, options and
other contracts, with maturities ranging from 30 days to 12 months.
See Note 10 of the notes to supplemental consolidated financial
statements and the "Risk Management Activities" section below for
further information regarding the use of energy derivatives by the
Company's regulated operations.
Sempra Energy Trading derives a substantial portion of its revenue
from trading activities in natural gas, petroleum and electricity.
Trading profits are earned as Sempra Energy Trading acts as a
dealer in structuring and executing transactions that permit its
counterparties to manage their risk profiles. In addition, Sempra
Energy Trading takes positions in energy markets based on the
expectation of future market conditions. These positions may be
offset either with similar positions or in the exchange-traded
markets. These positions include options, forwards, futures and
swaps. See Note 3 of the notes to supplemental consolidated
financial statements and the following "Risk Management Activities"
section for additional information regarding Sempra Energy
Trading's derivative financial instruments.
Risk Management Activities
Market Risk
Market risk, inherent in both derivative and non-derivative
financial instruments, generally represents the risk of loss that
may result from the potential change in (1) the value of a
financial instrument as a result of fluctuations in interest and
currency exchange rates and (2) equity and commodity prices. The
following is a discussion of the Company's primary market-risk
exposures as of December 31, 1997, including a discussion of how
these exposures are managed.
Interest Rate Risk
The Company is exposed to fluctuations in interest rates primarily
as a result of its fixed-rate long-term debt. The Company has
historically funded utility operations through long-term bond
issues with fixed interest rates. With the restructuring of the
regulatory process, greater flexibility has been permitted within
the debt-management process. As a result, recent debt offerings
have been selected with short-term maturities to take advantage of
yield curves or used a combination of fixed- and floating-rate
debt. Interest rate swaps, subject to regulatory constraints, may
be used to adjust interest-rate exposures when appropriate, based
upon market conditions.
A portion of the Company's borrowings are denominated in foreign
currencies, which exposes the Company to market risk associated
with exchange-rate movements. The Company's policy generally is to
hedge major foreign-currency cash exposures through swap
transactions. These contracts are entered into with major
international banks, thereby minimizing the risk of credit loss.
The Company employs a variance/covariance approach in its
calculation of Value at Risk (VaR), which measures the potential
losses in fair value or earnings that could arise from changes in
market conditions, using a 95-percent confidence level and assuming
a one-year holding period. VaR is a statistical measure that takes
into consideration historical volatilities and correlations of
market data (i.e., interest rates and currency exchange rates).
The VaR, which is the potential loss in fair value of long-term
debt with fixed interest rates, is estimated at approximately $250
million as of December 31, 1997. The VaR attributable to currency
exchange rates nets to zero as a result of a currency swap which is
directly matched to the Company's Swiss Franc debt obligation, its
only non-dollar-denominated debt.
Commodities Price Risk
Market risk related to physical commodities is based upon potential
fluctuations in natural-gas, petroleum and electricity commodity
exchange prices and basis. The Company's market risk is impacted
by changes in volatility and liquidity in the markets in which
these instruments are traded. The varying risk management
approaches adopted by the Company's subsidiaries accommodate (1)
the unique market risks to which each subsidiary is subjected; (2)
each subsidiary's unique operating environment, and (3) the
regulations to which each subsidiary is subjected.
SDG&E. SDG&E is subjected to market risk related to fluctuations
in exchange prices and basis of the following physical commodities:
natural gas, petroleum and electricity. SDG&E has adopted policies
to effectively manage each of its energy portfolios and relies upon
a variety of financial structures, products and terms to
effectively manage each portfolio's inherent market risk. Market
risk is monitored separately from the groups responsible for
creating or actively managing these risk exposures to ensure
compliance with the Company's stated risk-management policies.
SDG&E monitors its market risk on a daily basis utilizing VaR
calculations, which simulate forward price curves in the energy
markets to estimate the size and probability of future potential
losses. The quantification of market risk using VaR provides a
consistent measure of risk across diverse energy markets and
products. The use of this methodology requires a number of key
assumptions, including the selection of a confidence level for
losses and the holding period chosen for the VaR calculation.
SDG&E expresses VaR as the amount of SDG&E's earnings at risk based
on a 95 percent confidence level using a time horizon of the
average life of the portfolio. As of December 31, 1997, SDG&E's
VaR associated with its price-risk management activities was not
material to the Company's financial position. Since this is not an
absolute measure of risk under all conditions for all products,
SDG&E performs alternative scenario analyses to estimate the
economic impact of a sudden market movement on the value of the
portfolio. These analyses and the professional judgment of
experienced business and risk managers are used to supplement the
VaR methodology.
Based upon the ongoing policies and controls discussed above, SDG&E
does not anticipate a material adverse effect on its financial
position or results of operations as a result of market
fluctuations.
SoCalGas. SoCalGas is subject to price risk on its natural-gas
purchases if natural-gas costs exceed a 2% tolerance band above the
GCIM benchmark price. Price risk is influenced by physical
contract positions, financial contract positions, basis risk,
system demand, and regulation. SoCalGas becomes subject to price
risk when positions are incurred during the buying, selling and
storage of natural gas.
A Gas Acquisition Committee, composed of company officers, is
responsible for establishing natural-gas price-risk-management
objectives and strategies that are in alignment with the Price Risk
Management Policy. The committee also monitors the cost
effectiveness of natural-gas purchasing activities and ongoing
compliance with the established policies and procedures.
As part of the Price Risk Management Policy, SoCalGas has
established fixed price and basis position limits. The position
limits are established based on volumetric limits and are further
limited if the VaR calculations associated with these positions
exceeds 50% of the GCIM upper tolerance band. Volumetric limits
define the maximum position exposure each management level within
SoCalGas is authorized to accept without obtaining higher approval.
In addition to the position limits, internal controls have been
established to set individual contract limits, to monitor
established credit limits, to require current reporting of trading
activities and to facilitate a proper segregation of duties.
The VaR methodology employed by SoCalGas to estimate natural-gas
price risk is applied to physical, as well as financial, natural-
gas positions. The methodology involves determining the fair value
impact of the maximum expected adverse price change for the
aggregate net position in each forward month, using a 95%
confidence interval and assuming a one-month holding period. The
value so derived for each forward month is then aggregated to
arrive at the total VaR. In making these calculations,
volatilities are based upon the respective forward month's implied
volatility derived from quoted option prices. As of December 31,
1997, the total VaR of SoCalGas' natural-gas positions was not
material to SoCalGas' financial position.
Sempra Energy Trading. Sempra Energy Trading's market risk relates
to potential changes in the value of financial instruments based on
fluctuations in natural gas, petroleum and electricity commodity
exchange prices and basis.
A Risk Management Committee, composed of company officers, is
responsible for monitoring operating performance and compliance
with established risk-management policies. Sempra Energy Trading
has established position and stop-loss limits for each line of
business to monitor its market risk and traders are required to
maintain positions within these market-risk limits. The position
limits are monitored during the day by Sempra Energy Trading's
senior management. Based upon these and other reports, Sempra
Energy Trading's senior management determines whether to adjust its
market-risk profile.
All of Sempra Energy Trading's market-risk-sensitive instruments
are entered into for trading purposes. The following table
provides the potential changes in net principal transactions
revenues resulting from hypothetical 10-percent increases and 10-
percent decreases in the applicable commodity prices for
significant commodity market-price sensitive instruments held on
December 31, 1997. This quantitative information about market-risk
is limited because it does not take into account potential hedging
transactions or changes to the market-risk profile of the portfolio
by management in reaction to such changes in market conditions.
Additionally, it does not take into account anticipated management
reaction to breaches of counterparty credit limitations caused by
the shocks within a given risk category. Further, inherent
limitations arise from assuming that hypothetical 10-percent
increases and 10-percent decreases in commodity prices move in the
same direction, and this information does not recognize co-
movements in prices.
The following table presents the impact on Sempra Energy Trading's
net principal-transaction revenues resulting from a 10-percent
increase and 10-percent decrease in the respective December 31,
1997, commodity prices:
In thousands of dollars
- -------------------------------------------------------------------
Commodity 10% Increase 10% Decrease
- -------------------------------------------------------------------
Crude Oil and Derivatives $3,288 $(3,288)
Natural Gas (2,441) 2,441
Emission Credits (81) 81
Electricity (540) 540
- -------------------------------------------------------------------
Credit Risk
Credit risk relates to the risk of loss that would be incurred as a
result of nonperformance by counterparties pursuant to the terms of
their contractual obligations. The Company avoids concentration of
counterparties and maintains credit policies with regard to
counterparties that management believes significantly minimize
overall credit risk. These policies include an evaluation of
potential counterparties' financial condition (including credit
rating), collateral requirements under certain circumstances, and
the use of standardized agreements which allow for the netting of
positive and negative exposures associated with a single
counterparty.
The Company monitors credit risk through a credit approval process
and the assignment and monitoring of credit limits. These credit
limits are established based on risk and return considerations
under terms customarily available in the industry.
Year 2000
In 1997, the Company began a multi-year project to modify its
computer systems as necessary to ensure continued effective
operations in the year 2000 and beyond. The initial focus of the
project is on the systems that are key to customer safety, gas and
electric operations, external reporting, and billing and collection
processes. The project is expected to be completed in the spring of
1999. During 1997, the Company incurred expenses of $14 million on
the project, and expects to spend over $50 million during the life
of the project.
New Accounting Standards
In June 1997, the Financial Accounting Standards Board (FASB)
issued Statement of Financial Accounting Standards (SFAS) No. 130,
"Reporting Comprehensive Income," and SFAS No. 131, "Disclosures
about Segments of an Enterprise and Related Information." In
February 1998 the FASB issued SFAS No. 132, "Employers' Disclosures
about Pensions and Other Postretirement Benefits" and in June 1998
issued SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities." The impact on Sempra Energy of the adoption of
these new accounting standards is considered immaterial to the
company's financial statements. The Company estimates that the
primary segments upon adoption of SFAS No. 131 will be electric
operations, gas operations, energy services and other.
Information Regarding Forward Looking Statements
This Current Report on Form 8-K contains forward-looking statements
with respect to matters inherently involving various risks and
uncertainties. These statements are identified by the words
"estimates," "expects," "anticipates," "plans," "believes," and
similar expressions.
These statements are necessarily based upon various assumptions
involving judgments with respect to the future including, among
other factors, national, regional and local economic, competitive
and regulatory conditions; technological developments; inflation
and interest rates; energy markets; weather conditions; business
and regulatory decisions; and other uncertainties, all of which are
difficult to predict and most of which are beyond the control of
the Company. Accordingly, while the Company believes these
assumptions are reasonable, there can be no assurance that they
will approximate actual experience, or that the expectations will
be realized.
ITEM 6.
SEMPRA ENERGY
Supplemental Selected Financial Data
(Dollars in millions, except per share amounts)
Years Ended December 31,
---------------------------------------
1997 1996 1995 1994 1993
------- ------ ------ ------ ------
Income Statement Data
Revenues and Other Income $5,127 $4,524 $4,201 $4,539 $4,763
Income Before Interest and
Income Taxes $ 939 $ 927 $ 886 $ 867 $ 900
Net Income (a) $ 432 $ 427 $ 401 $ 359 $ 385
December 31,
---------------------------------------
1997 1996 1995 1994 1993
------- ------ ------ ------ ------
Balance Sheet Data
Total Assets $10,751 $9,762 $9,837 $9,931 $10,181
Long Term Debt $ 3,175 $2,704 $2,721 $2,889 $ 2,805
Short Term Debt (b) $ 624 $ 481 $ 485 $ 645 $ 604
Shareholders' Equity $ 2,959 $2,930 $2,815 $2,684 $ 2,542
Year Ended December 31,
---------------------------------------
1997 1996 1995 1994 1993
------- ------ ------ ------ ------
Per Share Data
Net Income Per Share of
Common Stock:
(Basic) (c) $ 1.83 $ 1.77 $ 1.67 $ 1.50 $ 1.62
(Diluted) (c) $ 1.82 $ 1.77 $ 1.67 $ 1.50 $ 1.62
Common Dividends Declared
per Share $ 1.27 $ 1.24 $ 1.22 $ 1.16 $ 0.93
Book Value per Common Share $12.56 $12.21 $11.70 $11.18 $10.60
(a) Net income amounts do not give effect to the synergies and related
cost savings of the business combination or its transaction costs.
(b) Includes bank and other notes payable, commercial paper borrowings
and long-term debt due within one year.
(c) Common share amounts give effect to the conversion of each
outstanding share of Pacific Enterprises Common Stock into 1.5038
shares of Sempra Energy Common Stock.
ITEM 8.
SEMPRA ENERGY
Supplemental Statements of Consolidated Income
Years Ended December 31,
-------------------------------
(Dollars in millions, except per share amounts) 1997 1996 1995
- -----------------------------------------------------------------------------------
Revenues and Other Income
Utility revenues:
Gas $ 2,964 $ 2,710 $ 2,542
Electric 1,769 1,591 1,504
Other operating revenues 336 195 120
Other income 58 28 35
-------- -------- --------
Total 5,127 4,524 4,201
-------- -------- --------
Expenses
Cost of gas distributed 1,168 958 747
Purchased power 441 311 342
Electric fuel 164 134 100
Operating expenses 1,615 1,405 1,393
Depreciation and decommissioning 604 587 521
Franchise payments and other taxes 178 180 182
Preferred dividends of subsidiaries 18 22 30
-------- -------- --------
Total 4,188 3,597 3,315
-------- -------- --------
Income Before Interest and Income Taxes 939 927 886
Interest 206 200 221
-------- -------- --------
Income Before Income Taxes 733 727 665
Income taxes 301 300 264
-------- -------- --------
Net Income $ 432 $ 427 $ 401
======== ======== ========
Net Income Per Share of Common Stock (Basic) $ 1.83 $ 1.77 $ 1.67
======== ======== ========
Net Income Per Share of Common Stock (Diluted) $ 1.82 $ 1.77 $ 1.67
======== ======== ========
Common Dividends Declared Per Share $ 1.27 $ 1.24 $ 1.22
======== ======== ========
See notes to supplemental consolidated financial statements.
SEMPRA ENERGY
Supplemental Consolidated Balance Sheets
December 31,
----------------
(Dollars in millions) 1997 1996
- --------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 814 $ 430
Accounts receivable - trade 633 505
Accounts and notes receivable - other 202 187
Energy trading assets 587 --
Inventories 111 113
Regulatory balancing accounts - net 297 250
Other 112 107
------- -------
Total current assets 2,756 1,592
------- -------
Regulatory assets 609 836
Nuclear decommissioning trusts 399 328
Investments and other assets 868 663
------- -------
Total investments and other assets 1,876 1,827
------- -------
Property, plant and equipment 12,040 11,835
Less accumulated depreciation
and amortization (5,921) (5,492)
------- -------
Total property, plant and
equipment - net 6,119 6,343
------- -------
Total assets $ 10,751 $ 9,762
======= =======
See notes to supplemental consolidated financial statements.
SEMPRA ENERGY
Supplemental Consolidated Balance Sheets
December 31,
-----------------
(Dollars in millions) 1997 1996
- ------------------------------------------------------------------
Liabilities
Current liabilities
Short-term debt $ 354 $ 262
Accounts payable - trade 300 407
Energy trading liabilities 557 --
Dividends and interest payable 121 109
Long-term debt due within one year 270 219
Other 604 575
------- -------
Total current liabilities 2,206 1,572
------- -------
Long-term debt
Long-term debt 3,045 2,574
Debt of Employee Stock Ownership Plan 130 130
------- -------
Total long-term debt 3,175 2,704
------- -------
Deferred credits and other liabilities
Customer advances for construction 72 77
Post-retirement benefits other than pensions 248 258
Deferred income taxes 773 818
Deferred investment tax credits 123 128
Deferred credits and other liabilities 916 996
------- -------
Total deferred credits and
other liabilities 2,132 2,277
------- -------
Preferred stock of subsidiaries 279 279
------- -------
Commitments and contingent liabilities (Note 12)
Shareholders' Equity
Common stock 1,849 1,953
Retained earnings 1,157 1,026
Less deferred compensation relating to
Employee Stock Ownership Plan (47) (49)
------- -------
Total shareholders' equity 2,959 2,930
------- -------
Total liabilities and shareholders'
equity $ 10,751 $ 9,762
======= =======
See notes to supplemental consolidated financial statements.
SEMPRA ENERGY
Supplemental Statements of Consolidated Cash Flows
Years Ended December 31,
---------------------------------
(Dollars in millions) 1997 1996 1995
- ------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 432 $ 427 $ 401
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities:
Depreciation and decommissioning 604 587 521
Deferred income taxes and investment tax credits (16) 26 29
Other - net 62 56 43
Net changes in other working capital components
(net of effects from acquisition of
Sempra Energy Trading) (164) 68 311
---------- --------- ---------
Net cash provided by operating activities 918 1,164 1,305
---------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for Property, Plant and Equipment (397) (413) (461)
Acquisition of Sempra Energy Trading,
net of cash acquired (206) -- --
Contributions to decommissioning funds (22) (22) (22)
Other - net 23 (79) 11
--------- ----------- ----------
Net cash used in investing activities (602) (514) (472)
--------- ----------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Sale of Common Stock 17 8 6
Redemption of Common Stock (122) (24) --
Redemption of Preferred Stock -- (225) (30)
Issuances of Long-Term Debt 798 304 125
Payment on Long-Term Debt (416) (459) (373)
Increase (Decrease) in Short-Term Debt 92 29 (133)
Dividends on Common Stock (301) (300) (293)
--------- ----------- ----------
Net cash provided by (used in)financing activities 68 (667) (698)
--------- ----------- ----------
Increase (Decrease) in Cash and Cash Equivalents 384 (17) 135
Cash and Cash Equivalents, January 1 430 447 312
--------- ----------- ----------
Cash and Cash Equivalents, December 31 $ 814 $ 430 $ 447
========= =========== ==========
See notes to supplemental consolidated financial statements.
SEMPRA ENERGY
Supplemental Statements of Consolidated Cash Flows
Years Ended December 31,
---------------------------------
(Dollars in millions) 1997 1996 1995
- ------------------------------------------------------------------------------------------
CHANGES IN OTHER WORKING CAPITAL COMPONENTS
(Excluding cash and cash equivalents, short-term
debt and long-term debt due within one year, and the
effects from the acquisition of Sempra Energy Trading)
Accounts and notes receivable $ (129) $ (58) $ 119
Inventories (2) 32 30
Regulatory balancing accounts 48 9 257
Other current assets 41 40 (79)
Accounts payable and other current liabilities (122) 45 (16)
-------- -------- --------
Net change in other working
capital components $ (164) $ 68 $ 311
======== ======== ========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Acquisition of Sempra Energy Trading:
Assets acquired $ 609 $ -- $ --
Cash paid (225) -- --
---------- ----------- ---------
Liabilities assumed $ 384 $ -- $ --
========== =========== =========
Real estate investments acquired $ 126 $ 97 $ 50
Cash paid -- -- (2)
---------- ----------- ---------
Liabilities assumed $ 126 $ 97 $ 48
========== =========== =========
Non-utility electric generation assets sold $ 77 $ -- $ --
Cash received (20) -- --
Loss on sale (6) -- --
---------- ----------- ---------
Note receivable obtained $ 51 $ -- $ --
========== =========== =========
See notes to supplemental consolidated financial statements.
SEMPRA ENERGY
SUPPLEMENTAL STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
Years Ended
December 31, 1997, 1996, 1995
(Dollars in millions)
Deferred
Premium on Compensation Total
Common Capital Retained Relating Shareholders'
Stock Stock Earnings to ESOP Equity
- ----------------------------------------------------------------------------------------------
Balance at 12/31/94 $1,383 $ 564 $ 791 $ (54) $2,684
Net income 401 401
Common stock dividends declared (293) (293)
Long-term incentive plan 2 2
Stock sales 6 6
Adjustment of
Quasi-reorganization 13 13
Common stock released
from ESOP 2 2
- ----------------------------------------------------------------------------------------------
Balance at 12/31/95 1,402 566 899 (52) 2,815
Net income 427 427
Common stock dividends declared (300) (300)
Long-term incentive plan 1 1
Stock sales 8 8
Stock repurchases (24) (24)
Common stock released
from ESOP 3 3
- ----------------------------------------------------------------------------------------------
Balance at 12/31/96 1,386 567 1,026 (49) 2,930
Net income 432 432
Common stock dividends declared (301) (301)
Long-term incentive plan 1 1
Stock sales 17 17
Stock repurchases (56) (66) (122)
Common stock released
from ESOP 2 2
- ----------------------------------------------------------------------------------------------
Balance at 12/31/97 $1,347 $ 502 $1,157 $ (47) $2,959
==============================================================================================
Sempra Energy is authorized to issue 750,000,000 shares of no par
value common stock. The number of common shares issued and
outstanding at December 31, 1997 and 1996 is 235,598,111 and
239,960,590, respectively. Sempra Energy is authorized to issue
50,000,000 shares of preferred stock, which may be issued in one or
more series.
See notes to supplemental consolidated financial statements.
SEMPRA ENERGY
SUPPLEMENTAL STATEMENTS OF CONSOLIDATED FINANCIAL
INFORMATION BY SEGMENTS OF BUSINESS
In millions of dollars
At December 31 or for the
years then ended 1997 1996 1995
- ---------------------------------- ----------- ----------- -----------
Revenues and Other Income (A) $ 5,127 $ 4,524 $ 4,201
=========== =========== ===========
Income (Loss) from Operations (B)
Gas utility operations $ 578 $ 492 $ 534
Electric utility operations 460 457 417
Other (99) (22) (65)
----------- ----------- -----------
Total $ 939 $ 927 $ 886
=========== =========== ===========
Depreciation and Decommissioning
Gas utility operations $ 288 $ 283 $ 270
Electric utility operations 287 279 228
Other 29 25 23
----------- ----------- -----------
Total $ 604 $ 587 $ 521
=========== =========== ===========
Expenditures for Property, Plant
and Equipment (C)
Gas utility operations $ 195 $ 239 $ 281
Electric utility operations 161 167 171
Other 41 7 9
----------- ----------- -----------
Total $ 397 $ 413 $ 461
=========== =========== ===========
Identifiable Assets
Property, plant and equipment - net
Gas utility operations $ 3,523 $ 3,617 $ 3,654
Electric utility operations 2,487 2,626 2,737
Other 109 100 69
----------- ----------- -----------
Total 6,119 6,343 6,460
----------- ----------- -----------
Inventories
Gas utility operations 53 57 84
Electric utility operations 50 47 54
Other 8 9 7
----------- ----------- -----------
Total 111 113 145
----------- ----------- -----------
Other identifiable assets
Gas utility operations 1,193 1,247 1,250
Electric utility operations 771 697 802
Other 1,958 1,183 1,163
----------- ----------- -----------
Total 3,922 3,127 3,215
----------- ----------- -----------
Other Assets 599 179 17
----------- ----------- -----------
Total Assets $ 10,751 $ 9,762 $ 9,837
=========== =========== ===========
(A) The detail to operating revenues is provided in the Statements of
Supplemental Consolidated Income. These margins arose from
interdepartmental transfers of $144 million in 1997, $111 million
in 1996 and $85 million in 1995, based on transfer pricing approved
by the California Public Utilities Commission in tariff rates.
(B) Before interest and income taxes. SDG&E corporate expenses are
allocated between electric and gas operations in accordance with
regulatory accounting requirements.
(C) Excluding allowance for equity funds used during construction.
See notes to supplemental consolidated financial statements.
REPORT OF INDEPENDENT ACCOUNTANTS
The Board of Directors
Sempra Energy
We have audited the accompanying supplemental consolidated balance
sheets of Sempra Energy and subsidiaries (the "Company") as of
December 31, 1997 and 1996, and the related supplemental
consolidated statements of income, cash flows, changes in
shareholders' equity and financial information by segments of
business for each of the three years in the period ended
December 31, 1997. These financial statements are the
responsibility of the Company's management. Our responsibility is
to express an opinion on these financial statements based on our
audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
The supplemental consolidated financial statements give retroactive
effect to the merger of Enova Corporation and Pacific Enterprises
into Sempra Energy on June 26, 1998, which has been accounted for
as a pooling of interests as described in Note 1 to the
supplemental consolidated financial statements. Generally accepted
accounting principles proscribe giving effect to a consummated
business combination accounted for by the pooling of interests
method in financial statements that do not include the date of
consummation. These financial statements do not extend through the
date of consummation; however, they will become the historical
consolidated financial statements of Sempra Energy and subsidiaries
after financial statements covering the date of consummation of the
business combination are issued.
In our opinion, the supplemental consolidated financial statements
referred to above present fairly, in all material respects, the
consolidated financial position of Sempra Energy and subsidiaries
as of December 31, 1997 and 1996, and the consolidated results of
their operations and their cash flows for each of the three years
in the period ended December 31, 1997, in conformity with generally
accepted accounting principles applicable after financial
statements are issued for a period which includes the date of
consummation of the business combination.
/S/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
San Diego, California
June 26, 1998
SEMPRA ENERGY
FOR THE YEAR ENDED DECEMBER 31, 1997.
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: BUSINESS COMBINATION
On June 26, 1998 (pursuant to an October 1996 agreement) Enova
Corporation (Enova) and Pacific Enterprises (PE) combined the two
companies into a new company named Sempra Energy. As a result of
the combination, (i) each outstanding share of common stock of
Enova converts into one share of common stock of Sempra Energy,
(ii) each outstanding share of common stock of PE converts into
1.5038 shares of common stock of Sempra Energy and (iii) the
preferred stock and preference stock of Enova's principal
subsidiary, San Diego Gas & Electric Company (SDG&E); PE; and PE's
principal subsidiary, Southern California Gas Company (SoCalGas)
remain outstanding.
The March 1998 decision of the California Public Utilities
Commission (CPUC) approving the business combination calls for the
equal sharing of the combination's net cost savings between
shareholders and customers, but only for five years rather than the
ten years sought, leaving the treatment of savings after the first
five years to a future commission decision. If the cost savings
after the first five years is fully allocated to customers, the
expected total net shareable savings would be reduced from $1.1
billion to $340 million. In addition, the decision requires, among
other things, the divestiture by SDG&E of its gas-fired generation
units (already in progress - see Note 13) and the sale (before
September 1998) by SoCalGas of its options to purchase the
California portions of the Kern River and Mojave Pipeline gas-
transmission facilities. Additional information concerning Enova/PE
joint activities is discussed in Note 3.
The combination is a tax-free transaction and is accounted for
as a pooling of interests. The corporate headquarters is located in
San Diego, California. Headquarters for SDG&E and SoCalGas, whose
names will be retained, will remain in San Diego and Los Angeles,
respectively.
Generally accepted accounting principles proscribe giving
effect to a consummated business combination accounted for by the
pooling of interests method in financial statements that do not
include the period during which consummation occurred. These
supplemental consolidated financial statements do not extend
through the date of consummation of the business combination;
however, they will become the historical consolidated financial
statements of Sempra Energy and subsidiaries when financial
statements covering the date of consummation of the business
combination are issued.
The per-share data shown on the supplemental consolidated
statements of income reflect the conversion of Enova common stock
and of PE common stock into Sempra Energy common stock, as
described above. The supplemental consolidated financial statements
are presented as if the companies were combined during all periods
included therein.
Financial statement presentation differences between Enova and
PE have been adjusted in the financial statements. Pro forma
adjustments for the periods presented were made to eliminate
intercompany transactions between Enova and PE and to reflect the
consolidation of certain subsidiaries, Sempra Energy Solutions,
Sempra Energy Trading, and two Mexican joint ventures,
Distribuidora de Gas Natural de Mexicali and Distribuidora de Gas
Natural de Chihuahua, that were previously accounted for by the
equity method on the separate books of Enova and PE. The only
significant intercompany adjustments were the eliminations of
SoCalGas' sales of natural-gas transportation and storage to SDG&E.
These sales amounted to $55 million, $60 million and $48 million in
1997, 1996 and 1995, respectively. The net effects from the
consolidation of the previously unconsolidated subsidiaries
increased Sempra Energy's total revenues and other income by $207
million for 1997 and total assets by $642 million at December 31,
1997 from the combined amounts that were separately reported in the
Enova and PE financial statements. The elimination of intercompany
sales (primarily the sales of natural-gas transportation and
storage from SoCalGas to SDG&E) reduced total revenues and other
income by $81 million, $60 million and $48 million in 1997, 1996
and 1995, respectively.
The results of operations for PE and Enova as reported as
separate companies are as follows (in millions of dollars):
Pacific Enterprises Enova
------------------------ ------------------------
1997 1996 1995 1997 1996 1995
---- ---- ---- ---- ---- ----
Revenues and
Other Income $2,777 $2,588 $2,377 $2,224 $1,996 $1,871
Net Income $ 180 $ 196 $ 175 $ 252 $ 231 $ 226
None of the future impacts resulting from combining the
operations of Enova and PE, such as the estimated cost savings
arising from the business combination, have been reflected in the
financial statements. Transaction costs (including fees for
financial advisors, attorneys, consultants, filings and printing)
have been charged to operating and maintenance expense as incurred
in accordance with Accounting Principles Board Opinion No. 16
"Business Combinations." These amounted to $15 million and $10
million for 1997 and 1996, respectively. An additional $24 million
is expected to be incurred subsequent to December 31, 1997.
NOTE 2: SIGNIFICANT ACCOUNTING POLICIES
Nature of Operations The supplemental consolidated financial
statements include Enova Corporation and Pacific Enterprises and
their subsidiaries, including SDG&E, SoCalGas, Sempra Energy
Solutions and Sempra Energy Trading.
Property, Plant and Equipment Utility plant represents the
buildings, equipment and other facilities used by SDG&E and
SoCalGas to provide gas and electric service. The cost of utility
plant includes labor, materials, contract services and related
items, and an allowance for funds used during construction. The
cost of retired depreciable utility plant, plus removal costs minus
salvage value is charged to accumulated depreciation. Information
regarding electric industry restructuring and its effect on utility
plant is included in Note 13. Combined utility plant in service by
major functional categories at December 31, 1997, are: gas
operations $6.8 billion, electric generation $1.8 billion, electric
distribution $2.3 billion, electric transmission $0.7 billion and
other electric $0.3 billion. The corresponding amounts at December
31, 1996 were essentially the same as 1997. Accumulated
depreciation and decommissioning of gas and electric utility plant
in service at December 31, 1997, are $3.3 billion and $2.6 billion,
respectively, and at December 31, 1996, were $3.2 billion and $2.2
billion, respectively. Depreciation expense is based on the
straight-line method over the useful lives of the assets or a
shorter period prescribed by the CPUC. The provisions for
depreciation as a percentage of average depreciable utility plant
(by major functional categories) in 1997 and (in 1996, 1995,
respectively) are: gas operations 4.31 (4.35, 4.33), electric
generation 8.83 (7.57, 4.04), electric distribution 4.39 (4.38,
4.36), electric transmission 3.28 (3.25, 3.21), and other electric
6.02 (5.95, 5.89). The increases for electric generation in 1997
and 1996 reflect the accelerated recovery of San Onofre Nuclear
Generating Station (SONGS) Units 2 and 3 approved by the CPUC in
April 1996.
Inventories Included in inventories at December 31, 1997, are
SDG&E's and SoCalGas' $56 million of materials and supplies ($53
million in 1996), and $47 million of natural gas and SDG&E's fuel
oil ($51 million in 1996). Materials and supplies are generally
valued at the lower of average cost or market; fuel oil and natural
gas are valued by the last-in first-out (LIFO) method.
Other Current Liabilities Included in other current liabilities at
December 31, 1997 are $81 million of accrued salaries and benefits
($65 million in 1996) and $21 million of deferred lease revenue
($33 million in 1996).
Trading Instruments Trading assets and trading liabilities are
recorded on a trade-date basis at fair value and include option
premiums paid and received, and unrealized gains and losses from
exchange-traded futures and options, over the counter (OTC) swaps,
forwards, and options. Unrealized gains and losses on OTC
transactions reflect amounts which would be received from or paid
to a third party upon settlement of the contracts. Unrealized gains
and losses on OTC transactions are reported separately as assets
and liabilities unless a legal right of setoff exists under a
master netting arrangement enforceable by law. Principal
transaction revenues are recognized on a trade-date basis and
include realized gains and losses, and the net change in unrealized
gains and losses.
Futures and exchange-traded option transactions are recorded
as contractual commitments on a trade-date basis and are carried at
fair value based on closing exchange quotations. Commodity swaps
and forward transactions are accounted for as contractual
commitments on a trade-date basis and are carried at fair value
derived from dealer quotations and underlying commodity exchange
quotations. OTC options are carried at fair value based on the use
of the valuation models that utilize, among other things, current
interest, commodity and volatility rates, as applicable. For long-
dated forward transactions, where there are no dealer or exchange
quotations, fair values are derived using internally developed
valuation methodologies based on available market information.
Where market rates are not quoted or where management deems
appropriate, current interest, commodity and volatility rates are
estimated by reference to current market levels. Given the nature,
size and timing of transactions, estimated values may differ from
realized values. Changes in the fair value are recorded currently
in income.
Allowance for Funds Used During Construction (AFUDC) The allowance
represents the cost of funds used to finance the construction of
utility plant and is added to the cost of utility plant. AFUDC also
increases income, as an offset to interest charges in the
supplemental statements of consolidated income, although it is not
a current source of cash.
Effects of Regulation SDG&E and SoCalGas accounting policies
conform with generally accepted accounting principles for regulated
enterprises and reflect the policies of the CPUC and the Federal
Energy Regulatory Commission (FERC). Interstate natural-gas
transmission subsidiaries follow accounting policies authorized by
the FERC.
SDG&E and SoCalGas have been preparing their financial
statements in accordance with the provisions of Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effects of Certain Types of Regulation," under which a regulated
utility may record a regulatory asset if it is probable that,
through the ratemaking process, the utility will recover that asset
from customers. Regulatory liabilities represent future reductions
in revenues for amounts due to customers. To the extent that
portions of SDG&E and SoCalGas operations are no longer subject to
SFAS No. 71, or recovery is no longer probable as a result of
changes in regulation or their competitive position, the related
regulatory assets and liabilities would be written off. In
addition, SFAS No. 121, "Accounting for the Impairment of Long-
Lived Assets to Be Disposed Of," affects utility plant and
regulatory assets such that a loss must be recognized whenever a
regulator excludes all or part of an asset's cost from rate base.
As discussed in Note 13, California enacted a law restructuring the
electric-utility industry. The law adopts the December 1995 CPUC
policy decision, and allows California electric utilities the
opportunity to recover existing utility plant and regulatory assets
over a transition period that ends in 2001. SDG&E has ceased the
application of SFAS No. 71 with respect to its electric-generation
business. The applicability of SFAS No. 121 continues to be
evaluated as industry restructuring progresses. Additional
information concerning regulatory assets and liabilities is
described below in "Revenues and Regulatory Balancing Accounts" and
in Note 13.
Revenues and Regulatory Balancing Accounts Revenues from utility
customers have consisted of deliveries to customers and the changes
in regulatory balancing accounts. The amounts included in
regulatory balancing accounts at December 31, 1997 represent a $355
million net receivable for SoCalGas combined with a $58 million net
payable for SDG&E. The corresponding amounts at December 31, 1996
were $285 million net receivable and $35 million net payable for
SoCalGas and SDG&E, respectively.
Previously earnings fluctuations from changes in the costs of
fuel oil, purchased energy and natural gas, and consumption levels
for electricity and the majority of natural gas were eliminated by
balancing accounts authorized by the CPUC. This is still the case
for natural-gas operations. However, as a result of California's
electric-restructuring law, beginning in 1997 overcollections
recorded in SDG&E's Energy Cost Adjustment Clause (ECAC) and
Electric Revenue Adjustment Mechanism (ERAM) balancing accounts
were transferred to the Interim Transition Cost Balancing Account
(ITCBA), which is being applied to transition cost recovery (see
Note 13). At December 31, 1997, overcollections of $130 million
were included in this account. Of this amount, $98 million of
overcollections were recorded at December 31, 1996. The elimination
of ECAC and ERAM resulted in quarter-to-quarter earnings volatility
in 1997. This earnings volatility will continue in future years.
Additional information on electric-industry restructuring is
included in Note 13.
Regulatory Assets Regulatory Assets include SDG&E's and SoCalGas'
unrecovered premium on early retirement of debt, post-retirement
benefit costs, deferred income taxes recoverable in rates and other
regulatory-related expenditures that the companies expect to
recover in future rates, excluding generation operations (discussed
above). These items are amortized as recovered in rates. The net
regulatory assets associated with SDG&E's generation operations at
December 31, 1997, were credited to the ITCBA.
Nuclear Decommissioning Liability Deferred credits and other
liabilities at December 31, 1997 include $117 million ($96 million
in 1996) of accumulated decommissioning costs associated with
SDG&E's SONGS Unit 1, which was permanently shut down in 1992.
Additional information on SONGS Unit 1 decommissioning costs is
included in Note 6.
Quasi-Reorganization and Discontinued Operations During 1993, PE
completed a strategic plan to refocus on its natural-gas utility
and related businesses. The strategy included the divestiture of
its merchandising operations and substantially all 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. Fair value
adjustments charged to common stock totaled $190 million.
Additionally, the accumulated deficit in retained earnings of $452
million at December 31, 1992 was eliminated by a reduction in the
common stock account.
In connection with the sale of its merchandising operations,
PE assumed the merchandising group's Employee Stock Ownership Plan
(ESOP) and related indebtedness (See Notes 5 and 8). In addition,
the merchandising group's buyer agreed to reimburse PE for a
portion of the ESOP quarterly debt service. In April 1994, PE
received a $65 million payment from the buyer. This payment
primarily reflected the settlement of the buyer's remaining debt
service obligation. It also canceled a warrant granted to the
company in connection with the sale of the merchandising operations
to purchase approximately 10 percent of the buyer's common stock.
Since the sale of the merchandising operations was recorded prior
to the quasi-reorganization, the settlement and resolution of other
contingencies related to the ESOP resulted in a $114 million
increase to shareholders' equity, of which $37 million was to
common stock.
Certain of the liabilities established in connection with
discontinued operations and the quasi-reorganization were favorably
resolved in 1995, including the sale of ownership in PE's
headquarters building and settlement of certain lawsuits remaining
from the oil exploration and production business. Excess reserves
of $13 million resulting from the favorable resolution of these
issues have been added to shareholders' equity. Other liabilities
will be resolved in future years. As of December 31, 1997,
management believes the provisions for these matters are adequate.
The supplemental consolidated financial statements for periods
prior to 1996 reflect Enova's June 1995 sale of Wahlco
Environmental Systems, Inc. as discontinued operations, in
accordance with Accounting Principles Board Opinion No. 30,
"Reporting the Effects of a Disposal of a Segment of Business." For
1995, income from discontinued operations (net of income taxes) was
$0.1 million (not separately disclosed on the supplemental
consolidated statement of income due to immateriality). The
components of this are summarized in the table below:
In millions of dollars 1995
- -------------------------------------------------------------------
Revenues $ 24
Loss from operations before income taxes --
Loss on disposal before income taxes (12)
Income tax benefits 12
The loss on disposal of Wahlco reflects the sale of Wahlco and
Wahlco's 1995 net operating losses prior to the sale.
Use of Estimates in the Preparation of the Financial Statements
The preparation of the supplemental consolidated financial
statements in conformity with generally accepted accounting
principles requires management to make estimates and assumptions
that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the
financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ
from those estimates.
Statements of Supplemental Consolidated Cash Flows Cash
equivalents are highly liquid investments with original maturities
of three months or less, or investments that are readily
convertible to cash.
Basis of Presentation Certain prior-year amounts have been
reclassified from the predecessor companies' classifications to
conform to the format of these financial statements.
NOTE 3: SIGNIFICANT ACQUISITIONS AND JOINT VENTURES
Sempra Energy Trading On December 31, 1997, Enova and PE completed
their acquisition (50% interest each) of Sempra Energy Trading
(then known as AIG Trading Corporation), for $225 million. The
transaction is being accounted for by the purchase method in
accordance with Accounting Principles Board Opinion No. 16,
"Business Combinations."
Sempra Energy Trading derives a substantial portion of its
revenue from market making and trading activities, as principal, in
natural gas, petroleum and electricity. It quotes bid and offer
prices to end users and to other market makers. It also earns
trading profits as a dealer by structuring and executing
transactions that permit its counterparties to manage their risk
profiles. In addition, it takes positions in energy markets based
on the expectation of future market conditions. These positions may
be offset with similar positions or may be offset in the exchange-
traded markets. These positions include options, forwards, futures
and swaps. These financial instruments represent contracts with
counterparties whereby payments are linked to or derived from
energy-market indices or on terms predetermined by the contract,
which may or may not be financially settled by Sempra Energy
Trading. For the year ended December 31, 1997, all of Sempra Energy
Trading's derivative transactions were held for trading purposes.
Market risk arises from the potential for changes in the value
of financial instruments resulting from fluctuations in natural
gas, petroleum and electricity commodity exchange prices and basis.
Market risk is also affected by changes in volatility and liquidity
in markets in which these instruments are traded.
Sempra Energy Trading also carries an inventory of financial
instruments. As trading strategies depend on both market making and
proprietary positions, given the relationships between instruments
and markets, those activities are managed in concert in order to
maximize trading profits.
Sempra Energy Trading's credit risk from financial instruments
as of December 31, 1997 is represented by the positive fair value
of financial instruments after consideration of master netting
agreements and collateral. Credit risk disclosures, however, relate
to the net accounting losses that would be recognized if all
counterparties failed completely to perform their obligations.
Options written do not expose Sempra Energy Trading to credit risk.
Exchange-traded futures and options are not deemed to have
significant credit exposure as the exchanges guarantee that every
contract will be properly settled on a daily basis.
The following table approximates the counterparty credit
quality and exposure of Sempra Energy Trading expressed in terms of
net replacement value (in millions of dollars):
Futures,
Forward and
Swap Purchased
Contracts Options Total
------------ --------- -------
Counterparty credit quality:
AAA $ 58 $ -- $ 58
AA 34 3 37
A 216 11 227
BBB 171 3 174
Below investment grade 37 2 39
Exchanges 23 1 24
---- ---- ----
$539 $ 20 $559
==== ==== ====
Financial instruments with maturities or repricing
characteristics of 180 days or less, including cash and cash
equivalents, are considered to be short-term and, therefore, the
carrying values of these financial instruments approximate their
fair values. Sempra Energy Trading's commodities owned, trading
assets and trading liabilities are carried at fair value. The
average fair values during the year, based on quarterly
observation, for trading assets and trading liabilities which are
considered financial instruments with off-balance sheet risk
approximate $620 million and $540 million, respectively. The fair
values are net of the amounts offset pursuant to rights of setoff
based on qualifying master netting arrangements with
counterparties, and do not include the effects of collateral held
or pledged.
Sempra Energy Trading had net assets of $30 million at December
31, 1997. The difference between the cost and the underlying equity
in the net assets acquired is being amortized over 15 years.
As of December 31, 1997, Sempra Energy Trading's trading assets
and trading liabilities approximate the following:
In millions of dollars
- -------------------------------------------------------------------
Trading Assets
Unrealized gains on swaps and forwards $ 497
Due from commodity clearing organization and clearing brokers 41
OTC commodity options purchased 33
Due from trading counterparties 16
- -------------------------------------------------------------------
Total $ 587
===================================================================
Trading Liabilities
Unrealized losses on swaps and forwards $ 487
Due to trading counterparties 41
OTC commodity options written 29
- -------------------------------------------------------------------
Total $ 557
===================================================================
The notional amounts of Sempra Energy Trading's financial
instruments are provided below and include a maturity profile as of
December 31, 1997, based upon the expected timing of the future
cash flows. The notional amounts do not necessarily represent the
amounts exchanged by parties to the financial instruments and do
not measure Sempra Energy Trading's exposure to credit or market
risks. The notional or contractual amounts are used to summarize
the volume of financial instruments, but do not reflect the extent
to which positions may offset one another. Accordingly, Sempra
Energy Trading is exposed to much smaller amounts potentially
subject to risk.
Within One to Five Five to Ten After
In millions of dollars One Year Years Years Ten Years Total
- --------------------------------------------------------------------------------
Forwards and
commodity swaps $3,175 $458 $90 $74 $3,797
Futures 856 189 -- -- 1,045
Options purchased 704 52 -- -- 756
Options written 592 62 -- -- 654
- --------------------------------------------------------------------------------
Total $5,327 $761 $90 $74 $6,252
================================================================================
On a pro forma basis, the results of operations for Sempra
Energy, which include Sempra Energy Trading as if it were acquired
on January 1, 1996 (rather than December 31, 1997) are summarized
as follows (unaudited, in millions of dollars, except per share
amounts):
1997 1996
---- ----
Revenues and
Other Income $ 5,175 $ 4,601
Net Income $ 419 $ 409
Earnings Per Share
(Basic) $ 1.73 $ 1.74
(Diluted) $ 1.72 $ 1.74
Sempra Energy Solutions In January 1998 Sempra Energy Solutions,
then a joint venture of PE and Enova, completed the acquisition of
CES/Way International, a leading national energy-service provider.
In September 1997 Sempra Energy Solutions formed a joint venture
with Bangor Hydro to build, own and operate a $40 million natural-
gas distribution system in Bangor, Maine. In December 1997, Sempra
Energy Solutions signed a partnership agreement with Frontier
Utilities to build and operate a $55 million natural-gas
distribution system in North Carolina.
International Gas Distribution Projects Sempra Energy
International (comprised of Enova International and Pacific
Enterprises International) and Proxima S.A. de C.V., partners in
the Mexican companies Distribuidora de Gas Natural de Mexicali and
Distribuidora de Gas Natural de Chihuahua, are the licensees to
build and operate natural-gas distribution systems in Mexicali and
Chihuahua. DGN - Mexicali will invest up to $25 million during the
first five years of the 30-year license period. DGN - Chihuahua
plans to invest $50 million in the gas-distribution project in
Chihuahua over the next five years. Sempra Energy International
owns interests of 60 and 95 percent in the Mexicali and Chihuahua
projects, respectively.
El Dorado Power Project In December 1997 Sempra Energy Resources
(formerly Enova Power Corporation) and Houston Industries Power
Generation (HIPG) formed a joint venture, El Dorado Energy, to
build, own and operate a 480-megawatt natural-gas-fired plant in
Boulder City, Nevada. Total cost of construction is expected to be
$280 million, with each company providing 50 percent of the
funding. Sempra Energy Resources and HIPG each will be responsible
for 50 percent of the plant's fuel procurement and output
marketing. Construction on the plant began in the second quarter of
1998 and is expected to be completed in the fourth quarter of 1999.
NOTE 4: SHORT-TERM BORROWINGS
At December 31, 1997 and 1996 Sempra Energy had $354 million and
$358 million, respectively, of commercial paper obligations
outstanding. Approximately $94 million of the outstanding
commercial paper in 1997 relates to the restructuring costs
associated with certain long-term gas-supply contracts under the
Comprehensive Settlement (see Note 13). The weighted average annual
interest rate of commercial paper obligations outstanding was 5.78%
and 5.36% at December 31, 1997 and 1996, respectively.
At December 31, 1996, $96 million of the commercial paper was
classified as long-term debt, since the intent was to continue to
refinance that portion of the debt on a long-term basis. No
commercial paper was classified as long-term debt at December 31,
1997.
NOTE 5: LONG-TERM DEBT AND PREFERRED STOCK
In millions of dollars
Balance at December 31,
------------------------
LONG TERM DEBT 1997 1996
----------- -----------
First mortgage bonds
5.5% due March 1, 1997 $ -- $ 25
6.5%, due December 15, 1997 -- 125
5.25%, due March 1, 1998 100 100
7.625% due June 15, 2002 80 80
6.875%, due August 15, 2002 100 100
5.75%, due November 15, 2003 100 100
6.8% due June 1, 2015 14 14
5.9% due June 1, 2018 71 71
Variable % due June 1, 2018 -- 15
5.9% due September 1, 2018 93 93
6.1% and 6.4% due September 1, 2018 and 2019 118 118
9.625% due April 15, 2020 54 100
Variable % due September 1, 2020 58 58
Variable % due September 1, 2020 17 17
5.85% due June 1, 2021 60 60
8.75%, due October 1, 2021 150 150
8.5% due April 1, 2022 44 60
8.75% due March 1, 2023 -- 25
7.375%, due March 1, 2023 100 100
7.5%, due June 15, 2023 125 125
6.875%, due November 1, 2025 175 175
Various % due December 1, 2027 250 250
----------- -----------
Total 1,709 1,961
----------- -----------
Rate-reduction bonds 658 --
----------- -----------
Debt incurred to acquire limited partnerships,
secured by real estate, at 6.8% to 9.0%,
payable annually through 2008 313 219
----------- -----------
Various unsecured obligations at 5.125%
to 8.75% due from 1997 to 2006 296 282
----------- -----------
Various unsecured obligations at fixed (5.9%)
and variable (4.3% to 5.0% at December 31,
1997) rates due from 2014 to 2023 254 229
----------- -----------
Capitalized leases 106 120
----------- -----------
Total 3,336 2,811
----------- -----------
Less:
Current portion of long-term debt 270 219
Unamortized discount on long-term debt 21 18
----------- -----------
291 237
----------- -----------
Total $ 3,045 $ 2,574
=========== ===========
Excluding capital leases, which are described in Note 12,
maturities of long-term debt, including PE's Employees Stock
Ownership Plan, are $263 million due in 1998, $325 million in 1999,
$140 million in 2000, $221 million in 2001 and $280 million in
2002. SDG&E and SoCalGas have CPUC authorization to issue an
additional $655 million in long-term debt. Although holders of
variable-rate bonds may elect to redeem them prior to scheduled
maturity, for purposes of determining the maturities listed above,
it is assumed the bonds will be held to maturity.
First Mortgage Bonds First mortgage bonds are secured by a lien on
substantially all utility plant. In addition, certain assets of the
non-utility subsidiaries are pledged as collateral for SoCalGas'
first mortgage bonds. SDG&E and SoCalGas may issue additional
first mortgage bonds upon compliance with the provisions of their
bond indentures, which provide for, among other things, the
issuance of an additional $1.5 billion of first mortgage bonds at
December 31, 1997.
During 1997, SDG&E and SoCalGas retired $252 million of first
mortgage bonds, of which $102 million (SDG&E) was retired prior to
scheduled maturity.
SDG&E first mortgage bonds totaling $249 million have
variable-interest-rate provisions. SoCalGas' first mortgage bonds
do not have variable-rate provisions. Certain first mortgage bonds
may be called at SDG&E's or SoCalGas' option. Of the remaining
bonds, $54 million are callable in the year 2000, $150 million in
2001, $237 million in 2002, and $624 million in 2003; $94 million
are non-callable.
Rate Reduction Bonds In December 1997, $658 million of rate-
reduction bonds were issued on behalf of SDG&E at an average
interest rate of 6.26 percent. These bonds were issued to
facilitate the 10-percent rate reduction mandated by California's
electric-restructuring law. These bonds are being repaid over 10
years by SDG&E's residential and small commercial customers via a
charge on their electricity bills. These bonds are secured by the
revenue streams collected from customers and are not secured by, or
payable from, utility assets.
Unsecured Debt Various long-term obligations totaling $550 million
are unsecured. During 1997, Sempra Energy issued $145 million of
unsecured debt, of which $120 million in medium-term notes were
issued by SoCalGas to finance working capital requirements.
Unsecured bonds totaling $124 million have variable-interest-rate
provisions.
Debt of Employee Stock Ownership Plan (ESOP) and Trust The Trust
covers substantially all of PE's employees and is used to partially
fund PE's retirement savings program. It has an ESOP feature and
holds approximately 2.1 million shares of PE's common stock. The
variable rate ESOP debt held by the Trust bears interest at a rate
necessary to place or remarket the notes at par. Principal is due
on November 30, 1999 and interest is payable monthly through 1999.
PE is obligated to make contributions to the Trust sufficient to
satisfy debt service requirements. As PE makes contributions to
the Trust, these contributions, plus any dividends paid on the
unallocated shares of PE's common stock held by the Trust, will be
used to repay the debt. As dividends are increased or decreased,
required contributions are reduced or increased, respectively.
Interest on ESOP debt amounted to $6 million in 1997 and 1996, and
$7 million in 1995. Dividends used for debt service amounted to $3
million in each of the years ended 1997, 1996 and 1995, and are
deductible for only federal income tax purposes.
Interest Payments Interest payments, including those applicable to
short-term borrowings, amounted to $193 million in 1997, $205
million in 1996 and $215 million in 1995.
Credit Agreements At December 31, 1997 Sempra Energy had various
multi-year credit agreements that expire between 1998 to 2000.
Credit lines totaling $700 million are available to support
commercial paper (see Note 4). Credit lines totaling $640 million
provide a committed source of medium-term and long-term borrowings.
At December 31, 1997 these bank lines of credit were unused. The
interest rates on the lines vary and are derived from formulas
based on market rates and credit ratings. Commitment fees on all
bank lines are paid on the unused portion of the lines and there
are no requirements for compensating balances.
Swap Agreements In February 1986 SoCalGas issued SFr. 100 million
of 5 1/8% bonds maturing on February 6, 1998. SoCalGas hedged the
currency exposure by entering into a swap transaction with a major
international bank. As a result, the bond issue, interest payments
and other ongoing costs were swapped for fixed annual payments.
The terms of the swap result in a U.S. dollar liability of $47
million at an interest rate of 9.725%.
SDG&E periodically enters into interest-rate swap and cap
agreements to moderate its exposure to interest-rate changes and to
lower its overall cost of borrowings. At December 31, 1997, SDG&E
had such an agreement, maturing in 2002, with underlying debt of
$45 million.
PREFERRED STOCK OF SUBSIDIARIES
Pacific Enterprises
Balance at December 31,
Call -----------------------------
In millions of dollars Price 1997 1996
-----------------------------
Preferred stock - cumulative,
no par value:
$4.75 Dividend, 200,000
shares outstanding $100.00 $ 20 $ 20
$4.50 Dividend, 300,000
shares outstanding $100.00 30 30
$4.40 Dividend, 100,000
shares outstanding $101.50 10 10
$4.36 Dividend, 200,000
shares outstanding $101.00 20 20
$4.75 Dividend, 253
shares outstanding $101.00 -- --
Unclassified, 9,199,747
shares authorized -- --
-----------------------------
Total $ 80 $ 80
=============================
Class A preferred stock - cumulative,
no par value, 5,000,000 shares authorized -- --
=============================
All or any part of every series of presently outstanding PE
preferred stock is subject to redemption at PE's option at any time
upon not less than 30 days notice, at the applicable redemption
prices for each series, together with the accrued and accumulated
dividends to the date of redemption. None of the outstanding
series of PE preferred stock has any conversion rights. At
December 31, 1995, PE had 1,100 shares of Remarketed Preferred,
Series A Stock (RP) outstanding with a liquidation preference of
$100,000 per share. In April 1996, PE exercised its option to
redeem the RP shares, in whole, at $100,000 per share plus
accumulated dividends. In connection with the redemption of the
RP, PE recorded a $2.4 million nonrecurring charge to reflect the
write-off of the original issuance underwriting discount.
SoCalGas
Balance at December 31,
--------------------------
In millions of dollars 1997 1996
- -----------------------------------------------------------------
6%, $25 par value, 28,664 shares outstanding $ 1 $ 1
6% Series A, $25 par value, 783,032
shares outstanding 19 19
Series Preferred, no par value
7.75%, $25 stated value, 3,000,000
shares outstanding 75 75
-----------------------------
$ 95 $ 95
=============================
None of SoCalGas' series of preferred stock are callable. On
February 2, 1998, SoCalGas redeemed all outstanding shares of 7.75%
Series Preferred Stock at a price per share of $25 plus $0.09 of
dividends accruing to the date of redemption. The total cost to
SoCalGas was approximately $75.3 million.
SDG&E
Balance at December 31,
-----------------------------
In millions of dollars Call
except call price Price 1997 1996
- -------------------------------------------------------------------
Not subject to mandatory
redemption
$20 par value, authorized
1,375,000 shares
5% Series, 375,000
shares outstanding $ 24.00 $ 8 $ 8
4.50% Series, 300,000
shares outstanding $ 21.20 6 6
4.40% Series, 325,000
shares outstanding $ 21.00 7 7
4.60% Series, 373,770
shares outstanding $ 20.25 7 7
Without par value
$1.70 Series, 1,400,000
shares outstanding $ 25.85 35 35
$1.82 Series, 640,000
shares outstanding $ 26.00 16 16
---------------------------
Total not subject to
mandatory redemption $ 79 $ 79
===========================
Subject to mandatory redemption
Without par value
$1.7625 Series, 1,000,000
shares outstanding $ 25.00 $ 25 $ 25
===========================
All series of SDG&E's preferred stock have cumulative preferences
as to dividends. The $20 par value preferred stock has two votes
per share on matters being voted upon by shareholders of SDG&E and
a liquidation value at par, whereas the no par value preferred
stock is nonvoting and has a liquidation value of $25 per share.
SDG&E is authorized to issue 10,000,000 shares of no par value
stock (both subject to and not subject to mandatory redemption).
Enova is authorized to issue 30,000,000 shares of no par value
stock, of which no shares were issued and outstanding at December
31, 1997. All series are currently callable except for the $1.70
and $1.7625 series (callable in 2003), and the $1.82 series
(callable November 1998). The $1.7625 series has a sinking fund
requirement to redeem 50,000 shares per year from 2003 to 2007; the
remaining 750,000 shares must be redeemed in 2008.
NOTE 6: FACILITIES UNDER JOINT OWNERSHIP
SONGS and the Southwest Powerlink transmission line are owned
jointly by SDG&E and other utilities. SDG&E's interests at December
31, 1997, are:
In millions of dollars
- -------------------------------------------------------------------
Southwest
Project SONGS Powerlink
- -------------------------------------------------------------------
Percentage ownership 20 89
Utility plant in service $1,143 $ 217
Accumulated depreciation $ 593 $ 96
Construction work in progress $ 9 $ --
SDG&E's share of operating expenses is included in the
supplemental statements of consolidated income. Each participant in
the projects must provide its own financing. The amounts specified
above for SONGS include nuclear production, transmission and other
facilities.
SONGS Decommissioning Objectives, work scope and procedures for
the future dismantling and decontamination of the SONGS units must
meet the requirements of the Nuclear Regulatory Commission, the
Environmental Protection Agency, the California Public Utilities
Code and other regulatory bodies.
SDG&E's share of decommissioning costs for the SONGS units is
estimated to be $401 million in current dollars and is based on
studies performed and updated periodically by outside consultants.
The most recent study had been performed in 1993. A new study is
underway, with results expected to be filed with the CPUC in the
fourth quarter of 1998. A new escalation methodology was utilized
to estimate the liability in 1997. This methodology was authorized
by the CPUC in its 1996 Performance-Based Ratemaking decision for
Southern California Edison (principal owner of SONGS), and
incorporates an internal rate-of-return calculation that results in
higher escalation amounts. Although electric-industry restructuring
legislation requires that stranded costs, which include SONGS plant
costs, be amortized in rates by 2001, the recovery of
decommissioning costs is allowed until the time as the costs are
fully recovered.
The amount accrued each year is based on the amount allowed by
regulators and is currently being collected in rates. This amount
is considered sufficient to cover SDG&E's share of future
decommissioning costs. The depreciation and decommissioning expense
reflected on the supplemental statements of consolidated income
includes $22 million of decommissioning expense for each of the
years 1997, 1996 and 1995.
The amounts collected in rates are invested in externally
managed trust funds. In accordance with SFAS No. 115, "Accounting
for Certain Investments in Debt and Equity Securities," the
securities held by the trust are considered available for sale and
are adjusted to market value ($399 million at December 31, 1997,
and $328 million at December 31, 1996) and shown on the
supplemental consolidated balance sheets. The fair values reflect
unrealized gains of $89 million and $50 million at December 31,
1997, and 1996, respectively. The corresponding accumulated accrual
is included on the supplemental consolidated balance sheets in
"Accumulated Depreciation and Amortization" for SONGS Units 2 and 3
and in "Deferred Credits and Other Liabilities" for Unit 1. SONGS
Unit 1 was permanently shut down in 1992.
The Financial Accounting Standards Board is reviewing the
accounting for liabilities related to closure and removal of long-
lived assets, such as nuclear power plants, including the
recognition, measurement and classification of such costs. The
Board could require, among other things, that Sempra Energy's
future balance sheets include a liability for the estimated
decommissioning costs, and a related increase in the cost of
utility plant.
Additional information regarding SONGS is included in Notes 12
and 13.
NOTE 7: INCOME TAXES
Income tax payments totaled $274 million in 1997, $268 million in
1996 and $277 million in 1995.
The components of accumulated deferred income taxes at December
31 are as follows:
In millions of dollars 1997 1996
- -------------------------------------------------------------------
Deferred tax liabilities
Differences in financial and tax
bases of utility plant $1,063 $1,170
Regulatory balancing accounts 133 95
Regulatory asset 120 135
Partnership income 21 49
Other 85 66
- -------------------------------------------------------------------
Total deferred tax liabilities 1,422 1,515
- -------------------------------------------------------------------
Deferred tax assets
Unamortized investment tax credits 89 95
Comprehensive settlement 117 90
Postretirement benefits 90 95
Other regulatory 110 93
Restructuring costs 54 46
Other 204 320
- -------------------------------------------------------------------
Total deferred tax assets 664 739
- -------------------------------------------------------------------
Net deferred income tax liability 758 776
Current portion (net asset) 15 42
- -------------------------------------------------------------------
Non-current portion (net liability) $ 773 $ 818
===================================================================
The components of income tax expense are as follows:
In millions of dollars 1997 1996 1995
- -------------------------------------------------------------------
Current
Federal $236 $183 $204
State 63 65 75
- -------------------------------------------------------------------
Total current taxes 299 248 279
- -------------------------------------------------------------------
Deferred
Federal 1 52 4
State 7 6 (14)
- -------------------------------------------------------------------
Total deferred taxes 8 58 (10)
- -------------------------------------------------------------------
Deferred investment
tax credits - net (6) (6) (5)
- -------------------------------------------------------------------
Total income tax expense $301 $300 $264
===================================================================
The reconciliation of the statutory federal income tax rate to
the effective income tax rate is as follows:
1997 1996 1995
- -------------------------------------------------------------------
Statutory federal income tax rate 35.0 % 35.0 % 35.0 %
Depreciation 7.1 6.2 5.7
State income taxes - net of
federal income tax benefit 6.7 6.2 5.9
Tax credits (5.7) (4.8) (4.2)
Equipment leasing activities (1.1) (1.4) (1.4)
Capitalized expenses not deferred (1.4) (2.1) (3.0)
Other - net 0.5 2.2 1.7
- -------------------------------------------------------------------
Effective income tax rate 41.1 % 41.3 % 39.7 %
===================================================================
NOTE 8: EMPLOYEE BENEFIT PLANS
The information presented below describes the plans of PE,
SoCalGas, Enova and/or SDG&E. In connection with the business
combination described in Note 1, certain of these plans will be
replaced or modified, and numerous participants will be
transferring from these plans to those of Sempra Energy.
Pension Plans
Both PE (of which over 90 percent of the covered employees are
employed by SoCalGas) and SDG&E have defined-benefit pension plans
which cover substantially all of their employees. Benefits are
related to the employees' years of service and compensation during
his or her last years of employment. Plan assets consist primarily
of common stocks, bonds and pooled equity funds. PE funds its plans
annually at a level which is fully deductible for federal income
tax purposes and as necessary on an actuarial basis to provide
assets sufficient to meet the benefits to be paid to plan members.
SDG&E funds its plan based on the projected unit credit actuarial
cost method. Net pension costs, in millions of dollars, consisted
of the following for the years ended December 31:
1997 1996 1995
- -------------------------------------------------------------------
Cost related to current service $ 52 $ 58 $ 41
Interest on projected benefit obligation 143 140 122
Return on plan assets (407) (293) (466)
Net amortization and deferral 217 132 317
- -------------------------------------------------------------------
Net periodic pension cost 5 37 14
Special early retirement program 13 -- 18
Regulatory adjustment -- (12) 3
- -------------------------------------------------------------------
Net cost $ 18 $ 25 $ 35
===================================================================
The plans' statuses, in millions of dollars, were as follows at
December 31:
1997 1996
- -------------------------------------------------------------------
Accumulated benefit obligation
Vested $ 1,671 $ 1,603
Non-vested 63 49
- -------------------------------------------------------------------
1,734 1,652
Effect of future salary increases 368 323
- -------------------------------------------------------------------
Projected benefit obligation 2,102 1,975
Less plan assets at fair value (2,653) (2,372)
Unrecognized net gain 737 572
Unrecognized prior service cost (60) (66)
Unrecognized transition obligation (4) (5)
Unrecognized effect of accounting change -- 1
- -------------------------------------------------------------------
Net liability $ 122 $ 105
===================================================================
The plans' major actuarial assumptions include:
1997 1996
- -------------------------------------------------------------------
Weighted average discount rate 7.00 - 7.25% 7.50%
Rate of increase in future
compensation levels 5.00% 5.00%
Expected long-term rate of
return on plan assets 8.00 - 8.50% 8.00 - 8.50%
===================================================================
The increases in the total accumulated benefit obligations and
projected benefit obligations at December 31, 1997 were due
primarily to decreases in the actuarial discount rates.
Post-Retirement Health Benefits
Both PE and SDG&E provide certain health and life insurance
benefits to qualified retirees and have implemented various
measures to control the increasing costs of these benefits. These
benefits are accrued during the employee's years of service, up to
the year of benefit eligibility. PE funds these benefits at a level
which is fully deductible for federal income tax purposes, not to
exceed amounts recoverable in rates for regulated companies, and as
necessary on an actuarial basis to provide assets sufficient to be
paid to plan participants. SDG&E's plans are generally unfunded.
The net periodic postretirement benefit cost consisted of the
following, in millions of dollars, for the years ended December 31:
1997 1996 1995
- -------------------------------------------------------------------
Cost related to current service $ 15 $ 18 $ 13
Interest on projected benefit obligation 35 36 34
Return on plan assets (58) (32) (37)
Net amortization and deferral 38 15 25
- -------------------------------------------------------------------
Net periodic postretirement benefit cost 30 37 35
Special early retirement program 2 -- --
Regulatory adjustment 12 12 13
- -------------------------------------------------------------------
Net postretirement benefit cost $ 44 $ 49 $ 48
===================================================================
A reconciliation of the plans' funded status, in millions of
dollars, at December 31 is as follows:
1997 1996
- -------------------------------------------------------------------
Accumulated postretirement benefit
obligation:
Retirees $ 234 $ 230
Fully eligible active plan participants 252 176
Other active plan participants 45 36
- -------------------------------------------------------------------
531 442
Less: plan assets at fair value,
primarily publicly traded common stocks
and pooled equity funds (363) (286)
Unrecognized prior service cost 14 78
Unrecognized net gain 66 24
- -------------------------------------------------------------------
Net postretirement benefit liability $ 248 $ 258
===================================================================
The plans' major actuarial assumptions include:
1997 1996
- -------------------------------------------------------------------
Health care cost trend rate 7.00 - 9.00% 7.00 - 10.00%
Weighted average discount rate 7.00 - 7.25% 7.50%
Rate of increase in future
compensation levels 5.00% 5.00%
Expected long-term rate of return
on plan assets 4.50 - 8.00% 4.50 - 8.00%
===================================================================
The assumed health-care-cost trend rate for 1998 and thereafter
used by PE and SDG&E is 6.5 percent and 8.25 percent, respectively.
The effect of a one-percentage-point increase in the assumed
health-care-cost trend rate for each future year is $9.8 million
(PE) and $.2 million (SDG&E) on the aggregate of the service and
interest cost components of net periodic postretirement cost for
1997 and $72.5 million (PE) and $1.6 million (SDG&E) on the
accumulated postretirement benefit obligation at December 31, 1997.
The estimated income tax rate used in the return on plan assets is
zero since the assets are invested in tax-exempt funds.
Savings Plans
Upon completion of one year of service, all employees of PE and
certain subsidiaries, and essentially all SDG&E employees, are
eligible to participate in that company's retirement savings plan
administered by bank trustees. PE employees may contribute from 1
percent to 14 percent of their regular earnings, and SDG&E
employees may contribute from 1 percent to 15 percent of their
regular earnings. The companies contribute an amount of cash or a
number of shares of the company's common stock of equivalent fair
market value which, when added to prior forfeitures, will equal 50
percent of the first 6 percent of eligible base salary contributed
by employees. The employees' contributions, at the direction of the
employees, are primarily invested in the companies' common stock,
mutual funds or guaranteed investment contracts. In 1995, 1996 and
1997, PE's contributions were partially funded by the Pacific
Enterprises Employee Stock Ownership Plan and Trust. Annual
compensation expense for the savings plans was approximately $10
million in 1997, 1996 and 1995.
Employee Stock Ownership Plan
The Pacific Enterprises Employee Stock Ownership Plan and Trust
(Trust) covers substantially all employees and is used to partially
fund PE's retirement savings plan program. All contributions to the
Trust are made by PE, and there are no contributions by the
participants. As PE makes contributions to the ESOP, the ESOP debt
service is paid and shares are released proportionately to the
total expected debt service. Compensation expense is charged and
equity is credited for the market value of the shares released.
However, tax deductions are allowed based on the cost of the
shares. Dividends on unallocated shares are used to pay debt
service and are charged against liabilities. The Trust held 2.1
million and 2.2 million shares of common stock with fair values of
$80.3 million and $67.6 million at December 31, 1997 and 1996,
respectively.
Enova and SDG&E do not have an employee stock ownership plan.
Post-Employment Benefits
Sempra Energy accrues its obligation to provide benefits to former
or inactive employees after employment but before retirement. There
is no impact on earnings since these costs are recovered in rates
as paid and, therefore, are reflected as a regulatory asset. At
December 31, 1997 and 1996 the liability was $40 million and $42
million, respectively, and represents primarily workers
compensation and disability benefits.
NOTE 9: STOCK-BASED COMPENSATION
Both PE and Enova have stock-based compensation plans. In 1995,
Statement of Financial Accounting Standards (SFAS) No. 123,
"Accounting for Stock-Based Compensation," was issued. It
encourages a fair-value-based method of accounting for stock-based
compensation. As permitted by SFAS No. 123, PE and Enova adopted
the disclosure-only requirements of the Statement and continue to
account for stock-based compensation in accordance with the
provisions of Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees."
Enova's long-term incentive stock compensation plan provides for
aggregate awards of Enova common stock equivalent to up to
2,700,000 shares of Sempra Energy common stock. The plan terminates
in April 2005. In each of the last 10 years, Enova shares
equivalent to 49,000 shares to 75,000 shares of Sempra Energy
common stock were issued to officers and key employees, subject to
forfeiture over four years if certain corporate goals are not met.
Holders of this stock have voting rights and will receive dividends
prior to the time the restrictions lapse if, and to the extent,
paid on Enova common stock generally. Enova's long-term incentive
stock compensation plan also provides for the granting of stock
options. In October 1997, Enova rescinded all options granted in
October 1996. There were no stock options outstanding at December
31, 1997. SDG&E's compensation expense for this plan was
approximately $1 million in 1997, $1 million in 1996 and $2 million
in 1995.
Pacific Enterprises' Employee Stock Option Plan provides for the
granting of stock options to officers and other employees of PE and
its subsidiaries. The option price is equal to the market price of
the company's stock at the date of grant. The stock options expire
in ten years from the date of grant. All options granted prior to
1997 became immediately exercisable upon approval by PE's
shareholders of the business combination with Enova. The options
were originally scheduled to vest annually over a service period
ranging from three to five years. The authorized number of options
granted each year may not exceed one percent of the outstanding
common stock at the beginning of the year.
PE's plan allows for the granting of dividend equivalents based
upon performance goals. This feature provides grantees, upon
exercise of the option, with the opportunity to receive all or a
portion of the cash dividends that would have been paid on the
shares if the shares had been outstanding since the grant date.
Dividend equivalents are not payable if PE does not meet the
established performance goal, or if the exercise price exceeds the
market value of the shares purchased. The percentage of dividends
paid as dividend equivalents will depend upon the extent to which
the performance goals are met.
The following information regarding PE's stock options is presented
after conversion of PE stock into Sempra Energy stock as described
in Note 1. PE's stock option activity for the years ended December
31, 1995, 1996 and 1997 is summarized in the following tables:
Options With Performance Features
Shares Wtd. Avg. Shares
Under Exercise Exercisable
Option Prices at Year-End
- -------------------------------------------------------------------
December 31, 1994 1,506,898 $17.68 619,806
Granted 846,188 16.23
Exercised (341,964) 13.44
Cancelled (100,093) 27.60
- ----------------------------------
December 31, 1995 1,911,029 $17.28 551,744
Granted 1,030,404 17.95
Exercised (93,988) 14.27
Cancelled (77,295) 26.24
- ----------------------------------
December 31, 1996 2,770,150 $17.38 884,335
Granted 1,040,103 20.37
Exercised (359,288) 16.53
Cancelled (71,190) 20.37
- ----------------------------------
December 31, 1997 3,379,775 $18.33 2,407,103
===================================================================
Options Without Performance Features
Shares Wtd. Avg. Shares
Under Exercise Exercisable
Option Prices at Year-End
- -------------------------------------------------------------------
December 31, 1994 1,658,015 $17.72 622,498
Exercised (240,728) 14.96
Cancelled (180,110) 18.37
- ----------------------------------
December 31, 1995 1,237,177 $18.15 648,439
Exercised (210,532) 15.32
Cancelled (48,122) 25.75
- ----------------------------------
December 31, 1996 978,523 $18.39 595,415
Exercised (493,848) 14.94
Cancelled (14,737) 35.24
- ----------------------------------
December 31, 1997 469,938 $21.47 469,938
===================================================================
Additional information on PE options outstanding at December 31,
1997 is as follows:
Outstanding Options
Wtd. Wtd.
Range of Number Average Average
Exercise of Remaining Exercise
Prices Shares Life Price
- -------------------------------------------------------------------
$12.80 - 16.13 1,357,781 6.19 $14.96
$16.79 - 20.37 2,001,543 8.43 $19.05
$24.11 - 31.42 490,389 2.27 $27.74
---------
3,849,713 6.85 $18.71
===================================================================
Exercisable Options
Wtd.
Range of Number Average
Exercise of Exercise
Prices Shares Price
- -------------------------------------------------------------------
$12.80 - 16.13 1,354,022 $14.96
$16.79 - 20.37 1,032,629 $17.80
$24.11 - 31.42 490,389 $27.74
---------
2,877,040 $18.16
===================================================================
The fair value of each PE option grant (including the dividend
equivalent) was estimated on the date of grant using the Black-
Scholes option-pricing model. Weighted average fair values for PE
options granted in 1997, 1996 and 1995 were $5.23, $5.00 and $4.87,
respectively.
The assumptions that were used to determine these fair values are
as follows:
Year Ended December 31
-----------------------------------------
1997 1996 1995
- -------------------------------------------------------------------
Stock price volatility 18 % 19 % 19 %
Risk-free rate of return 6.4 % 6.1 % 7.1 %
Annual dividend yield 0 % 0 % 0 %
Expected life 3.8 Years 4.3 Years 4.3 Years
===================================================================
No compensation expense has been recognized for PE's stock-based
compensation plans except for the dividend-equivalent performance-
based options. PE recorded compensation expense of $16.9 million,
$5.5 million and $3.4 million in 1997, 1996 and 1995, respectively.
The differences between compensation cost included in net income
and the related cost measured by the fair-value-based method
defined in SFAS No. 123 are immaterial.
NOTE 10: FINANCIAL INSTRUMENTS
Fair Value The fair values of Sempra Energy's financial
instruments (cash, temporary investments, funds held in trust,
notes receivable, investments in limited partnerships, dividends
payable, short- and long-term debt, deposits from customers, and
preferred stock of subsidiaries) are not materially different from
the carrying amounts, except for long-term debt and preferred stock
of subsidiaries. The carrying amounts and fair value of long-term
debt are $3.3 billion and $3.4 billion, respectively, at December
31, 1997, and $2.8 billion each, at December 31, 1996. The carrying
amounts and fair value of subsidiaries' preferred stock are $278
million and $258 million, respectively, at December 31, 1997 and
$278 million and $240 million, respectively, at December 31, 1996.
The fair values of the first mortgage bonds and preferred stock are
estimated based on quoted market prices for them or for similar
issues. The fair values of long-term notes payable are based on the
present values of the future cash flows, discounted at rates
available for similar notes with comparable maturities. The fair
values of rate-reduction bonds issued in December 1997 are
estimated to approximate carrying value due to the relatively short
period of time between the issuance date and the valuation date,
and the relative market stability during those periods.
Off-Balance-Sheet Financial Instruments Sempra Energy's policy is
to use derivative financial instruments to reduce its exposure to
fluctuations in interest rates, foreign-currency exchange rates and
natural-gas prices. These financial instruments expose the company
to market and credit risks which may at times be concentrated with
certain counterparties, although counterparty nonperformance is not
anticipated. Additional information on this topic is included in
Note 3.
Swap Agreements SDG&E and SoCalGas periodically enter into
interest-rate-swap agreements to moderate their exposure to
interest-rate changes and to lower their overall cost of borrowing.
These agreements generally remain off the balance sheet as they
involve the exchange of fixed- and variable-rate interest payments
without the exchange of the underlying principal amounts. The
related gains or losses are reflected in the income statement as
part of interest expense. In addition, a portion of SoCalGas'
borrowings are denominated in foreign currencies, which exposes the
company to market risk associated with exchange rate movements. The
company's policy generally is to hedge major foreign currency cash
exposures through swap transactions.
At December 31, 1997, SDG&E had one interest-rate-swap agreement: a
floating-to-fixed-rate swap associated with $45 million of
variable-rate bonds maturing in 2002. SDG&E expects to hold this
derivative financial instrument to its maturity. This swap
agreement has effectively fixed the interest rate on the underlying
variable-rate debt at 5.4 percent. SDG&E would be exposed to
interest-rate fluctuations on the underlying debt should the
counterparty to the agreement not perform. Such nonperformance is
not anticipated. This agreement, if terminated, would result in an
obligation of $2 million at December 31, 1997, and at December 31,
1996.
Additional information on this topic is included in Note 5.
Foreign-Currency Forward Exchange Contracts SDG&E and PE/SoCalGas
pension funds (see Note 8) periodically use foreign-currency
forward contracts to reduce their exposures to exchange-rate
fluctuations associated with certain investments in foreign equity
securities. These contracts generally have maturities ranging from
three to six months. At December 31, 1997, SDG&E and PE/SoCalGas
had no foreign-currency forward contracts outstanding.
Energy Derivatives Information on derivative financial instruments
of Sempra Energy Trading is provided in Note 3. Other subsidiaries
of Sempra Energy use energy derivatives for both hedging and
trading purposes within certain limitations imposed by company
policies. Gas futures contracts are used to mitigate risk and
better manage costs. These derivative financial instruments include
forward contracts, swaps, options and other contracts which have
maturities ranging from 30 days to nine months.
Sempra Energy's accounting policy is to adjust the book value of
these derivatives to market each month with gains and losses
recognized in earnings. These instruments are included in other
current assets on the supplemental consolidated balance sheet.
Certain instruments such as swaps are entered into and closed out
within the same month and, therefore, do not have any balance sheet
impact. Gains and losses are included in electric or gas revenue or
expense, whichever is appropriate, on the supplemental consolidated
income statement.
As of December 31, 1997, the net fair value of SDG&E's open
positions was $5.9 million. The net unrealized profit of these open
positions was $0.3 million. These positions hedge approximately 6
percent of SDG&E's annual total purchased-gas volumes. The average
fair value of derivative financial instruments during 1997 was an
obligation of $0.2 million. The net gains arising from these
activities during 1997 were $2.5 million.
SoCalGas is subject to price risk on its natural-gas purchases if
its cost exceeds a 2-percent tolerance band above the Gas Cost
Incentive Mechanism (GCIM) benchmark price. SoCalGas becomes
subject to price risk when positions are incurred during the
buying, selling and storage of natural gas. As a result of the
GCIM, SoCalGas enters into a certain amount of gas futures
contracts in the open market with the intent of reducing gas costs
within the GCIM tolerance band. The CPUC has approved the use of
gas futures for managing risk associated with the GCIM. For the
year ended December 31, 1997, gains and losses from gas futures
contracts are not material to SoCalGas' financial statements.
NOTE 11: EARNINGS PER SHARE
Prior to 1997, Enova and PE reported earnings per share (EPS) in
accordance with Accounting Principles Board Opinion No. 15,
"Earnings per Share." In February 1997, Statement of Financial
Accounting Standards No. 128, "Earnings Per Share" (SFAS No. 128)
was issued.
SFAS No. 128 established standards for computing and
presenting EPS and applies to entities with publicly held common
stock or potential common stock. This statement simplifies the
standards for computing EPS previously found in Accounting
Principles Board Opinion No. 15, and makes them comparable to
international EPS standards.
SFAS No. 128 replaces the presentation of primary EPS with a
presentation of basic EPS based upon the weighted average number of
common shares for the period. It also requires dual presentation of
basic and diluted EPS on the face of the income statement for all
entities with complex capital structures and requires a
reconciliation of the numerator and denominator of the basic EPS
computation to the numerator and denominator of the diluted EPS
computation. SFAS No. 128 was adopted by Enova and PE at the end of
1997 and EPS for all prior periods were restated.
PE's outstanding stock options represent the only forms of
potential common stock at December 31, 1997. Dilutive options or
warrants that are issued during a period or that expire or are
canceled during a period are included in the denominator of diluted
EPS for the period that they were outstanding.
For Sempra Energy, the reconciliation between the numerator
and denominator for basic and diluted EPS is as follows:
Income Shares Per-Share
(Numerator) (Denominator) Amount
(in millions) (in thousands)
- -------------------------------------------------------------------
1997:
Basic EPS $432 236,662 $1.83
Effect of dilutive
securities (stock options) 587
- -------------------------------------------------------------------
Diluted EPS $432 237,249 $1.82
===================================================================
1996:
Basic EPS $427 240,825 $1.77
Effect of dilutive
securities (stock options) 332
- -------------------------------------------------------------------
Diluted EPS $427 241,157 $1.77
===================================================================
1995:
Basic EPS $401 240,245 $1.67
Effect of dilutive
securities (stock options) 110
- -------------------------------------------------------------------
Diluted EPS $401 240,355 $1.67
===================================================================
The number of shares includes the conversion of each share of PE
common stock into 1.5038 shares of Sempra Energy common stock (see
Note 1).
NOTE 12: CONTINGENCIES AND COMMITMENTS
Natural-Gas Contracts SoCalGas has commitments for firm pipeline
capacity under contracts with pipeline companies that expire at
various dates through the year 2006. These agreements provide for
payments of an annual reservation charge. SoCalGas recovers such
fixed charges in rates. Estimated minimum commitments as of
December 31, 1997 are included in the table below.
SDG&E's long-term contracts with interstate pipelines for
transportation capacity expire on various dates between 2007 and
2023. SDG&E has long-term natural-gas supply contracts (included in
the table below) with four Canadian suppliers that expire between
2001 and 2004. SDG&E has been involved in negotiations and
litigation with the suppliers concerning the contracts' terms and
prices. SDG&E has settled with one supplier, with gas being
delivered under the terms of the settlement agreement. The
remaining suppliers have ceased deliveries pending legal
resolution. A U.S. Court of Appeals has upheld a U.S. District
Court's invalidation of the contracts with two of these suppliers.
At December 31, 1997, the future minimum payments under
natural-gas contracts were:
Transportation Natural
In millions of dollars and Storage Gas
- -------------------------------------------------------------------
1998 $ 194 $ 19
1999 195 17
2000 198 19
2001 200 21
2002 200 24
Thereafter 868 25
- -------------------------------------------------------------------
Total minimum payments $1,855 $125
===================================================================
SDG&E's natural-gas contracts with SoCalGas for intra-state
transportation capacity and storage capacity are considered inter-
company and are excluded from the above table.
Purchased-Power Contracts SDG&E buys electric power under several
short-term and long-term contracts. Purchases are for up to 7
percent of plant capacity under contracts with other utilities and
up to 100 percent of plant capacity under contracts with nonutility
suppliers. No one supplier provides more than 3 percent of SDG&E's
total system requirements. The contracts expire on various dates
between 1998 and 2025.
At December 31, 1997, the estimated future minimum payments
under the contracts were:
In millions of dollars
- -------------------------------------------------------------------
1998 $ 234
1999 232
2000 200
2001 183
2002 134
Thereafter 2,462
- -------------------------------------------------------------------
Total minimum payments $3,445
===================================================================
These payments represent capacity charges and minimum energy
purchases. SDG&E is required to pay additional amounts for actual
purchases of energy that exceed the minimum energy commitments.
Total payments, including energy payments, under the contracts were
$421 million in 1997, $296 million in 1996 and $329 million in
1995. Payments under purchased-power contracts increased in 1997
due to increased sales volume and lower nuclear generation
availability.
In November 1997, SDG&E announced a plan to auction its power
plants and other electric-generating resources, which include its
long-term purchased-power contracts. Additional information on
SDG&E's plan to divest its electric-generating assets is discussed
in Note 13.
Leases PE and its subsidiaries have leases (primarily operating)
on real and personal property expiring at various dates from 1998
to 2011. The rentals payable under these leases are determined on
both fixed and percentage bases and most leases contain options to
extend, which are exercisable by PE or its subsidiaries.
SDG&E has nuclear fuel, office buildings, a generating
facility and other properties that are financed by long-term
capital leases. Utility plant includes $198 million at December 31,
1997, and $200 million at December 31, 1996, related to these
leases. The associated accumulated amortization is $102 million and
$95 million, respectively. SDG&E and nonutility subsidiaries also
lease office facilities, computer equipment and vehicles under
operating leases. Certain leases on office facilities contain
escalation clauses requiring annual increases in rent ranging from
2 percent to 7 percent.
The minimum rental commitments payable in future years under
all noncancellable leases are:
Operating Capitalized
In millions of dollars Leases Leases
- -------------------------------------------------------------------
1998 $ 85 $ 29
1999 61 29
2000 61 23
2001 50 15
2002 51 15
Thereafter 335 20
- -------------------------------------------------------------------
Total future rental commitment $643 $131
Imputed interest (6% to 9%) (25)
- -------------------------------------------------------------------
Net commitment $106
===================================================================
Rent expense totaled $137 million in 1997, $146 million in
1996 and $151 million in 1995.
In connection with the quasi-reorganization (see Note 2) and
loss on disposal of discontinued operations, PE established
reserves of $102 million to fairly value operating leases related
to its headquarters and other leases at December 31, 1992. The
remaining amount of these reserves was $79 million at December 31,
1997.
Environmental Issues Operations are conducted in accordance with
federal, state and local environmental laws and regulations
governing hazardous wastes, air and water quality, land use, and
solid-waste disposal. SoCalGas and SDG&E incur significant costs to
operate their facilities in compliance with these laws and
regulations. The costs of compliance with environmental laws and
regulations have been recovered in customer rates.
In 1994 the CPUC approved the Hazardous Waste Collaborative
Memorandum account allowing utilities to recover their hazardous
waste costs, including those related to Superfund sites or similar
sites requiring cleanup. The decision allows recovery of 90 percent
of cleanup costs and related third-party litigation costs and 70
percent of the related insurance litigation expenses. Environmental
liabilities that may arise are recorded when remedial efforts are
probable, and the costs can be estimated.
Sempra Energy's capital expenditures to comply with
environmental laws and regulations were $5 million in 1997, $9
million in 1996 and $7 million in 1995, and are expected to be $65
million over the next five years. These expenditures primarily
include the estimated cost of retrofitting SDG&E's power plants to
reduce air emissions. SDG&E has been associated with various sites
which may require remediation under federal, state or local
environmental laws. Sempra Energy is unable to determine the extent
of its responsibility for remediation of these sites until
assessments are completed. Furthermore, the number of others that
also may be responsible, and their ability to share in the cost of
the cleanup, is not known.
As discussed in Note 13, restructuring of the California
electric-utility industry will change the way utility rates are set
and costs are recovered. Both the CPUC and state legislation have
indicated that the California utilities will be allowed an
opportunity to recover existing utility plant and regulatory assets
over a transition period that ends in 2001. SDG&E has asked the
CPUC that beginning on January 1, 1998, the collaborative account
be modified, and that electric generation-related cleanup costs be
eligible for transition-cost recovery. A CPUC decision is still
pending. Depending on the final outcome of industry restructuring
and the impact of competition, the costs of compliance with
environmental regulations may not be fully recoverable.
SoCalGas has identified and reported to California
environmental authorities 42 former manufactured gas plant sites
for which it (together with other utilities as to 21 of these
sites) may have remedial obligations under environmental laws. As
of December 31, 1997, preliminary investigations have been
completed on 39 of the gas plant sites, including 10 sites at which
remediations above have been completed and two sites that are in
the process of being remediated. In addition, PE and its
subsidiaries have been named as potentially responsible parties for
two landfill sites and two industrial waste disposal sites. At
December 31, 1997 SoCalGas' estimated remaining investigation and
remediation liability was $72 million, of which 90 percent is
authorized to be recovered through the Collaborative Memorandum
accounts discussed above. Environmental liabilities that may arise
from these assessments are recorded when remedial efforts are
probable, and the costs can be estimated.
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 $8.7 billion of coverage
is provided by secondary financial protection required by the
Nuclear Regulatory Commission and provides for loss sharing among
utilities owning nuclear reactors if a costly accident occurs.
SDG&E could be assessed retrospective premium adjustments of up to
$32 million in the event of a nuclear incident involving any of the
licensed, commercial reactors in the United States, if the amount
of the loss exceeds $200 million. In the event the public-liability
limit stated above is insufficient, the Price-Anderson Act provides
for Congress to enact further revenue-raising measures to pay
claims, which could include an additional assessment on all
licensed reactor operators.
Insurance coverage is provided for up to $2.8 billion of
property damage and decontamination liability. Coverage is also
provided for the cost of replacement power, which includes
indemnity payments for up to three years, after a waiting period of
17 weeks. Coverage is provided primarily through mutual insurance
companies owned by utilities with nuclear facilities. If losses at
any of the nuclear facilities covered by the risk-sharing
arrangements were to exceed the accumulated funds available from
these insurance programs, SDG&E could be assessed retrospective
premium adjustments of up to $6 million.
Department of Energy Decommissioning The Energy Policy Act of 1992
established a fund for the decontamination and decommissioning of
the Department of Energy nuclear-fuel-enrichment facilities.
Utilities using the DOE services are contributing a total of $2.3
billion, subject to adjustment for inflation, over a 15-year period
ending in 2006. Each utility's share is based on its share of
enrichment services purchased from the DOE. SDG&E's annual
contribution is $1 million, and will be recovered as part of
decommissioning costs (see Note 6).
Litigation Sempra Energy is involved in various legal matters,
including those arising out of the ordinary course of business.
Management believes that these matters will not have a material
adverse effect on results of operations, financial condition or
liquidity.
Electric Distribution System Conversion Under a CPUC-mandated
program and through franchise agreements with various cities, SDG&E
is committed, in varying amounts, to convert overhead distribution
facilities to underground. As of December 31, 1997, the aggregate
unexpended amount of this commitment was approximately $100
million. Capital expenditures for underground conversions were $17
million in 1997, $15 million in 1996 and $12 million in 1995.
Concentration of Credit Risk SDG&E and SoCalGas grant credit to
their utility customers, substantially all of which are located in
their service territories, which together cover all of Southern
California and a portion of Central California.
Sempra Energy Trading monitors and controls its credit risk
exposures through various systems which evaluate its credit risk,
and through credit approvals and limits. To manage the level of
credit risk, Sempra Energy Trading deals with a majority of
counterparties with good credit standing, enters into master
netting arrangements whenever possible and, where appropriate,
obtains collateral. Master netting agreements incorporate rights of
setoff that provide for the net settlement of subject contracts
with the same counterparty in the event of default.
NOTE 13: REGULATORY MATTERS
Electric Industry Restructuring
In September 1996, the state of California enacted a law
restructuring California's electric-utility industry (AB 1890). The
legislation adopts the December 1995 CPUC policy decision
restructuring the industry to stimulate competition and reduce
rates. The law supersedes the CPUC policy decision when in
conflict.
Beginning on March 31, 1998, customers may buy their
electricity through a power exchange that obtains power from
qualifying facilities, nuclear units and, lastly, from the lowest-
bidding suppliers. The power exchange serves as a wholesale power
pool allowing all energy producers to participate competitively. An
Independent System Operator schedules power transactions and access
to the transmission system. Consumers also may choose either to
continue to purchase from their local utility under regulated
tariffs or to enter into private contracts with generators, brokers
or others. The local utility continues to provide distribution
service regardless of which source the consumer chooses.
Utilities are allowed a reasonable opportunity to recover
their stranded costs through December 31, 2001. Stranded costs,
such as those related to reasonable employee-related costs directly
caused by restructuring, and purchased-power contracts (including
those with qualifying facilities) may be recovered beyond December
31, 2001. Outside of those exceptions, stranded costs not recovered
through 2001 will not be collected from customers. Such costs, if
any, would be written off as a charge against earnings.
SDG&E's transition cost application filed in October 1996
identifies costs totaling $2 billion (net present value in 1998
dollars). These identified transition costs were determined to be
reasonable by independent auditors selected by the CPUC, with $73
million requiring further action before being deemed recoverable
transition costs. Of this amount, the CPUC has excluded from
transition cost recovery $39 million in fixed costs relating to gas
transportation to power plants, which SDG&E believes will be
recovered through contracts with the ISO. Total transition costs
include sunk costs, as well as ongoing costs the CPUC finds
reasonable and necessary to maintain generation facilities through
December 31, 2001. Both the CPUC policy decision and AB 1890
provide that above-market costs for existing purchased-power
contracts may be recovered over the terms of the contracts or
sooner. Qualifying facilities purchases include approximately 100
existing contracts, which extend as far as 2025. Other power
purchases consist of two long-term contracts expiring in 2001 and
2013. Transition costs also include other items SDG&E has accrued
under cost-of-service regulation. Nuclear decommissioning costs are
nonbypassable until fully recovered, but are not included as part
of transition costs.
Through December 31, 1997, SDG&E has recovered transition
costs of $0.2 billion for nuclear generation and $0.1 billion for
non-nuclear generation. Additionally, overcollections of $0.1
billion recorded in the ECAC and ERAM balancing accounts as of
December 31, 1997, have been applied to transition cost recovery,
leaving approximately $1.6 billion for future recovery. Included
therein is $0.4 billion for post-2001 purchased-power-contract
payments that may be recovered after 2001, subject to an annual
reasonableness review.
SDG&E has announced a plan to auction its power plants and
other electric-generating assets. This plan includes the
divestiture of SDG&E's fossil power plants and combustion turbines,
its 20-percent interest in SONGS and its portfolio of long-term
purchased-power contracts. The power plants, including the interest
in SONGS, have a net book value as of December 31, 1997, of $800
million ($200 million for fossil and $600 million for SONGS). The
proceeds from the auction will be applied directly to SDG&E's
transition costs. In December 1997, SDG&E filed with the CPUC for
its approval of the auction plan. SDG&E has requested that the sale
of the non-nuclear power plants be completed by the end of 1998.
During the 1998-2001 period, recovery of transition costs is
limited by the rate freeze (discussed below). Management believes
that the rates within the rate cap and the proceeds from the sale
of electric-generating assets will be sufficient to recover all of
SDG&E's approved transition costs by December 31, 2001, not
including the post-2001 purchased-power contracts payments that may
be recovered after 2001. However, if the proceeds from the sale of
the power plants are less than expected or if generation costs,
principally fuel costs, are greater than anticipated, SDG&E may be
unable to recover all of its approved transition costs. This would
result in a charge against earnings at the time it becomes probable
that SDG&E will be unable to recover all of the transition costs.
The California legislation provides for a 10-percent reduction
of residential and small commercial customers' rates, which began
in January 1998, as a result of the utilities' receiving the
proceeds of rate-reduction bonds issued by an agency of the state
of California. In December 1997, $658 million of rate-reduction
bonds were issued on behalf of SDG&E 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 nonbypassable
charge on their electric bills.
In addition, the California legislation includes a rate freeze
for all electric customers. Until the earlier of March 31, 2002, or
when transition cost recovery is complete, SDG&E's system-average
rate will be frozen at June 1996 levels (9.64 cents per kwh),
except for the impact of fuel-cost changes and the 10-percent rate
reduction described above. Beginning in 1998 system-average rates
were fixed at 9.43 cents per kwh, which includes the maximum
permitted increase related to fuel-cost increases and the mandatory
rate reduction.
As discussed in Note 2, SDG&E has been accounting for the
economic effects of regulation in accordance with SFAS No. 71. The
SEC indicated a concern that the California investor-owned
utilities may not meet the criteria of SFAS No. 71 with respect to
their electric-generation net regulatory assets. SDG&E has ceased
the application of SFAS No. 71 to its generation business, in
accordance with the conclusion by the Emerging Issues Task Force of
the Financial Accounting Standards Board that the application of
SFAS 71 should be discontinued when deregulatory legislation is
issued that determines that a portion of an entity's business will
no longer be regulated. The discontinuance of SFAS No. 71 applied
to the utilities' generation business did not result in a write-off
of their net regulatory assets, since the CPUC has approved the
recovery of these assets by the distribution portion of their
business, subject to the rate cap.
Performance-Based Regulation
On July 16, 1997, the CPUC issued its final decision on SoCalGas'
application for performance-based regulation (PBR), which was filed
with the CPUC in 1995. PBR replaces the general rate case and
certain other regulatory proceedings through December 31, 2002.
Under PBR, regulators allow future income potential to be tied to
achieving or exceeding specific performance and productivity
measures, rather than relying solely on expanding utility rate base
in a market where SoCalGas already has a highly developed
infrastructure. Key elements of the PBR include a 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. Specifically, the key elements of PBR include the
following:
- The decision required a net rate reduction of $164 million for
an initial base margin of $1.3 billion. The $164 million is
comprised of a rate reduction of $191 million, effective August 1,
1997, which is partially offset by an estimated $27 million rate
increase reflecting inflation and customer growth, effective
January 1, 1998.
- Earnings up to 25 basis points exceeding 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
excess earnings being given back to customers and declining to 0
percent as earned returns approach 300 basis points above
authorized amounts. However, the decision rejects sharing of any
amount by which actual earnings fall below the authorized rate of
return. In 1998, SoCalGas is authorized to earn a 9.49 percent
return on rate base.
- Revenue or margin per customer is indexed based on inflation
less an estimated productivity factor of 2.1 percent in the first
year, increasing 0.1 percent per year up to 2.5 percent in the
fifth year. This factor includes 1 percent to approximate the
projected impact of a declining rate base.
- The CPUC decision allows for pricing flexibility for
residential and small commercial customers, with any shortfalls
being borne by shareholders and with any gains shared between
shareholders and customers.
- The decision allows SoCalGas to continue offering some types
of products and services it currently offers (e.g. contract meter
reading) but the issue of other new product and service offerings
was addressed in the CPUC's Affiliate Transaction Decision.
SoCalGas implemented the base margin reduction effective
August 1, 1997, and all other PBR elements on January 1, 1998. The
CPUC intends the PBR decision to be in effect for five years;
however, the CPUC decision allows for the possibility that changes
to the PBR mechanism could be adopted in a decision to be issued in
SoCalGas' 1998 Biennial Cost Allocation Proceedings (BCAP)
application which is anticipated to become effective on August 1,
1999.
Under SoCalGas' PBR, annual cost of capital proceedings are
replaced by an automatic adjustment mechanism if changes in certain
indices exceed established tolerances. The mechanism is triggered
if actual interest rates increase or decrease by more than 150
basis points and are forecasted to continue to vary by at least 150
basis points for the next year. If this occurs, there would be an
automatic adjustment of rates for the change in the cost of capital
according to a pre-established formula which applies a percentage
of the change to various capital components.
SDG&E has been participating in a PBR process for base rates,
gas procurement, and electric generation and dispatch. SDG&E has
applied to extend the Gas Procurement Mechanism. The Generation and
Dispatch mechanism has been terminated.
SDG&E has filed a proposal for a new Distribution PBR
mechanism to replace the current experimental Base-Rate PBR when it
terminates at the end of 1998. The new distribution PBR for
electric distribution and gas operations includes a 1999 Cost of
Service study, which was filed in January 1998. The proposed
mechanism includes a formula for indexing year-to-year gas and
electric distribution rates due to inflationary impacts. Rates
under the new mechanism are self-calibrating and will be reset each
year based on SDG&E's financial performance achieved the previous
year. To the extent that return on rate base for any year differs
from the authorized rate by more than 100 basis points, the next
year's authorized rates will be adjusted up or down by an amount
equal to 20 percent of that excess.
Performance indicators under the proposed Distribution PBR
include customer satisfaction, employee safety, electric system
reliability, electric competition enhancement, environmental
citizenship and electric system maintenance. Although the
application requests an increase in SDG&E's distribution revenue
requirements, the increase does not affect overall electric
distribution rates and, therefore, would reduce the amount of
revenue available to recover transition costs (discussed above).
In February 1998 SDG&E reached an agreement with the CPUC's
Office of Ratepayer Advocates on a proposed permanent Gas
Procurement PBR mechanism. The proposal essentially continues the
existing mechanism, establishing a monthly benchmark against which
SDG&E's gas procurement activities are measured. The resulting
costs or savings will be shared equally between shareholders and
customers. A final CPUC decision is expected in July 1998.
Restructuring of Gas-Supply Contracts
In 1993 SoCalGas' and PE's gas-supply subsidiaries restructured
long-term gas-supply contracts with suppliers of California
offshore and Canadian gas. In the past, SoCalGas' cost of these
supplies had been substantially in excess of its average delivered
cost of gas for all gas supplies.
The restructured contracts substantially reduced the ongoing
delivered costs of these gas supplies and provided lump-sum
payments totaling $391 million to the suppliers. The expiration
date for the Canadian gas supply contract was shortened from 2012
to 2003.
Comprehensive Settlement of Regulatory Issues
On July 20, 1994, the CPUC approved a comprehensive settlement
(Comprehensive Settlement) of a number of pending regulatory issues
including rate recovery of a significant portion of the
restructuring costs associated with long-term gas-supply contracts
discussed above. The Comprehensive Settlement permits SoCalGas to
recover in utility rates approximately 80 percent of the contract-
restructuring costs of $391 million and accelerated amortization of
related pipeline assets of approximately $140 million, together
with interest, over a period of approximately five years. In
addition to the gas-supply issues, the Comprehensive Settlement
addresses the following other regulatory issues:
- Noncore Customer Rates. The Comprehensive Settlement changed
the procedures for determining noncore rates to be charged by
SoCalGas to its customers for the five-year period commencing
August 1, 1994. Rates charged to the customers are established
based upon SoCalGas' recorded throughput to these customers for
1991. SoCalGas will bear the full risk of any declines in noncore
deliveries from 1991 levels. Any revenue enhancement from
deliveries in excess of 1991 levels will be limited by a crediting
account mechanism that will require a credit to customers of 87.5
percent of revenues in excess of certain limits. These annual
limits above which the credit is applicable increase from $11
million to $19 million over the five-year period from August 1,
1994 through July 31, 1999. SoCalGas' ability to report as
earnings the results from revenues in excess of SoCalGas'
authorized return from noncore customers due to volume increases
has been eliminated for the five years beginning August 1, 1994 as
a result of the Comprehensive Settlement.
- Reasonableness Reviews. The Comprehensive Settlement includes
settlement of all pending reasonableness reviews with respect to
SoCalGas' gas purchases from April 1989 through March 1992, as well
as certain other future reasonableness review issues.
- Gas Cost Incentive Mechanism. On April 1, 1994, SoCalGas
implemented a new process for evaluating its gas purchases,
substantially replacing the previous process of reasonableness
reviews. Initially a three-year pilot program, the CPUC recently
extended the Gas Cost Incentive Mechanism (GCIM) program through
March 31, 1999.
GCIM compares SoCalGas' cost of gas with a benchmark level,
which is the average price of 30-day firm spot supplies delivered
to its market area. 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 of purchases or savings outside the "tolerance
band" are shared equally between customers and shareholders.
The CPUC approved the use of gas futures for managing risk
associated with the GCIM. PE enters into gas futures contracts in
the open market on a limited basis to mitigate risk and better
manage gas costs.
Since SoCalGas' purchased gas costs were below the specified
GCIM benchmark for the annual period ended March 1996, the CPUC, in
June 1997, approved a $3.2 million pre-tax award to shareholders
under the procurement portion of the incentive mechanism. This $3.2
million award was recognized as income in the second quarter of
1997.
In June 1997, the Company filed its annual GCIM application
with the CPUC requesting an award of $10.8 million, pre-tax, for
the annual period ended March 31, 1997.
- Attrition Allowances. The Comprehensive Settlement authorized
SoCalGas an annual allowance for increases in operating and
maintenance expenses. In 1996, attrition was calculated on the
inflation rate in excess of 3 percent, authorizing SoCalGas to
collect $12 million in rates. No attrition allowance was authorized
for 1997 based on an agreement reached as part of the PBR
application.
PE recorded the impact of the Comprehensive Settlement in 1993.
Upon giving effect to liabilities previously recognized by PE and
SoCalGas, the costs of the Comprehensive Settlement, including the
restructuring of gas-supply contracts, did not result in any future
charge to earnings.
BCAP
In the second quarter of 1997, the CPUC issued a decision on
SoCalGas' 1996 BCAP filing. The CPUC decision extends the recovery
period of approximately $20 million in noncore costs, resulting in
a noncore rate decrease, and leaves in place the existing
residential rate structure. The decision did not adopt the SoCalGas
proposal to increase flexibility in offering discounts to utility
electric-generating customers to retain load or prevent bypass.
SoCalGas implemented the new rates and core residential monthly gas
pricing on June 1, 1997.
The BCAP substantially eliminates the effect on core income of
variances in core market demand and gas costs subject to the
limitations of the GCIM and the Comprehensive Settlement. The
CPUC's PBR decision indicates that it will address issues such as
throughput forecast, cost allocation, rate design and other matters
which may arise from SoCalGas' PBR experience during the 1998 BCAP.
Transactions Between Utility and Affiliated Companies
On December 16, 1997, the CPUC adopted rules, effective January 1,
1998, establishing uniform standards of conduct governing the
manner in which California investor-owned utilities conduct
business with their energy-related affiliates (Energy Affiliates).
The objective of the affiliate-transaction rules is to ensure that
utility affiliates do not gain an unfair advantage over other
competitors in the marketplace and that utility customers do not
subsidize affiliate activities. The rules establish standards
relating to non-discrimination, disclosure and information exchange
and separation of activities. Key elements of the affiliate-
transaction decision are as follows:
- Allows unregulated affiliates to operate within the utility's
service territory.
- Requires non-discriminatory pricing which mandates that all
transactions between the utility and its Energy Affiliates be
tariffed or competitively bid, excluding permitted corporate
support services and certain joint purchases.
- Allows utilities to share logos with their parent companies
and their Energy Affiliates; however, in California, the
relationship of the affiliated companies to the utilities must be
clearly communicated.
- Prohibits joint marketing activities and joint use of call
centers by utilities and their Energy Affiliates.
- Permits corporate support services (such as corporate
oversight, government support systems and personnel) to be provided
by the utility, its holding company or a separate affiliate created
solely to provide such services.
- Prohibits utilities from sharing office space, computers and
office equipment with Energy Affiliates, except in connection with
providing corporate-support services.
- Eliminates a parent company from the definition of an
"affiliate" unless it is directly involved in marketing energy
products or services.
Utility-to-utility transactions are also included under the
definition of an affiliate transaction unless the rules are
modified in a subsequent merger or other regulatory proceeding. The
CPUC excluded the transactions between SDG&E and SoCalGas from the
affiliate-transaction rules in its March 1998 decision approving
the business combination of Enova and PE (see Note 1). As required
by the decision, SDG&E and SoCalGas filed compliance plans with the
CPUC addressing the companies' implementation of the new rules. In
addition, the companies have filed for exemptions on certain rules
as well as petitions for rehearing which seek revision and
clarification on certain aspects of the rules.
NOTE 14: SUBSEQUENT EVENTS
International Projects In March 1998 Sempra Energy increased its
existing investment in two Argentine natural-gas utility holding
companies (Sodigas Pampeana S.A. and Sodigas Sur S.A.) by
purchasing an additional 9-percent interest for $40 million. With
this purchase, Sempra Energy's interest in the holding companies
was increased to 21.5 percent.
In May 1998 Sempra Energy and its partner Union Fenosa of
Spain were awarded a bid to build and operate a natural-gas and
propane distribution system in Uruguay, excluding Montevideo.
Sempra Energy holds a 75-percent interest in the partnership. The
partnership will hold a 55-percent interest in the system, with the
other 45 percent controlled by ANCAP, Uruguay's state-owned oil and
gas company. The cost to build the combined system, which is
expected to serve almost 800,000 customers by 2003, is estimated to
be in the $150 million to $200 million range.
California Ballot Initiative In June 1998 a coalition of consumer
groups received verification that its electric-restructuring ballot
initiative received the needed signatures to qualify for the
November 1998 California ballot. The initiative, among other
things, could result in an additional 10-percent rate reduction,
require that this rate reduction be achieved through the
elimination or reduction of CTC payments and prohibit the
collection of the charge on customer bills that would finance the
rate reduction. In May 1998 a statewide coalition of California's
investor-owned electric utilities and business groups filed a
lawsuit with a California District Court of Appeal to block the
initiative. Sempra Energy cannot predict the final outcome of the
initiative or lawsuit. If the initiative were to be voted into law
and upheld by the courts, the financial impact on Sempra Energy
could be substantial.
SEMPRA ENERGY
FOR THE THREE MONTHS ENDED MARCH 31, 1998.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following discussion should be read in conjunction with the
Supplemental Consolidated Financial Statements contained in this
Current Report on Form 8-K and the annual Management's Discussion
and Analysis contained elsewhere in this Current Report on Form 8-
K.
INFORMATION REGARDING FORWARD-LOOKING COMMENTS
The following discussion includes forward-looking statements with
respect to matters inherently involving various risks and
uncertainties. These statements are identified by the words
"estimates", "expects", "anticipates", "plans", "believes" and
similar expressions. These statements are necessarily based upon
various assumptions involving judgments with respect to the future
including, among others, national, regional and local economic,
competitive and regulatory conditions, technological developments,
inflation rates, interest rates, energy markets, weather
conditions, business and regulatory decisions, and other
uncertainties, all of which are difficult to predict and most of
which are beyond the control of the Company. Accordingly, while
the Company believes that the assumptions are reasonable, there can
be no assurance that they will approximate actual experience, or
that the expectations will be realized.
BUSINESS COMBINATION
On March 26, 1998, the California Public Utilities Commission
(CPUC) approved the combination of Pacific Enterprises (PE) and
Enova Corporation (Enova). In June 1998, final regulatory
approvals were received from the Federal Energy Regulatory
Commission (FERC) and the Security Exchange Commission (SEC). As a
result of the combination, PE and Enova became subsidiaries of
Sempra Energy (the Company) effective June 26, 1998. The holders
of common stock of each company became the holders of common stock
of Sempra Energy. PE's common shareholders received 1.5038 shares
of Sempra Energy common stock for each share of PE common stock,
and Enova common shareholders received one share of Sempra Energy
common stock for each share of Enova common stock. The combination
was approved by the shareholders of both companies on March 11,
1997 and will be a tax-free transaction accounted for as a pooling
of interests. See additional discussion in Note 1 of the notes to
supplemental consolidated financial statements and in the annual
Management's Discussion & Analysis of Financial Condition and
Results of Operations contained elsewhere in this Current Report on
Form 8-K.
CAPITAL RESOURCES AND LIQUIDITY
Cash flows from operations were $753 million and $443 million for
the three months ended March 31, 1998 and 1997, respectively. The
increase is primarily due to gas costs incurred being lower than
amounts collected in rates, resulting in a decrease in previously
undercollected regulatory balancing accounts, and an increase in
gas volumes sold.
Capital expenditures were $78 million and $88 million for the three
months ended March 31, 1998 and 1997, respectively. Capital
expenditures are estimated to be $442 million in 1998 and will be
financed primarily by internally generated funds and will largely
represent investment in utility operations
In April 1998 El Dorado Energy, a joint venture of Sempra Energy
Resources and Houston Industries Power Generation, began
construction on a 480-megawatt natural-gas-fired power plant in
Boulder City, Nevada. The $280 million project, which is expected
to be completed in the fourth quarter of 1999, will employ an
advanced combined-cycle gas-turbine technology, enabling it to
efficiently produce electricity for sale into the wholesale market
in the western United States.
Included in Other - net of the cash flows from investing activities
were investments of $70 million for the three months ended March
31, 1998 which represent additional investment in Argentine utility
operations and the acquisition of CES/Way International, Inc. (See
"Other" below). There were no investments in the three months
ended March 31, 1997.
Cash used for financing activities was $540 million and $379
million for the three months ended March 31, 1998 and 1997,
respectively. The increase is due to greater long- and short-term
debt repayments and the repurchase of preferred stock partially
offset by the repurchase of common stock in 1997. On February 2,
1998, SoCalGas redeemed all outstanding shares of 7 3/4% Series
Preferred Stock at a price per share of $25.09. The total cost was
$75.3 million.
Cash and cash equivalents at March 31, 1998 were $833 million.
This cash is available for investment in new energy-related
domestic and international projects, the retirement of debt and
other corporate purposes.
On May 1, 1998 SDG&E announced a voluntary tender for the entire
outstanding balances of three issuances of first mortgage bonds:
$54.3 million of 9.625-percent bonds, $43.7 million of 8.5-percent
bonds, and $80.0 million of 7.625-percent bonds. This, coupled
with the $32 million of variable-rate, taxable IDBs retired
previously and the $83 million of debt offset by temporary assets,
will complete the anticipated debt-related use of rate-reduction
bond proceeds. See additional discussion of rate-reduction bond
proceeds in the annual Management's Discussion & Analysis of
Financial Condition and Results of Operations contained elsewhere
in the Current Report on Form 8-K.
CONSOLIDATED RESULTS OF OPERATIONS
Net income for the three months ended March 31, 1998 was $87
million, or $.37 per common share (basic), compared to $98 million,
or $.41 per common share (basic) in 1997. The decrease is
primarily due to a lower base margin established at SoCalGas in the
Performance Based Regulation (PBR) decision which became effective
on August 1, 1997. Also contributing to lower net income were
operating losses at Sempra Energy Solutions and Sempra Energy
Trading. In addition, international subsidiaries had greater
operating costs in the first quarter of 1998 compared to the first
quarter of 1997 from efforts to develop their operations. Partially
offsetting the decrease were lower interest expense due to lower
debt levels and lower expenses related to the business combination.
Business-combination costs were $1 million and $6 million, after-
tax, for the three months ended March 31, 1998 and 1997,
respectively. Other offsetting factors include the previously
announced seasonal variability related to the elimination of
electric balancing accounts, rewards reflecting SDG&E's performance
under its Gas Procurement PBR mechanism, and lower operating and
maintenance expenses. The increase in depreciation (matched with a
corresponding increase in electric revenues) is due to the
acceleration of depreciation of electric-generating assets
resulting from electric-industry restructuring.
The weighted average number of shares of common stock outstanding
for the first quarter of 1998 decreased to 235 million shares
compared with 239 million shares for the first quarter of 1997, due
to the repurchase of common stock in the later part of 1997.
UTILITY OPERATIONS
Financial Results
Key financial and operating data for utility operations are
highlighted in the following table:
Three Months Ended March 31,
(Dollars in millions) 1998 1997
- ----------------------------------------------------------
Operating Revenues:
Gas $ 761 $ 848
Electric $ 497 $ 374
Cost of gas $ 330 $ 401
Purchased power $ 96 $ 88
Electric Fuel $ 31 $ 39
Operating expenses $ 272 $ 274
Income from operations $ 147 $ 145
- ----------------------------------------------------------
Utility gas revenues decreased 10% for the three months ended March
31, 1998 compared to the corresponding period in 1997 primarily due
to the margin reduction established in PBR at SoCalGas and the
lower cost of gas. Utility electric revenues increased 33%
primarily due to the recovery of stranded costs via the competition
transition charge (CTC) and differences between forecasted and
actual sales volume during the first quarter of 1998.
Cost of gas distributed decreased 18% primarily due a decrease in
the average cost of gas purchased. Under the current regulatory
framework, changes in revenue resulting from changes in volumes in
the core market and cost of gas do not affect net income.
Purchased power increased 9% for the three months ended March 31,
1998 compared to the corresponding period in 1997 primarily due to
increases in both energy costs and capacity charges. Electric fuel
expense decreased 21 percent primarily due to decreases in natural-
gas prices, offset by increases in sales volumes.
Operating expenses decreased 1% for the three month ended March 31,
1998 compared to the corresponding period in 1997 primarily due to
a continuing emphasis on reducing costs to remain competitive in
the energy marketplace.
Income from operations increased 1% for the three months ended
March 31, 1998 compared to 1997 primarily due to income from the
recovery of rate-reduction bond interest expense from customers and
savings resulting from lower operating and maintenance expenses
than amounts authorized in rates. The increase was partially
offset by the lower base margin established in the SoCalGas PBR.
Operating Results
The table below summarizes the components of utility gas and
electric volumes and revenues by customer class for the period
ended March 31, 1998 and 1997. Throughput, the total gas sales and
transportation volumes moved through the utilities systems,
increased in 1998, primarily because of colder weather. Electric
sales and transmission volumes moved through the utilities system
increased in 1998 primarily due to an increase in sales for resale
to other utilities and increased retail sales volume due to the
colder weather.
Gas Sales, Transportation & Exchange
(Dollars in millions, volumes in billion cubic feet)
Gas Sales Transportation & Exchange Total
Throughput Revenue Throughput Revenue Throughput Revenue
- ---------------------------------------------------------------------------------
Three Months Ended March 31, 1998
Residential 109 $809 1 $ 4 110 $ 813
Commercial/Industrial 30 186 86 71 116 257
Utility Generation 10 2 23 11 33 13
Wholesale 43 13 43 13
---------------------------------------------------------------
Total in Rates 149 $997 153 $99 302 1,096
Balancing and Other (335)
------
Total Operating Revenues $ 761
- ---------------------------------------------------------------------------------
Three Months Ended March 31, 1997
Residential 96 $659 1 $ 3 97 $ 662
Commercial/Industrial 31 215 80 71 111 286
Utility Generation 9 7 21 11 30 18
Wholesale 38 14 38 14
---------------------------------------------------------------
Total in Rates 136 $881 140 $99 276 980
Balancing and Other (132)
------
Total Operating Revenues $ 848
- ---------------------------------------------------------------------------------
Electric Distribution
(Dollars in millions, volumes in millions of Kwhrs)
1998 1997
---------------------------------------------------------------
Volumes Revenue Volumes Revenue
Three Months Ended March 31
Residential 1,631 $ 167 1,563 $ 172
Commercial 1,632 134 1,510 129
Industrial 814 48 893 52
Other 617 148 465 21
---------------------------------------------------------
Total 4,694 $ 497 4,431 $ 374
- ---------------------------------------------------------------------------
FACTORS INFLUENCING FUTURE PERFORMANCE
Performance of the Company in the near future will primarily depend
on the results of SDG&E and SoCalGas. Because of the ratemaking and
regulatory process, electric and gas industry restructurings and the
changing energy marketplace, there are several factors that will
influence future financial performance. These factors are
summarized below.
In September 1996, the state of California enacted a law (AB 1890)
restructuring California's electric industry. The legislation
adopts the December 1995 California Public Utilities Commission
(CPUC) policy decision that restructures the industry to stimulate
competition and reduce rates. The impact of AB 1890 on the
operations of the Company include:
-- 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 (i.e., private generators, brokers, etc.) or to
buy their power from the independent power exchange that serves as
a wholesale power pool allowing all energy producers to
participate competitively.
-- AB 1890 required a 10-percent reduction of residential and
small commercial customers' rates beginning in January 1998. As a
result, SDG&E received $658 million in December 1997 from the
proceeds of rate-reduction bonds issued by an agency of the state
of California. These bonds are being repaid over 10 years by
SDG&E's residential and small-commercial customers via a
nonbypassable charge on their electricity bills.
-- Utilities are allowed a reasonable opportunity to recover
their stranded costs through December 31, 2001. Stranded costs
such as those related to reasonable employee-related costs
directly caused by restructuring and purchased-power contracts may
be recovered beyond 2001.
-- AB 1890 included a rate freeze for all customers. Until the
earlier of March 31, 2002, or when transition cost recovery is
complete, SDG&E's average system rate will be frozen at 9.64 cents
per kilowatt-hour, except for impacts of natural gas price changes
and the mandatory 10-percent rate reduction.
See additional discussion in the annual Management's Discussion &
Analysis of Financial Condition and Results of Operations contained
elsewhere in this Current Report on Form 8-K.
In November 1997 SDG&E announced a plan to auction its power plants
and other electric-generating assets, enabling it to continue to
concentrate its business on the transmission and distribution of
electricity and natural gas in a competitive marketplace. The plan
includes the divestiture of SDG&E's fossil plants - the Encina
(Carlsbad, California) and South Bay (Chula Vista, California)
plants - and its combustion turbines, as well as its 20-percent
interest in the San Onofre Nuclear Generating Station (SONGS) and
its portfolio of long-term purchased-power contracts, including
those with qualifying facilities. The power plants, including the
interest in SONGS, have a net book value as of March 31, 1998 of
$700 million ($200 million for fossil and $500 million for SONGS)
and a combined generating capacity of 2,400 megawatts. The proceeds
from the auction will be applied directly to SDG&E's transition
costs (see Note 3 of the notes to supplemental consolidated
financial statements). SDG&E has proposed to the CPUC that the sale
of its fossil plants be completed by the end of 1998.
On July 16, 1997, the CPUC issued its final decision on
SoCalGas' application for PBR, which was filed with the CPUC in
1995. PBR replaces the general rate case and certain other
regulatory proceedings through December 31, 2002. Under PBR,
regulators allow future income potential to be tied to achieving or
exceeding specific performance and productivity measures, rather
than relying solely on expanding utility rate base in a market where
the Company already has a highly developed infrastructure. Key
elements of the PBR include a 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 ratebase, and rate
refunds to customers if service quality deteriorates.
SoCalGas implemented the base margin reduction effective August 1,
1997, and all other PBR elements on January 1, 1998. The CPUC
intends the PBR decision to be in effect for five years; however,
the CPUC decision allows for the possibility that changes to the PBR
mechanism could be adopted in a decision to be issued in the
Company's 1998 Biennial Cost Allocation Proceeding (BCAP)
application which is anticipated to become effective August 1, 1999.
SDG&E continues to participate in a PBR process for base rates, gas
procurement, and electric generation and dispatch.
See additional discussion in the annual Management's Discussion &
Analysis of Financial Condition and Results of Operations contained
elsewhere in this Current Report on Form 8-K.
For 1998, SoCalGas is authorized to earn a rate of return on common
equity of 11.6 percent and a 9.49 percent return on rate base, the
same as in 1997. SDG&E is authorized to earn a rate of return on
common equity of 11.6 percent and a rate of return on rate base of
9.35 percent, also unchanged from 1997.
OTHER
Sempra Energy Trading Corp., a leading natural gas and power
marketing firm headquartered in Greenwich, Connecticut, which was
acquired on December 31, 1997, recorded a net loss of $7 million for
the three months ended March 31, 1998. The loss was primarily due
to the amortization of costs associated with its purchase.
CES/Way International, Inc., which provides energy-efficiency
services including energy audits, engineering design, project
management, construction and financing and contract maintenance, was
acquired in January 1998.
In March 1998, the Company increased its existing investment in two
Argentine natural gas utility holding companies (Sodigas Pampeana
S.A and Sodigas Sur S.A.) by purchasing an additional 9-percent
interest for $40.1 million. With this purchase, the Company's
interest in the holding companies was increased to 21.5 percent.
The net loss for international operations was $2 million in the
first quarter of 1998 compared to net income of $0.3 million in
1997. The decrease is primarily due to increased expenses related
to the evaluation of international opportunities.
SEMPRA ENERGY
Supplemental Statements of Consolidated Income (unaudited)
Three Months Ended March 31,
----------------------------
(Dollars in millions, except per share amounts) 1998 1997
- --------------------------------------------------------------------------
Revenues and Other Income
Utility Revenues:
Gas $ 761 $ 848
Electric 497 374
Other Operating Revenues 77 69
Other Income 15 10
---------- ----------
Total 1,350 1,301
---------- ----------
Expenses
Cost of gas distributed 330 401
Purchased power 96 88
Electric fuel 31 39
Operating expenses 377 362
Depreciation and decommissioning 275 150
Franchise payments and other taxes 51 48
Preferred dividends of a subsidiary 4 5
--------- ---------
Total 1,164 1,093
--------- ---------
Income Before Interest and Income Taxes 186 208
Interest 55 51
--------- ---------
Income Before Income Taxes 131 157
Income taxes 44 59
--------- ---------
Net Income $ 87 $ 98
========= =========
Net Income Per Share of Common Stock (Basic) $ 0.37 $ 0.41
========= =========
Net Income Per Share of Common Stock (Diluted) $ 0.37 $ 0.41
========= =========
Common Dividends Declared Per Share $ 0.32 $ 0.31
========= =========
See notes to supplemental consolidated financial statements.
SEMPRA ENERGY
Supplemental Consolidated Balance Sheets
March 31, December 31,
(Dollars in millions) 1998 1997
(unaudited)
- ----------------------------------------------------------------------------
Assets
Current assets
Cash and cash equivalents $ 833 $ 814
Accounts receivable - trade 567 633
Accounts and notes receivable - other 149 202
Energy trading assets 734 587
Inventories 86 111
Regulatory balancing accounts -- 297
Other 41 112
------- -------
Total current assets 2,410 2,756
------- -------
Regulatory assets 681 609
Nuclear decommissioning trusts 433 399
Investments and other assets 1,049 868
------- -------
Total investments and other assets 2,163 1,876
------- -------
Property, plant and equipment 12,108 12,040
Less accumulated depreciation
and amortization (6,168) (5,921)
------- -------
Total property, plant and
equipment - net 5,940 6,119
------- -------
Total assets $ 10,513 $ 10,751
======= =======
See notes to supplemental consolidated financial statements.
SEMPRA ENERGY
Supplemental Consolidated Balance Sheets
March 31, December 31,
(Dollars in millions) 1998 1997
(unaudited)
- ----------------------------------------------------------------------------
Liabilities
Current liabilities
Short-term debt $ 113 $ 354
Accounts payable - trade 269 300
Energy trading liabilities 716 557
Dividends and interest payable 118 121
Long-term debt due within one year 125 270
Regulatory balancing accounts - net 21 --
Other 558 604
------- -------
Total current liabilities 1,920 2,206
------- -------
Long-term debt
Long-term debt 3,063 3,045
Debt of Employee Stock Ownership Plan 130 130
------- -------
Total long-term debt 3,193 3,175
------- -------
Deferred credits and other liabilities
Customer advances for construction 69 72
Post-retirement benefits other than pensions 242 248
Deferred income taxes 768 773
Deferred investment tax credits 154 123
Deferred credits and other liabilities 984 916
------- -------
Total deferred credits and
other liabilities 2,217 2,132
------- -------
Preferred stock of subsidiaries 203 279
------- -------
Commitments and contingent liabilities (Note 3)
Shareholders' Equity
Common stock 1,858 1,849
Retained earnings 1,169 1,157
Less deferred compensation relating to
Employee Stock Ownership Plan (47) (47)
------- -------
Total shareholders' equity 2,980 2,959
------- -------
Total liabilities and shareholders'
equity $ 10,513 $ 10,751
======= =======
See notes to supplemental consolidated financial statements.
SEMPRA ENERGY
Supplemental Statements of Consolidated Cash Flows
(unaudited)
Three Months Ended March 31
---------------------------
(Dollars in millions) 1998 1997
- -------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income $ 87 $ 98
Adjustments to Reconcile Net Income to Net Cash
Provided by Operating Activities:
Depreciation and decommissioning 275 150
Deferred income taxes and investment tax credits (57) 4
Application of balancing accounts to stranded costs (86) --
Other - net (38) (17)
Net changes in other working capital components 572 208
--------- ---------
Net cash provided by operating activities 753 443
--------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for Property, Plant and Equipment (78) (88)
Contributions to decommissioning funds (5) (6)
Other - net (111) 15
--------- ---------
Net cash used in investing activities (194) (79)
--------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES
Sale of Common Stock 9 2
Redemption of Common Stock (1) (84)
Redemption of Preferred Stock (75) --
Issues of Long-Term Debt 76 --
Payment on Long-Term Debt (201) (48)
Decrease in Short-Term Debt (272) (172)
Dividends on Common Stock (76) (77)
--------- ---------
Net cash used in financing activities (540) (379)
--------- ---------
Increase (Decrease) in Cash and Cash Equivalents 19 (15)
Cash and Cash Equivalents, January 1 814 429
--------- ---------
Cash and Cash Equivalents, March 31 $ 833 $ 414
========= =========
Supplemental Disclosure of Cash Flow Information
Income tax payments (refunds) $ 7 $ (37)
========= =========
Interest payments, net of amounts capitalized $ 59 $ 48
========= =========
Supplemental Schedule of NonCash Activities
Real estate investments acquired $ -- $ 75
Cash paid -- --
--------- ---------
Liabilities assumed $ -- $ 75
========= =========
See notes to supplemental consolidated financial statements.
SEMPRA ENERGY
FOR THE THREE MONTHS ENDED MARCH 31, 1998.
NOTES TO SUPPLEMENTAL CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
1. BUSINESS COMBINATION
On June 26, 1998 (pursuant to an October 1996 agreement) Enova
Corporation (Enova) and Pacific Enterprises (PE) combined the two
companies into a new company named Sempra Energy. As a result of
the combination, (i) each outstanding share of common stock of
Enova converts into one share of common stock of Sempra Energy,
(ii) each outstanding share of common stock of PE converts into
1.5038 shares of common stock of Sempra Energy and (iii) the
preferred stock and preference stock of Enova's principal
subsidiary, San Diego Gas & Electric Company (SDG&E); PE; and PE's
principal subsidiary, Southern California Gas Company (SoCalGas)
remain outstanding.
Generally accepted accounting principles proscribe giving effect to
a consummated business combination accounted for by the pooling of
interests method in financial statements that do not include the
period during which consummation occurred. These supplemental
consolidated financial statements do not extend through the date of
consummation of the business combination; however, they will become
the historical consolidated financial statements of Sempra Energy
and subsidiaries when financial statements covering the date of
consummation of the business combination are issued.
The per-share data shown on the supplemental consolidated
statements of income reflect the conversion of Enova common stock
and of PE common stock into Sempra Energy common stock, as
described above. The supplemental consolidated financial statements
are presented as if the companies were combined during all periods
included therein.
Financial statement presentation differences between Enova and PE
have been adjusted in the financial statements. Pro forma
adjustments for the periods presented were made to eliminate
intercompany transactions between Enova and PE and to reflect the
consolidation of certain subsidiaries, Sempra Energy Solutions,
Sempra Energy Trading and two Mexican joint ventures, Distribuidora
de Gas Natural de Mexicali and Distribuidora de Gas Natural de
Chihuahua, that were previously accounted for by the equity method
on the separate books of Enova and PE. The only significant
intercompany adjustments were the eliminations of SoCalGas' sales
of natural-gas transportation and storage to SDG&E. These sales
amounted to $12 million and $11 million for the three-month periods
ended March 31, 1998 and 1997, respectively. The net effects from
the consolidation of the previously unconsolidated subsidiaries
increased Sempra Energy's total revenues and other income by $53
million for the three months ended March 31, 1998 and total assets
by $637 million at March 31, 1998 from the combined amounts that
were separately reported in the Enova and PE financial statements.
The elimination of intercompany sales (primarily the sales of
natural-gas transportation and storage from SoCalGas to SDG&E)
reduced total revenues and other income by $3 million and $11
million for the three months ended March 31, 1998 and 1997,
respectively.
The results of operations for PE and Enova as reported as separate
companies for the three months ended March 31 are as follows (in
millions of dollars):
Pacific Enterprises Enova
------------------------ -----------------------
1998 1997 1998 1997
---- ---- ---- ----
Revenues and
Other Income $ 678 $ 803 $ 616 $ 509
Net Income $ 39 $ 49 $ 48 $ 49
None of the future impacts resulting from combining the operations
of Enova and PE, such as the estimated cost savings arising from
the business combination, have been reflected in the financial
statements. Transaction costs (including fees for financial
advisors, attorneys, consultants, filings and printing) have been
charged to operating and maintenance expense as incurred in
accordance with Accounting Principles Board Opinion No. 16
"Business Combinations." These amounted to $1 million and $3
million for the three-month periods ended March 31, 1998 and 1997,
respectively. An additional $23 million is expected to be incurred
subsequent to March 31, 1998.
Additional information on the business combination is discussed in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations."
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The accompanying supplemental consolidated financial statements
have been prepared in accordance with the interim-period reporting
requirements of Form 10-Q. The financial statements presented
herein represent the consolidated statements of Sempra Energy and
its subsidiaries. Unless otherwise indicated, the "Notes to
Supplemental Financial Statements" and "Management's Discussion and
Analysis of Financial Condition and Results of Operations" herein
pertain to Sempra Energy as a consolidated entity.
Generally accepted accounting principles proscribe giving effect
to a consummated business combination accounted for by the
pooling of interests method in financial statements that do not
include the period during which consummation occurred. These
supplemental consolidated financial statements do not extend
through the date of consummation of the business combination;
however, they will become the historical consolidated financial
statements of Sempra Energy and subsidiaries when financial
statements covering the date of consummation of the business
combination are issued.
Results of operations for interim periods are not necessarily
indicative of results for the entire year. In order to match
revenues and costs for interim reporting purposes, certain Sempra
Energy subsidiaries defer revenues related to costs which are
expected to be incurred later in the year. Sempra Energy believes
that all adjustments necessary to present a fair statement of the
consolidated financial position and results of operations for the
periods covered by this report, consisting of recurring accruals,
have been made. These adjustments are of a normal recurring nature.
Certain changes in account classification have been made in the
financial statements pertaining to March 31, 1997 to conform to the
1998 financial statement presentation.
Significant accounting policies, including those of the
subsidiaries, are described in the notes to supplemental
consolidated financial statements contained elsewhere in this
Current Report on Form 8-K. The same accounting policies are
followed for interim reporting purposes.
This quarterly report should be read in conjunction with Sempra
Energy's annual supplemental consolidated financial statements and
notes thereto, and the annual "Management's Discussion & Analysis
of Financial Condition and Results of Operations" contained
elsewhere in this Current Report on Form 8-K.
3. MATERIAL CONTINGENCIES
INDUSTRY RESTRUCTURING -- CALIFORNIA PUBLIC UTILITIES COMMISSION
In September 1996 the state of California enacted a law
restructuring California's electric utility industry (AB 1890). The
legislation adopts the December 1995 California Public Utilities
Commission (CPUC) policy decision that restructures the industry to
stimulate competition and reduce rates.
Beginning on March 31, 1998 customers were given the opportunity to
choose to continue to purchase their electricity from the local
utility under regulated tariffs, to enter into contracts with other
energy service providers (i.e., private generators, brokers, etc.)
or 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, nuclear units and, lastly, from the lowest-bidding
suppliers. The California investor-owned electric utilities (IOUs)
are obligated to bid their power supply, including electric
generation and purchased-power contracts, into the PX. An
Independent System Operation (ISO) schedules power transactions and
access to the transmission system. The local utility continues to
provide distribution service regardless of which source the
customer chooses.
As discussed in Note 13 in the notes to supplemental consolidated
financial statements contained elsewhere in this Current Report on
Form 8-K, the IOUs have been given a reasonable opportunity to
recover their stranded costs via a competition transition charge
(CTC) to customers through December 31, 2001. SDG&E has identified
that its estimated transition costs total $2 billion (net present
value in 1998 dollars). Through March 31, 1998 SDG&E has recovered
transition costs of $0.3 billion for nuclear generation, $0.1
billion for non-nuclear generation and $0.1 billion for purchased-
power contracts. Additionally, overcollections of $0.1 billion
recorded in the Energy Cost Adjustment Clause and Electric Revenue
Adjustment Mechanism balancing accounts at December 31, 1997 have
been applied to transition cost recovery, leaving approximately
$1.4 billion for future CTC recovery. Included therein is $0.4
billion for post-2001 purchased-power contract payments that may be
recovered after 2001, subject to an annual reasonableness review.
During the 1998-2001 period, recovery of transition costs is
limited by the rate cap (discussed below). Generation plant
additions made after December 20, 1995 are not eligible for
transition cost recovery. Instead, each utility must file a
separate application seeking a reasonableness review thereof. The
CPUC has approved an agreement between SDG&E and the CPUC's Office
of Ratepayer Advocates for the recovery of $13.6 million of SDG&E's
$14.5 million in 1996 capital additions for the Encina and South
Bay power plants.
In November 1997 SDG&E announced a plan to auction its power plants
and other electric-generating assets. This plan includes the
divestiture of SDG&E's fossil power plants and combustion turbines,
its 20-percent interest in San Onofre Nuclear Generating Station
(SONGS) and its portfolio of long-term purchased-power contracts.
The power plants have a net book value as of March 31, 1998 of $700
million ($200 million for fossil and $500 million for SONGS). The
proceeds from the auction will be applied directly to SDG&E's
transition costs. SDG&E has proposed to the CPUC that the sale of
its fossil plants be completed by the end of 1998. Management
believes that the rates within the rate cap and the proceeds from
the sale of electric-generating assets will be sufficient to
recover all of SDG&E's approved transition costs by December 31,
2001, not including the post-2001 purchased-power contract payments
that may be recovered after 2001 (see discussion above). However,
if the proceeds from the sale of the power plants are less than
expected or if generation costs, principally fuel costs, are
greater than anticipated, SDG&E may be unable to recover all of its
approved transition costs. This would result in a charge against
earnings at the time it becomes probable that SDG&E will be unable
to recover all of the transition costs.
California's electric restructuring law (AB 1890) required a 10-
percent reduction of residential and small commercial customers'
rates beginning in January 1998. AB 1890 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 charge on their electric bills. In 1997 SDG&E
formed a subsidiary, SDG&E Funding LLC, to facilitate the issuance
of the rate-reduction 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 customers. Consequently, the revenue streams
are not the property of SDG&E nor are they available to satisfy any
claims of SDG&E's creditors.
In June 1998 a coalition of consumer groups received verification
that its electric restructuring ballot initiative received the
needed signatures to qualify for the November 1998 California
ballot. The initiative, among other things, could result in an
additional 10-percent rate reduction, require that this rate
reduction be achieved through the elimination or reduction of CTC
payments and prohibit the collection of the charge on customer
bills that would finance the rate reduction. In May 1998 a
statewide coalition of California's investor-owned electric
utilities and business groups filed a lawsuit with a California
District Court of Appeals to block the initiative. SDG&E cannot
predict the final outcome of the initiative. If the initiative were
to be voted into law and upheld by the courts, the financial impact
on Sempra Energy could be substantial.
AB 1890 includes a rate freeze for all customers. Until the earlier
of March 31, 2002, or when transition cost recovery is complete,
SDG&E's system average rate will be frozen at June 10, 1996 levels
(9.64 cents per kilowatt-hour (kwh)), except for the impact of
certain fuel cost changes and the 10-percent rate reduction
described above. Beginning in 1998 rates were fixed at 9.43 cents
per kwh, which includes the maximum permitted increase related to
fuel cost increases and the mandatory rate reduction.
SDG&E and SoCalGas have been accounting for the economic effects of
regulation on all of their utility operations in accordance with
SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation," as described in the notes to supplemental consolidated
financial statements contained elsewhere in this Current Report on
Form 8-K. SDG&E has ceased the application of SFAS No. 71 to its
generation business, in accordance with the conclusion of the
Financial Accounting Standards Board that the application of SFAS
No. 71 should be discontinued when legislation is issued that
determines that a portion of an entity's business will no longer be
regulated. The discontinuance of SFAS No. 71 has not resulted in a
write-off of SDG&E's generation assets, since the CPUC has approved
the recovery of these assets by the distribution portion of its
business, subject to the rate cap.
INDUSTRY RESTRUCTURING -- FEDERAL ENERGY REGULATORY COMMISSION
In October 1997 the FERC approved key elements of the California
IOUs' restructuring proposal. This included the transfer by the
IOUs of the operational control of their transmission facilities to
the ISO, which is under FERC jurisdiction. The FERC also approved
the establishment of the California PX to operate as an independent
wholesale power pool. The IOUs pay to the PX an up-front
restructuring charge (in four annual installments) and an
administrative-usage charge for each megawatt-hour of volume
transacted. SDG&E's share of the restructuring charge is
approximately $10 million, which is being recovered as a transition
cost. The IOUs have jointly guaranteed $300 million of commercial
loans to the ISO and PX for their development and initial start-up.
SDG&E's share of the guarantee is $30 million.
QUASI-REORGANIZATION
In 1993 PE completed a strategic plan to refocus on its natural-gas
utility and related businesses. The strategy included the
divestiture of its merchandising operations and all 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. Certain of the
liabilities established in connection with discontinued operations
and the quasi-reorganization will be resolved in future years. As
of March 31, 1998 the provisions previously established for these
matters are adequate.
NUCLEAR INSURANCE
SDG&E and the co-owners of the SONGS units have purchased primary
insurance of $200 million, the maximum amount available, for public
liability claims. An additional $8.7 billion of coverage is
provided by secondary financial protection required by the Nuclear
Regulatory Commission and provides for loss sharing among utilities
owning nuclear reactors if a costly accident occurs. SDG&E could be
assessed retrospective premium adjustments of up to $32 million in
the event of a nuclear incident involving any of the licensed,
commercial reactors in the United States, if the amount of the loss
exceeds $200 million. In the event the public liability limit
stated above is insufficient, the Price-Anderson Act provides for
Congress to enact further revenue-raising measures to pay claims,
which could include an additional assessment on all licensed
reactor operators.
Insurance coverage is provided for up to $2.75 billion of property
damage and decontamination liability. Coverage is also provided for
the cost of replacement power, which includes indemnity payments
for up to three years, after a waiting period of 17 weeks. Coverage
is provided through mutual insurance companies owned by utilities
with nuclear facilities. If losses at any of the nuclear facilities
covered by the risk-sharing arrangements were to exceed the
accumulated funds available from these insurance programs, SDG&E
could be assessed retrospective premium adjustments of up to $6
million.
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration
Statement Number 333-51309 of Sempra Energy on Form S-3 of our
report dated June 26, 1998 on the supplemental consolidated
financial statements, appearing in this Current Report on Form 8-K
of Sempra Energy dated June 26, 1998.
/S/ Deloitte & Touche LLP
DELOITTE & TOUCHE LLP
San Diego, California
June 26, 1998
