SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the fiscal year ended December 31, 2001
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OR
[ ] Transition report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 for the transition period from
to
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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)
Registrant's telephone number, including area code (619)696-2000
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of each exchange
Title of each class on which registered
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Common Stock, Without Par Value New York and Pacific
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months and
(2) has been subject to such filing requirements for the past 90
days. Yes [ X ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant
to Item 405 of Regulation S-K is not contained herein, and will not
be contained, to the best of registrant's knowledge, in definitive
proxy or information statements incorporated by reference in Part
III of this Form 10-K or any amendment to this Form 10-K. [X]
Exhibit Index on page 33. Glossary on page 40.
Aggregate market value of the voting stock held by non-affiliates
of the registrant as of February 28, 2002 was $4.6 billion.
Registrant's common stock outstanding as of February 28, 2002 was
205,057,502 shares.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the 2001 Annual Report to Shareholders are incorporated
by reference into Parts I, II, and IV.
Portions of the Proxy Statement prepared for the May 2002 annual
meeting of shareholders are incorporated by reference into Part
III.
TABLE OF CONTENTS
PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . 4
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . .23
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . .24
Item 4. Submission of Matters to a Vote of Security Holders. .24
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . .25
Item 6. Selected Financial Data. . . . . . . . . . . . . . . .25
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . .25
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk . . . . . . . . . . . . . . . . .25
Item 8. Financial Statements and Supplementary Data. . . . . .26
Item 9. Changes In and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . .26
PART III
Item 10. Directors and Executive Officers of the Registrant . .26
Item 11. Executive Compensation . . . . . . . . . . . . . . . .27
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . .27
Item 13. Certain Relationships and Related Transactions . . . .27
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . .27
Independent Auditors' Consent and Report on Schedule. . . . . .29
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . .32
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . .33
Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . .40
This Annual Report contains statements that are not historical fact
and constitute forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995. The words
"estimates," "believes," "expects," "anticipates," "plans," "intends,"
"may," "would" and "should" or similar expressions, or discussions of
strategy or of plans are intended to identify forward-looking
statements. Forward-looking statements are not guarantees of
performance. They involve risks, uncertainties and assumptions. Future
results may differ materially from those expressed in these forward-
looking statements.
Forward-looking statements are necessarily based upon various
assumptions involving judgments with respect to the future and other
risks, including, among others, local, regional, national and
international economic, competitive, political, legislative and
regulatory conditions and developments; actions by the CPUC, the
California Legislature, the DWR, and the FERC; the financial condition
of other investor-owned utilities; capital market conditions,
inflation rates, interest rates and exchange rates; energy and trading
markets, including the timing and extent of changes in commodity
prices; weather conditions and conservation efforts; business,
regulatory and legal decisions; the pace of deregulation of retail
natural gas and electricity delivery; the timing and success of
business development efforts; and other uncertainties, all of which
are difficult to predict and many of which are beyond the control of
the company. Readers are cautioned not to rely unduly on any forward-
looking statements and are urged to review and consider carefully the
risks, uncertainties and other factors which affect the company's
business described in this annual report and other reports filed by
the company from time to time with the Securities and Exchange
Commission.
PART I
ITEM 1. BUSINESS
Description of Business
A description of Sempra Energy and its subsidiaries (the company) is
given in "Management's Discussion and Analysis of Financial Condition
and Results of Operations" of the 2001 Annual Report to Shareholders,
which is incorporated by reference.
GOVERNMENT REGULATION
The most significant government regulation affecting Sempra Energy is
that affecting its utility subsidiaries, which is discussed below.
Other subsidiaries are also subject to governmental regulation.
Local Regulation
Southern California Gas Company (SoCalGas) has gas franchises with the
239 legal jurisdictions in its service territory. These franchises
allow SoCalGas to locate facilities for the transmission and
distribution of natural gas in the streets and other public places.
Some franchises have fixed terms, such as that for the city of Los
Angeles, which expires in 2012. Most of the franchises do not have
fixed terms and continue indefinitely. The range of expiration dates
for the franchises with definite terms is 2003 to 2048.
San Diego Gas and Electric (SDG&E) has electric franchises with the
three counties and the 26 cities, and gas franchises with one county
and the 23 cities in its service territory. These franchises allow
SDG&E to locate facilities for the transmission and distribution of
electricity and/or natural gas in the streets and other public places.
The franchises do not have fixed terms, except for the electric and
natural gas franchises with the cities of Chula Vista (2003),
Encinitas (2012), San Diego (2021) and Coronado (2028); and the
natural gas franchises with the city of Escondido (2036) and the
county of San Diego (2030).
California Utility Regulation
The State of California Legislature, from time to time, passes laws
that regulate SDG&E's and SoCalGas' operations. For example, in 1996
the legislature passed an electric industry deregulation bill, and
then in 2000 and 2001 passed additional bills aimed at addressing
problems in the deregulated electric industry. In addition, the
legislature enacted a law in 1999 addressing natural gas industry
restructuring.
The California Public Utilities Commission (CPUC), which consists of
five commissioners appointed by the Governor of California for
staggered six-year terms, regulates SDG&E's and SoCalGas' rates and
conditions of service, sales of securities, rate of return, rates of
depreciation, uniform systems of accounts, examination of records, and
long-term resource procurement. The CPUC also conducts various reviews
of utility performance and conducts investigations into various
matters, such as deregulation, competition and the environment, to
determine its future policies.
The California Energy Commission (CEC) has discretion over electric-
demand forecasts for the state and for specific service territories.
Based upon these forecasts, the CEC determines the need for additional
energy sources and for conservation programs. The CEC sponsors
alternative-energy research and development projects, promotes energy
conservation programs and maintains a state-wide plan of action in
case of energy shortages. In addition, the CEC certifies power-plant
sites and related facilities within California.
United States Utility Regulation
The Federal Energy Regulatory Commission (FERC) regulates the
interstate sale and transportation of natural gas, the transmission
and wholesale sales of electricity in interstate commerce,
transmission access, the uniform systems of accounts, rates of
depreciation, and electric rates involving sales for resale.
The Nuclear Regulatory Commission (NRC) oversees the licensing,
construction and operation of nuclear facilities. NRC regulations
require extensive review of the safety, radiological and environmental
aspects of these facilities. Periodically, the NRC requires that newly
developed data and techniques be used to re-analyze the design of a
nuclear power plant and, as a result, requires plant modifications as
a condition of continued operation in some cases.
International Utility Regulation
The company's consolidated and unconsolidated affiliates have
locations in Argentina, Canada, Chile, Mexico, Peru and Uruguay. These
operations are subject to the local, federal and other regulations of
the countries in which they are located.
Other Regulation
As a trading company, Sempra Energy Trading has locations and
operations in North America, Europe, Asia and South America, and is
subject to regulation as to its operations and its financial position.
Other subsidiaries are also subject to varying amounts of regulation
by various governments, including other states in the United States.
Licenses and Permits
SoCalGas and SDG&E obtain a number of permits, authorizations and
licenses in connection with the transmission and distribution of
natural gas. In addition, SDG&E obtains a number of permits,
authorizations and licenses in connection with the transmission and
distribution of electricity. Both require periodic renewal, which
results in continuing regulation by the granting agency. The company's
unregulated affiliates are also required to obtain permits,
authorizations and licenses in the normal course of business.
Other regulatory matters are described in Notes 14 and 15 of the 2001
Annual Report to Shareholders, which is incorporated by reference.
SOURCES OF REVENUE
Industry segment information is contained in "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and in
Note 16 of the notes to Consolidated Financial Statements of the 2001
Annual Report to Shareholders, which is incorporated by reference.
Various information concerning revenue and revenue recognition is
provided in Note 2 of the notes to Consolidated Financial Statements
of the 2001 Annual Report to Shareholders, which is incorporated by
reference.
NATURAL GAS OPERATIONS
The company purchases, sells, distributes, stores and transports
natural gas. SoCalGas owns and operates a natural gas distribution,
transmission and storage system that supplies natural gas to 5.1
million end-use customers throughout a 23,000-square-mile service
territory from central California to the Mexican border. SoCalGas also
transports gas to about 1,300 utility electric generation (UEG),
wholesale, large commercial, industrial and off-system (outside the
company's normal service territory) customers. SDG&E purchases and
distributes natural gas to 774,000 end-use customers throughout the
western portion of San Diego county. SDG&E also transports gas to over
1,000 customers who procure their gas from other sources. On a smaller
scale, Sempra Energy International (SEI) operates natural gas
distribution systems in Mexico through 60 percent, 95 percent and 100
percent ownership of companies operating in Mexicali, Chihuahua and La
Laguna Durango, respectively. SEI also has a 10-year contract to
deliver up to 300 million cubic feet per day of natural gas to a power
plant in Rosarito, Mexico. These North American operations are
included in the following discussion of the company's natural gas
operations. SEI also has interests in natural gas operations in South
America which are not consolidated and, therefore, are not included in
these discussions. Additional information on international operations
is provided in "Management's Discussion and Analysis of Financial
Condition and Results of Operations."
In December 1999, Sempra Atlantic Gas (SAG), a subsidiary of SEI, was
awarded a 25-year franchise by the provincial government of Nova
Scotia to build and operate a natural gas distribution system. In
September 2001, due to new conditions required by the government of
Nova Scotia, SAG notified the government that it intended to surrender
its natural gas distribution franchise.
Supplies of Natural Gas
The company buys natural gas under several short-term and long-term
contracts. Short-term purchases are from various Southwest U.S. and
Canadian suppliers and are primarily based on monthly spot-market
prices. SoCalGas and SDG&E transport gas under long-term firm pipeline
capacity agreements that provide for annual reservation charges, which
are recovered in rates. SoCalGas has commitments for firm pipeline
capacity under contracts with pipeline companies that expire at
various dates through 2006. SDG&E has long-term natural gas
transportation contracts with various interstate pipelines which
expire on various dates between 2003 and 2023.
Most of the natural gas purchased and delivered by the company is
produced outside of California. These supplies are delivered to the
company's intrastate transmission system by interstate pipeline
companies, primarily El Paso Natural Gas Company and Transwestern
Natural Gas Company. These interstate companies provide transportation
services for supplies purchased from other sources by the company or
its transportation customers. The rates that interstate pipeline
companies may charge for natural gas and transportation services are
regulated by the FERC.
The following table shows the sources of natural gas deliveries for
SoCalGas and SDG&E (collectively, the California utilities) from 1997
through 2001:
ENERGY PURCHASE AGREEMENT
This ENERGY PURCHASE AGREEMENT (this "Agreement") is made and entered into as of the date set forth below, by and between the Department of Water Resources, an agency of the State of California, with respect to the Department of Water Resources Electric Power Fund separate and apart from its powers and responsibilities with respect to the State Water Resources Development System ("Department") and Sempra Energy Resources, a California corporation ("SER").
RECITALS
A. Department requires electric energy in connection with its responsibilities, as set forth in California Water Code Section 80000 et seq., with respect to the Department of Water Resources Electric Power Fund (the "Fund"), as established by February 1, 2001, Assembly Bill 1, First Extraordinary Session (the "Act").
B. Department solicited bids for energy pursuant to a Request for Bids ("RFB") published by Department on February 2, 2001.
C. Certain affiliates of SER (the "Project Companies") own and operate, or will own, lease and/or operate, the generating facilities described in Appendix B (the "Projects").
D. On February 28, 2001, SER submitted a revised bid pursuant to the RFB to provide energy to Department with the intention of assigning portions of its rights and obligations under any resulting energy purchase agreement to the Project Companies.
E. On February 28, 2001, Department executed SER's bid made pursuant to the RFB.
F. The RFB provides that "[n]o binding commitment shall arise on the part of CDWR to any Bidder under this Request for Bids until and unless the Parties sign documents of agreement that become effective in accordance with their terms"; and
G. This Agreement is the binding and definitive agreement of the Parties as to the energy sale contemplated by SER's bid, Department's acceptance of that bid and subsequent revisions to SER's bid requested by Department.
NOW, THEREFORE, in consideration of the foregoing, and of other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Department and SER hereto agree as follows:
ARTICLE I
DEFINITIONS AND INTERPRETATION
Section 1.01. Definitions. The following terms have the respective meanings in this Agreement:
"AAA" means the American Arbitration Association.
"AAA Rules" means the Commercial Arbitration Rules of the AAA.
"Act" has the meaning set forth in the Recitals hereto.
"Agreement" has the meaning set forth in the Preamble hereto.
"Affiliate" means, with respect to any person, any other person (other than an individual) that, directly or indirectly, through one or more intermediaries, controls, or is controlled by, or is under common control with, such person. For this purpose, "control" means the direct or indirect ownership of fifty percent (50%) or more of the outstanding capital stock or other equity interests having ordinary voting power.
"Alternative Delivery Point" has the meaning set forth in Section 2.06 hereof.
"Annual Energy Delivery Plan" has the meaning set forth in Section 2.05(a) hereof.
"Associated Cal ISO Delivery Zone" means, with respect to a Delivery Point associated with a Project, the Cal ISO Delivery Zone for the Delivery Point identified in Appendix B (Column (D)) and, with respect to Cal ISO Delivery Points associated with Market Sources and Alternative Delivery Points, the Cal ISO Delivery Zone (SP15, NP15, ZP26) in which such Delivery Point resides or to which such Delivery Point is adjacent.
"As Available Resources" means the Maximum Capacity at the Delivery Point that could be provided from a Market Source, the El Dorado Project and/or the Elk Hills (SC) Project for the period commencing at 12:00 a.m. (Pacific Time) on April 1, 2002 and ending at 11:59 p.m. (Pacific Time) on May 31, 2003.
"Authorized Representative" means the person or persons designated in Appendix A as having full authority to act on behalf of a Party for all purposes hereof.
"Billing Address" means the billing address specified in Appendix A or as otherwise specified by Department.
"Billing Period" has the meaning set forth in Section 4.01 hereof.
"Bond Offering" means an offering by Department of bonds with recourse only to the Trust Estate, a maturity of ten (10) or more years and an Investment Grade rating for the purposes specified in Section 80010(a) of the Act.
"Bond Trustee" means any financial institution designated in a resolution of Department or an indenture with Department as the trustee thereunder in connection with its Bond Offering.
"Business Day" means any day other than a Saturday or Sunday or a United States holiday, as observed by Federal Reserve member banks in New York City.
"Cal ISO" means the California Independent System Operator.
"Cal ISO Delivery Points" means any point on the transmission grid currently controlled by and any scheduling point of the Cal ISO.
"Cal ISO Delivery Zone" means, with respect to a Delivery Point listed in Appendix B (Column (D)), the Cal ISO Zone associated with such Delivery Point (SP15, NP15, ZP26), as indicated in Appendix B (Column (E)).
"Cal ISO Zone" means a congestion management zone designated as "SP15," "NP15" or "ZP26" in Appendix I to the Cal ISO FERC Electric Tariff filed with FERC.
"Capacity" means the net power (in MW), as described in Appendix C and as modified in this Agreement, with respect to which Seller is providing Energy to Department under this Agreement.
"Commercial Operation" means, with respect to each Project, the successful completion of all permitting, construction and testing of generating and associated facilities of the Project, Transmission Provider and Interconnection Service Provider such that Seller believes, using its reasonably exercised discretion, that Seller can safely, reliably and lawfully provide Energy from the Project up to the Maximum Capacity at the Delivery Point to Department at the Delivery Point associated with the Project.
"Commercial Operation Target Date" means, with respect to each Project, the date on which SER anticipates that such Project will commence Commercial Operation. The Commercial Operation Target Date for each Project is set forth in Appendix B and may be adjusted pursuant to Section 2.10.
"Contractual Gas Requirement" means, with respect to any Billing Period, the estimated total amount of Natural Gas (in MMBtu) required to generate the Energy during such Billing Period, calculated in accordance with the formula contained in Section 2.03(c).
"Copper Mountain Project" means the planned Copper Mountain power plant and associated facilities near Boulder City, Nevada.
"Costs" has the meaning set forth in Section 6.04 hereof.
"CPUC" means the Public Utilities Commission of California.
"Delivery Point" means any of the points of delivery listed in Appendix B (Column (D)) or any Alternative Delivery Point.
"Economy Energy" means power sales by Seller or to Department made on a "non-firm," "interruptible" or "as available" basis or on a "firm" basis under agreements of less than one (1) year in duration.
"El Dorado Project" means the existing 480 MW El Dorado Energy power plant and associated facilities in Boulder City, Nevada, in which SER owns a fifty percent (50%) interest as of the date of this Agreement.
"Elk Hills (SC) Project" means the planned Elk Hills power plant and associated facilities near Bakersfield, California during the time period when such plant is operating on a simple-cycle basis.
"Enabling Agreement" means an umbrella service agreement under SER's Tariff between Seller and Department, which umbrella service agreement shall be filed with the FERC.
"Energy" means the aggregate amount of electric energy (in MW-hours) to be provided from the Capacity for the relevant number of hours in each time period as described in Appendix C.
"EPNG" means El Paso Natural Gas Company.
"Event of Default" has the meaning set forth in Section 6.01 hereof.
"FERC" means the Federal Energy Regulatory Commission.
"FPA" has the meaning set forth in Section 2.09 hereof.
"Fuel Supply Plan" has the meaning set forth in Section 2.03 hereof.
"Fuel Supply Year" means the period commencing at 12:00 a.m. (Pacific Time) on June 1, 2003 and ending at 11:59 p.m. (Pacific Time) at December 31, 2003, each of the calendar years of the Term 2004 through and including 2010 and the period commencing at 12:00 a.m. (Pacific Time) on January 1, 2011 and ending at 11:59 p.m. (Pacific Time) on September 30, 2011.
"Fund" has the meaning set forth in the Recitals hereto.
"Gas Price" means the price of Natural Gas (in dollars per MMBtu) determined in accordance with the formula contained in Section 2.03(c).
"Interest Rate" means, for any date, the lesser of: (a) the per annum rate of interest equal to the prime lending rate as may from time to time be published in The Wall Street Journal under "Money Rates" on such day (or if not published on such day on the most recent preceding day on which published), plus two hundred (200) basis points, and (b) the maximum rate permitted by applicable law.
"Interconnection Service Provider" means any entity or entities providing service by which a Project interconnects with a Transmission Provider as needed to transmit or transport Energy from Seller to a Delivery Point.
"Investment Grade" means, with respect to a person, a rating on such person's senior long-term unsecured debt at or above "BBB-" by S&P or "Baa3" by Moody's.
"Kern River" means Kern River Gas Transmission Company.
"Market Quotation Average Price" means the average of the good faith quotations (in dollars per MW-hour) solicited from not less than five (5) Reference Market-makers disregarding the highest and lowest quotations. If quotations cannot be obtained from five (5) Reference Market-makers, the Market Quotation Price shall be the average of all quotations received.
"Market Source" means any marketer, trader, seller or generator other than the Projects (including Seller's Affiliates) from which Seller could obtain power supplies.
"Market Value" has the meaning set forth in Section 6.04 hereof.
"Maximum Capacity at the Delivery Point" means the Capacity associated with the Delivery Points in Appendix B but does not establish any limitation on the amount of Energy that may be delivered at any of those Delivery Points.
"Mesquite Project" means the planned Mesquite power plant and associated facilities in Arlington, Arizona.
"MMBtu" means one million British thermal units, where British thermal units represent the amount of heat required to raise the temperature of one pound of pure water from 59° F to 60° F at a constant pressure of 14.73 pounds per square inch.
"Monthly Energy Delivery Plan" has the meaning set forth in Section 2.05(b) hereof.
"Moody's" means Moody's Investors Service, Inc.
"MW" means megawatt, a measure of electric generating capacity.
"Natural Gas" means methane or other gaseous hydrocarbons meeting the quality standards and specifications of Seller and the applicable Natural Gas Service Provider.
"Natural Gas Service Provider" means any entity that provides Natural Gas transportation, distribution, storage and/or other delivery services relating to Seller's provision of Energy to Department pursuant to this Agreement.
"NERC" means the North American Electric Reliability Council.
"NERC Holiday" means a holiday defined by NERC.
"Non-Defaulting Party" has the meaning set forth in Section 6.03 hereof.
"Party" means Department or Seller.
"Per Unit Market Price" means the applicable price (in dollars per MW-hour) determined in accordance with Section 6.04.
"Present Value Rate" has the meaning set forth in Section 6.04 hereof.
"Project" has the meaning set forth in the Recitals hereto.
"Project Companies" has the meaning set forth in the Recitals hereto.
"Project Company Assignment and Assumption Agreement" means the agreement by which SER may make an assignment of its rights and obligations under this Agreement with respect to a Project to a Project Company. A form of Project Company Assignment and Assumption Agreement is set forth in Appendix F.
"Project Energy" means the portion of the Energy to be provided by a Project Company as a result of an assignment pursuant to Section 9.02(a).
"Project Lender" means a lender providing all or part of the initial construction and/or debt financing for a Project, or any refinancing thereof, in the form of senior debt, and any fiscal agents, trustees or other nominees acting on their behalf.
"Prudent Electric Practice" means any of the practices, methods and/or acts (i) required by the National Electric Safety Code or NERC, whether or not Seller is a member thereof, or (ii) otherwise engaged in or approved by a significant portion of the non-utility electric generation industry during the relevant time period or any of the practices, methods and acts that in the exercise of commercially reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Prudent Electric Practice is not intended to be the optimum practice, method or act to the exclusion of all others, but rather to be any of the practices, methods and/or acts generally accepted in the region.
"Purchase Price" has the meaning set forth in Section 2.02 hereof.
"Reduced Amount" has the meaning set forth in Section 2.10 hereof.
"Reference Market-maker" means any marketer, trader or seller of or dealer in energy products whose long-term unsecured senior debt has an Investment Grade rating.
"Replacement Contract" means a contract having a term, transaction quantity and quality, delivery rate, Delivery Point and product configuration substantially similar to the remaining Term, transaction quantity and quality, delivery rate, Delivery Point and product configuration of a Transaction.
"Replacement Price" means the price (in dollars per MW-hour) at which Department, acting in a commercially reasonable manner, purchases substitute Energy at the Delivery Point as a replacement for any Energy not delivered by Seller hereunder, plus (i) costs reasonably incurred by Department in purchasing such substitute Energy and (ii) additional transmission or other charges, if any, reasonably incurred by Department to the Delivery Point, or at Department's option, the market price at the Delivery Point for such Energy not delivered as determined by Department in a commercially reasonable manner; provided, however, in no event shall such price include any penalties, ratcheted demand or similar charges, nor shall Department be required to utilize or change its utilization of its owned or controlled assets or market positions to minimize Seller's liability. For purposes of this definition, Department shall be considered to have purchased substitute Energy to the extent Department shall h ave entered into one or more arrangements in a commercially reasonable manner whereby Department repurchases its obligation to purchase and receive the Energy from another party at the Delivery Point.
"S&P" means Standard & Poor's Rating Group (a division of McGraw-Hill, Inc.).
"Sale Price" means the price (in dollars per MW-hour) at which Seller, acting in a commercially reasonable manner, resells at the Delivery Point any Energy not received by Department, deducting from such proceeds any (i) costs reasonably incurred by Seller in reselling such Energy and (ii) additional transmission charges, if any, reasonably incurred by Seller in delivering such Energy to the third party purchasers, or at Seller's option, the market price at the Delivery Point for such Energy not received as determined by Seller in a commercially reasonable manner; provided, however, in no event shall such price include any penalties, ratcheted demand or similar charges nor shall Seller be required to utilize or change its utilization of its owned or controlled assets, including contractual assets, or market positions to minimize Department's liability. For purposes of this definition, Seller shall be considered to have resold such Energy to the extent Seller shall have entered into one or more arrangements in a commercially reasonable manner whereby Seller repurchases its obligation to purchase and receive the Energy from another party at the Delivery Point.
"Seller" means SER or, if applicable, a Project Company to which SER has made an assignment of this Agreement with respect to a Project pursuant to Section 9.02(a).
"SER's Tariff" means SER's market-based rate wholesale power sales tariff, which tariff is on file with FERC.
"7 x 24 Price" means the price of Energy (in dollars per MW-hour) associated with base load Capacity, as set forth in Appendix C or as calculated in accordance with Section 2.02.
"6 x 16 Price" means the price of Energy (in dollars per MW-hour) associated with peaking Capacity, as set forth in Appendix C or as calculated in accordance with Section 2.02.
"So Cal Gas" means Southern California Gas Company.
"Southern California Border Point" means deliveries to one or more of the following Natural Gas delivery points as directed solely by Seller: (i) the interconnection between EPNG and So Cal Gas at Topock in San Bernardino County, California; (ii) the interconnection between EPNG and Pacific Gas and Electric Company at Topock in San Bernardino County, California; (iii) the interconnection between EPNG and So Cal Gas at Ehrenburg in Riverside County, California; (iv) the interconnection between EPNG and Southwest Gas at Topock in Mohave County, Arizona; (v) the proposed interconnection between EPNG and the North Baja Pipeline in La Paz County, Arizona; (vi) the interconnection between Kern River and Southwest Gas at Blue Diamond in Clark County, Nevada; (vii) the proposed interconnection between EPNG and SER for the Mesquite Project in Maricopa County, Arizona; (viii) the Kern River and Mojave Pipeline Company pipeline at the "17Z Delivery Point" in Kern County, California; (ix)& nbsp;the proposed interconnection between Kern River and SER for the El Dorado Project and the Copper Mountain Project near Goodsprings in Clark County, Nevada; and/or (x) such other locations to which the Parties may mutually agree, which agreement shall not be unreasonably withheld.
"Southern California Border Gas Price" means, for any Billing Period, the price (in dollars per MMBtu) set forth in the edition of Natural Gas Intelligence, Weekly Price Index (Intelligence Press, Inc.) published for the relevant calendar month, in the table styled "SPOT GAS PRICES", for the item entitled "Southern Cal. Border Avg.", under the column captioned "Bidweek Avg."
"Southwest Gas" means Southwest Gas Corporation.
"State" means the State of California.
"Summer 2001" means the time period commencing at 12:00 a.m. (Pacific Time) on June 1, 2001 and ending at 11:59 p.m. (Pacific Time) on September 30, 2001.
"Summer 2001 Market Price" means for the Summer 2001 the sum of: (i) fifty percent (50%) of the mid-market futures price (in dollars per MW-hour) at close of business on the date this Agreement is executed for an on-peak 6 x 16 electric power product into Cal ISO Zone SP15 as published in Nat Source; and (ii) fifty percent (50%) of the arithmetic average of all the daily on-peak 6 x 16 prices (in dollars per MW-hour) for electric power sold into Cal ISO Zone SP15 published under the headings "South Path 15" in Platts Energy Trader and "SP15" in Megawatt Daily.
"Summer 2001 Short Receivable" means the positive difference between the Summer 2001 Market Price and one hundred and eighty-nine dollars ($189) multiplied by the number of MW-hours of Energy purchased by Department from Seller under this Agreement during the Summer 2001.
"Term" has the meaning set forth in Section 2.08 hereof.
"Terminated Transaction" has the meaning set forth in Section 6.03(a) hereof.
"Termination Payment" has the meaning set forth in Section 6.03 hereof.
"Transaction" has the meaning set forth in Section 9.02(a) hereof.
"Transmission Provider" means any entity or entities transmitting or transporting Energy on behalf of Seller or Buyer to or from the Delivery Point.
"Trust Estate" means all revenues under any obligation entered into, and rights to receive the same, and monies on deposit in the Fund and income or revenue derived from the investment thereof.
"Uncontrollable Force" has the meaning set forth in Section 5.01 hereof.
"WSCC" means the Western Systems Coordinating Council.
Section 1.02. Rules of Interpretation. Unless otherwise provided herein: (a) words denoting the singular include the plural and vice versa; (b) words denoting a gender include both genders; (c) references to a particular part, clause, section, paragraph, article, party, exhibit, schedule or other attachment shall be a reference to a part, clause, section, paragraph, or article of, or a party, exhibit, schedule or other attachment to the document in which the reference is contained; (d) a reference to any statute, regulation, proclamation, ordinance or law includes all statutes, regulations, proclamations, amendments, ordinances or laws varying, consolidating or replacing the same from time to time, and a reference to a statute includes all regulations, policies, protocols, codes, proclamations and ordinances issued or otherwise applicable under that statute unless, in any such case, otherwise expressly provided in any such statute or in the document in which the reference is contained; (e) a ref erence to a particular section, paragraph or other part of a particular statute shall be deemed to be a reference to any other section, paragraph or other part substituted therefor from time to time; (f) a definition of or reference to any document, instrument or agreement includes an amendment or supplement to, or restatement, replacement, modification or novation of, any such document, instrument or agreement unless otherwise specified in such definition or in the context in which such reference is used; (g) a reference to any person includes such person's successors and permitted assigns in that designated capacity; (h) any reference to "days" shall mean calendar days unless Business Days are expressly specified; (i) any reference to "dollars" or "$" shall mean United States dollars unless otherwise specified; (j) any reference to time is a reference to the time then prevailing, whether standard or daylight savings time, in the specified time zone; (k) if the date as of which any right, option or election is exercisable, or the date upon which any amount is due and payable, is stated to be on a date or day that is not a Business Day, such right, option or election may be exercised, and such amount shall be deemed due and payable, on the next succeeding Business Day with the same effect as if the same was exercised or made on such date or day (without, in the case of any such payment, the payment or accrual of any interest or other late payment or charge, provided such payment is made on such next succeeding Business Day); (l) words such as "hereunder," "hereto," "hereof" and "herein" and other words of similar import shall, unless the context requires otherwise, refer to the whole of the applicable document and not to any particular article, section, subsection, paragraph or clause thereof; and (m) a reference to "including" means including without limiting the generality of any description preceding such term, and for purpo ses hereof the rule of ejusdem generis shall not be applicable to limit a general statement, followed by or referable to an enumeration of specific matters, to matters similar to those specifically mentioned.
ARTICLE II
PURCHASE AND SALE OF ENERGY
Section 2.01. Purchase and Sale of Energy. Seller shall sell and deliver, or cause to be sold and delivered, and Department shall purchase and receive, or cause to be purchased and received, the Energy at the Delivery Point, and Department shall pay Seller the Purchase Price. Seller may provide the Energy from any Project, Market Source or combination of Projects and/or Market Sources and may deliver Energy at any Delivery Point or combination of Delivery Points. Seller shall be responsible for any costs or charges imposed on or associated with the Energy up to the Delivery Point. Department shall be responsible for any costs or charges imposed on or associated with the Energy or its receipt at and from the Delivery Point.
Section 2.02. Determination of the Purchase Price.
(a) Purchase Price for Summer 2001. For Summer 2001, the Purchase Price shall be equal to the Summer 2001 Market Price, as adjusted pursuant to Section 10.07; provided, however, that Department shall be required to pay only one hundred and eighty-nine dollars ($189) per MW-hour, as adjusted pursuant to Section 10.07, for Energy during Summer 2001 unless Department fails to complete the Bond Offering by September 30, 2001 and Seller exercises its right to terminate this Agreement under Section 6.05(i).
(b) Purchase Price for October 1, 2001 through May 31, 2003. The Purchase Price shall be, for the portion of the Term commencing at 12:00 a.m. (Pacific Time) on October 1, 2001 and ending at 11:59 p.m. (Pacific Time) on May 31, 2003, the price of Energy set forth in Appendix C, as adjusted pursuant to Section 10.07.
(c) Purchase Price for June 1, 2003 through September 30, 2011. For the portion of the Term commencing at 12:00 a.m. (Pacific Time) on June 1, 2003, Seller shall calculate the Purchase Price using the Gas Price determined in accordance with Section 2.03 and the formulas set forth below for the 7 x 24 Price and the 6 x 16 Price and making adjustments pursuant to Section 10.07:
7 x 24 Price = (Gas Price x 7.5 MMBtu per MW-hour) + $26 per MW-hour
6 x 16 Price = (Gas Price x 10.0 MMBtu per MW-hour) + $31 per MW-hour
Section 2.03. Natural Gas Supply Arrangements.
(a) At least ninety (90) days prior to the commencement of each Fuel Supply Year, SER shall provide to Department a proposed fuel supply plan (the "Fuel Supply Plan") for such Fuel Supply Year. The Fuel Supply Plan will provide information as to how SER intends to procure Natural Gas and associated Natural Gas transportation, distribution, storage and/or other delivery services such that Department can evaluate the Fuel Supply Plan in order to ascertain the expected cost of Natural Gas needed to generate Energy sold under this Agreement. The Parties may meet at mutually agreeable times prior to and during the Fuel Supply Year to discuss any modifications to the Fuel Supply Plan that Department reasonably requests. SER shall act in accordance with the Fuel Supply Plan. Nothing in this Section 2.03 shall be construed as obligating SER to adopt a Fuel Supply Plan or to agree to any modifications to a Fuel Supply Plan that: (i) SER reasonably believes could interfere with its abi lity to provide the Energy from any combination of the Projects and/or Market Sources; or (ii) SER believes, in its sole discretion, could potentially expose SER to risks, including credit, market or delivery risks, or liabilities that SER considers unacceptable.
(b) After review of the Fuel Supply Plan and no later than thirty (30) days prior to the commencement of the upcoming Fuel Supply Year, Department may elect, at its sole option, to provide up to eighty percent (80%) of the Contractual Gas Requirement for the upcoming Fuel Supply Year from Department's own Natural Gas purchases and will notify SER of the specific quantity of Natural Gas that Department intends to provide pursuant to an election pursuant to this Section 2.03(b). Department shall deliver such Natural Gas, in amounts and at times coincident with Seller's obligation to deliver Energy to Department hereunder, for SER's account to the Southern California Border Point. Any election under this Section 2.03(b) will be for a full Fuel Supply Year or as otherwise mutually agreed.
(c) The Gas Price is intended to reflect the cost of Natural Gas procured by SER to generate Energy under this Agreement, and Natural Gas provided by Department pursuant to an election under Section 2.05(b) shall be deemed to be provided to SER at no cost. The Gas Price shall be calculated in accordance with the following formula:
|
Gas Price = [(S x PS) + (B x PB)] |
|
CGR |
WHERE:
S = Amounts of Natural Gas (in MMBtu) purchased by SER pursuant to the Fuel Supply Plan described Section 2.03(a).
PS = The weighted average price of S (in dollars per MMBtu) for the Billing Period.
B = The portion of the Contractual Gas Requirement (in MMBtu) not purchased pursuant to Sections 2.03(a) by SER or provided by Department pursuant to Section 2.03(b), plus amounts of Natural Gas purchased by SER to replace amounts of Natural Gas that Department fails to deliver and less amounts of Natural Gas delivered by Department equivalent to scheduled Energy deliveries curtailed by SER to Department pursuant to Section 2.04(b)(iii), calculated in accordance with the following formula:
B = CGR - D - S
WHERE:
D = Amounts of Natural Gas (in MMBtu) provided to SER by Department pursuant to an election under Section 2.03(b).
PB = The Southern California Border Gas Price (in dollars per MMBtu) for the Billing Period.
CGR = The Contractual Gas Requirement (in MMBtu), calculated in accordance with the following formula:
|
CGR = (OPE x 10.0 MMBtu per MW-hour) + |
|
(BLE x 7.5 MMBtu per MW-hour) |
WHERE:
OPE = MW-hours of 6 x 16 on-peak Energy provided during the Billing Period determined by multiplying the 6 x 16 Capacity applicable during such Billing Period, as indicated in Appendix C, by the number of days, excluding Sundays and NERC Holidays, in the Billing Period by sixteen (16).
BLE = MW-hours of 7 x 24 base load Energy provided during the Billing Period determined by multiplying the 7 x 24 Capacity applicable during such Billing Period, as indicated in Appendix C, by the number of days in such Billing Period by twenty-four (24).
- SER shall be responsible for all fuel imbalances.
Section 2.04. Transmission Scheduling.
(a) Transmission Scheduling Generally. Seller shall only be responsible for and shall arrange transmission service to the Delivery Point. Seller shall schedule or arrange for scheduling services with its Transmission Providers in accordance with the practice of the Transmission Providers to deliver the Energy to the Delivery Point. Department shall be responsible for and shall arrange transmission service at and from the Delivery Point and shall schedule with its Transmission Providers to receive the Energy at the Delivery Point. All deliveries shall be prescheduled, and each Party shall be responsible for ensuring that transmission is scheduled consistent with the most recent rules adopted by the WSCC. SER and Department shall be equally responsible for all Cal ISO imbalance charges associated with this Agreement.
(b) Transmission Curtailment or Interruption Responsibilities. Risks of transmission curtailment or interruption shall be the responsibility of Seller up to the Delivery Point and at and from the Delivery Point to the extent provided for under Section 2.04(c), but shall otherwise be the responsibility of Department at and from the Delivery Point; provided, however, that Seller shall not bear risks of transmission curtailment or interruption that result from: (i) Department's failure to take the steps contemplated by Section 2.04(c)(i) and Section 2.04(c)(iii) to prevent or to alleviate transmission curtailments or interruptions, or (ii) unduly discriminatory actions taken by Department.
(c) Response to Transmission Curtailment or Interruption. SER shall make commercially reasonable efforts to provide or to cause to be provided for the delivery of Energy at Delivery Points that prevent and/or alleviate existing or potential transmission curtailments or interruptions. SER and Department agree to take the following steps in the following order if and to the extent needed to prevent and/or to alleviate existing or potential transmission curtailments or interruptions that could affect the delivery of scheduled Energy under this Agreement to a Delivery Point and/or transmission of such Energy by Department from that Delivery Point to a point elsewhere within the Associated Cal ISO Delivery Zone: (i) Department shall reduce, interrupt or curtail its purchases of Economy Energy; (ii) SER shall, or shall cause Seller to, reduce, interrupt or curtail its sales of Economy Energy; (iii) Department shall redispatch or reschedule its power deliveries associated with dispatchable purcha ses of a duration of twelve (12) months or less to the maximum extent permitted by its power sales contracts; and (iv) SER shall, or shall cause Seller to, make commercially reasonable efforts to deliver the affected portion of the Energy to any other Cal ISO Delivery Point. In the event and to the extent the foregoing measures are insufficient to prevent transmission curtailments or interruptions affecting the delivery of the Energy to a Delivery Point and/or transmission of such Energy by Department from that Delivery Point to a point elsewhere within the Associated Cal ISO Delivery Zone, Seller's obligation to deliver the affected portion of the scheduled Energy to the Delivery Point, and Department's obligation to make payment for that portion of the scheduled Energy, shall be reduced accordingly.
Section 2.05. Energy Scheduling.
(a) Annual Energy Delivery Plan. Within ten (10) Business Days of the execution of this Agreement for Summer 2001 and no less than ninety (90) days before the end of each calendar year of the Term thereafter, SER shall deliver to Department (by facsimile or other reasonable means), a description of planned deliveries of Energy over the upcoming year (the "Annual Energy Delivery Plan") indicating the intended Delivery Points and the amounts of Energy to be provided at such Delivery Points for each month, on-peak and off-peak, considering, but not limited to:
- outage schedules for the Projects;
- any known changes in Project availability;
- known or anticipated transmission constraints requiring modification of operations compared to the prior year's operations;
- status of contracts between any Seller and others for firm sales from the Projects which could impact ability or schedule for deliveries from the respective Projects; and
- Natural Gas transportation or other factors which influence preferred sources of generation and associated points of delivery.
Department shall provide its comments on the Annual Energy Delivery Plan within thirty (30) days of receipt for the purposes of any recommendations for revisions in delivery plans and to accommodate preferred fuel supply plans. SER shall make commercially reasonable efforts to accommodate the requested revisions.
(b) Monthly Energy Delivery Plan. No less than five (5) days prior to the commencement of each month, SER shall deliver to Department (by facsimile or other reasonable means), a description of planned deliveries of Energy in the upcoming month (the "Monthly Energy Delivery Plan") indicating the amounts and Delivery Points for such Delivery Points of Energy. All Energy to be provided from the Projects, Market Sources and/or any combination of the Projects and Market Sources shall be scheduled in accordance with Section 2.05(c). Any material deviations from the most recent Annual Energy Delivery Plan shall be noted and reasons for the changes explained. Within two (2) business days of receipt of the Monthly Energy Delivery Plan, Department shall note any exceptions or requested modifications to the Monthly Energy Delivery Plan. SER shall make commercially reasonable efforts to accommodate revisions requested by Department.
(c) Energy Scheduling Generally. Seller may deliver all or part of the Energy to any Delivery Point regardless of whether such Energy is generated at a Project associated with such Delivery Point or obtained from Market Sources and without regard to the Maximum Capacity at the Delivery Point specified for any Project. Except as provided in Section 2.04(c), Seller shall, in accordance with standard operating practices and the Annual Energy Delivery Plan and Monthly Energy Delivery Plan promulgated in accordance with this Section 2.05, deliver to Department (by facsimile or other reasonable means) on each Business Day a notice indicating the Delivery Points and the amounts of Energy to be provided at such Delivery Points for each hour of the time period commencing on the next day and extending through and including the next Business Day.
Section 2.06. Alternative Delivery Points. In addition to the Delivery Points identified in Appendix B, the Parties may agree to other points at which Energy may be delivered under this Agreement ("Alternative Delivery Points"). For any dispatch hour during the Term, either Party may designate, subject to the other Party's prior approval and consistent with requirements of the Transmission Provider, an Alternative Delivery Point. Unless otherwise agreed by the Parties, the Party designating such an Alternative Delivery Point shall be solely responsible for all costs, including transmission costs, and risks, including risks of non-delivery, associated with the use of an Alternative Delivery Point.
Section 2.07. Sources of Payment; No Debt of State. Department's obligation to make payments hereunder shall be limited solely to the Trust Estate. Any liability of Department arising in connection with this Agreement or any claim based thereon or with respect thereto, including, but not limited to, any Termination Payment arising as the result of any breach or default or Event of Default under this Agreement, and any other payment obligation or liability of or judgment against Department hereunder, shall be satisfied solely from the Trust Estate. NEITHER THE FULL FAITH AND CREDIT NOR THE TAXING POWER OF THE STATE ARE OR MAY BE PLEDGED FOR ANY PAYMENT UNDER THIS AGREEMENT. Revenues and assets of the State Water Resources Development System shall not be liable for or available to make any payments or satisfy any obligation arising under this Agreement.
Section 2.08. Term. Unless earlier terminated pursuant to Article VI hereof, the term of this Agreement (the "Term") shall commence at 12:00 a.m. (Pacific Time) on the date of execution of this Agreement and end at 11:59 p.m. (Pacific Time) on September 30, 2011.
Section 2.09. FERC Authorization a Condition Precedent. FERC acceptance of the Enabling Agreement for filing under Section 205 of the Federal Power Act ("FPA"), without modifications or conditions that SER or Department, each using its reasonably exercised discretion, considers unacceptable, shall be a condition precedent to Seller's obligations under this Agreement.
Section 2.10. Commercial Operation of Projects.
(a) As to each Project, Seller's obligations hereunder are subject to commencement of Commercial Operation of the Project. The Parties agree, in the event and to the extent that a Project does not commence Commercial Operation, Seller may reduce its Energy obligations to Department in accordance with Section 2.10(b). Seller will make commercially reasonable efforts to achieve Commercial Operation of each Project on or before the Commercial Operation Target Date for such Project in Appendix B, but nothing in this Section 2.10 or any other provision of this Agreement shall be construed as obligating Seller to commence or to continue efforts to achieve Commercial Operation of any Project.
(b) If a Project does not commence Commercial Operation on or before the Commercial Operation Target Date as contemplated by Section 2.10(a), then Seller may reduce proportionately its Energy obligations to Department by an amount ("Reduced Amount") calculated in accordance with the following formula:
Reduced Amount = Cap x (X/Y)
WHERE:
Cap = Capacity as listed in Appendix C for all affected Periods.
X = Maximum Capacity at the Delivery Point for the affected Project as identified in Appendix B (Column (F)) for the time periods including and subsequent to the affected Project's Commercial Operation Target Date listed in Appendix B (Column (C)).
Y = The sum of the Maximum Capacity at the Delivery Point for all Projects as identified in Appendix B (Column (F)) for the time periods including and subsequent to the affected Project's Commercial Operation Target Date listed in Appendix B (Column (C)).
Notwithstanding the foregoing, Seller at its sole discretion, may provide the Reduced Amount, in whole or in part, relying on supplies available from other Projects and/or Market Sources.
(c) Seller shall notify Department on at least a quarterly basis of the progress towards achieving Commercial Operation of all uncompleted Projects. No less than six (6) months prior to a Project's Commercial Operation Target Date, Seller will provide Department, in writing, a good faith estimate of the date on which the Project will achieve Commercial Operation and shall indicate any necessary change in the Commercial Operation Target Date to reflect delays in achieving Commercial Operation. No less than three (3) months prior to the Commercial Operation Target Date, as adjusted pursuant to the preceding sentence, Seller will provide Department, in writing, a further good faith estimate of the date on which the Project will achieve Commercial Operation, and, if the Project is not expected to achieve Commercial Operation on or before the Commercial Operation Target Date, Seller will inform Department that it will: (i) provide all or part of the Reduced Amount on the adjusted Commercial Operation Targe t Date by relying on supplies available from other Projects and/or Market Sources; (ii) provide all or part of the Reduced Amount on an adjusted Commercial Operation Target Date; and/or (iii) reduce its obligations to Department by all or part of the Reduced Amount for the remainder of the Term.
(d) Seller will operate and maintain each Project in accordance with Prudent Electric Practice and will notify Department of any maintenance that would affect Seller's performance of its obligation to provide Energy under this Agreement.
Section 2.11 As Available Resources. The Parties acknowledge that Seller can provide Energy to Department from As Available Resources only to the extent such As Available Resources are available to Seller. The Parties agree that, in the event and to the extent Seller determines that such As Available Resources are not available to Seller to provide Energy to Department, Seller shall remain obligated to provide Energy to Department in an amount equal to at least ninety percent (90%) of the Maximum Capacity at the Delivery Point for each As Available Resource.
ARTICLE III
REPRESENTATIONS AND WARRANTIES
Section 3.01. Representations and Warranties of Department. As of the date hereof, Department represents and warrants to Seller that:
(a) Pursuant to the Act, Department is authorized and empowered to enter into the transactions contemplated by this Agreement and has taken all requisite action to carry out its obligations hereunder. By proper action of its officers, Department has duly authorized the execution and delivery of this Agreement.
(b) The execution, delivery and performance by Department of this Agreement and the consummation by Department of the transactions herein contemplated have been duly authorized and will not violate any provision of law in any material respect, or any order or judgment of any court or agency of government having jurisdiction thereover, or be in material conflict with or result in a material breach of or constitute (with due notice and/or lapse of time) a material default under any material indenture, material agreement or other material instrument to which Department is a party or by which it or any of its property is subject to or bound.
(c) Assuming due and proper execution hereof by Seller, this Agreement constitutes the legal, valid and binding obligation of Department enforceable against Department in accordance with its terms, except as such enforceability may be limited by bankruptcy, insolvency, reorganization, moratorium or other similar laws affecting creditors' rights generally and subject to general rules of equity (regardless of whether such enforceability is considered in a proceeding at law or in equity).
(d) All persons representing Department are the duly appointed incumbents in their positions in good standing in accordance with applicable law.
(e) Entry into and performance of this Agreement by Department is for a proper public purpose under the Act and all other relevant constitutional, organic or other governing documents and applicable law.
(f) The Term does not extend beyond any applicable limitation imposed by the Act or other relevant constitutional, organic or governing documents and applicable law relevant constitutional, organic or governing documents and applicable law.
(g) Obligations to make payments hereunder do not constitute any kind of indebtedness of Department or create any kind of lien on, or security interest in, any property or revenues of Department which, in either case, is proscribed by any provision of the Act or any other relevant constitutional, organic or governing documents and applicable law, any order or judgment of any court or other agency of government applicable to it or its assets, or any contractual restriction binding on or affecting it or any of its assets.
Section 3.02. Representations and Warranties of SER. As of the date hereof, SER represents and warrants to Department that:
(a) SER is a corporation duly organized, validly existing and in good standing under the laws of the State, is duly qualified to do business in and is in good standing under the laws of the State, has the power and authority to own its property and assets, to carry on its business as now being conducted by it and to execute, deliver and perform this Agreement. To the best of SER's knowledge, SER is duly qualified to do business in every jurisdiction in which such qualification is necessary.
(b) The execution, delivery and performance of this Agreement and the consummation of the transactions by SER herein contemplated have been duly authorized by all material requisite action on the part of SER and will not violate any provision of law, any order or judgment of any court or agency of government, or the certificate of incorporation or by-laws of SER, or any material indenture, agreement or other instrument to which SER is a party or by which it or any of its property is subject to or bound, or be in conflict with or result in a breach of or constitute (with due notice and/or lapse of time) a material default under any such indenture, agreement or other instrument.
(c) This Agreement constitutes the legal, valid and binding obligations of SER enforceable against SER in accordance with its terms subject to applicable bankruptcy, insolvency, fraudulent conveyance, reorganization, moratorium or other laws affecting creditors' rights generally and subject to general principles of equity, regardless of whether considered in a proceeding in equity or at law.
(d) Except for the filing of the Enabling Agreement with FERC as contemplated by Section 2.09 and the other authorizations, consents and approvals of governmental bodies or agencies necessary to achieve Commercial Operation with respect to the Projects other than the El Dorado Project, all material authorizations, consents and approvals of governmental bodies or agencies required to be obtained by SER as of the date hereof in connection with the execution and delivery of this Agreement or in connection with the performance of the obligations of SER hereunder have been obtained, and there is no substantive action or proceeding pending or, to the best knowledge of SER, threatened by or against SER by or before any court or administrative agency that might adversely affect the ability of SER to perform its obligations under this Agreement.
(e) No action has been instituted, with respect to SER, by SER or by another person or entity of a bankruptcy, reorganization, moratorium, liquidation or similar insolvency proceeding or other relief under any bankruptcy or insolvency law affecting creditor's rights or petitions have been presented or instituted for its winding-up or liquidation.
Section 4.01. Billing Period; Billing Address. The accounting and billing period ("Billing Period") for transactions under this Agreement shall be one (1) calendar month. Bills sent to Department shall be sent to the Billing Address.
Section 4.02. Payments. Department shall pay invoiced amounts billed hereunder so that such payments are received by Seller on the later of the twentieth (20th) day of the month following the Billing Period or the tenth (10th) day after Department receives the invoice or, if either such day is not a Business Day, then on the next Business Day. Payment shall be made by electronic funds transfer, or by other mutually agreeable method, to the account designated by Seller.
Section 4.03. Late Payments. Amounts not paid on or before the due date shall be payable with interest accrued at the Interest Rate.
Section 4.04 Disputes. In case any portion of any bill is in dispute, the entire bill shall be paid when due. Any excess amount of bills which, through inadvertent errors or as a result of a dispute, have been overpaid shall be returned by Seller upon determination of the correct amount, with interest accrued at the Interest Rate, prorated by days from the date of overpayment to the date of refund. Neither Department nor Seller shall have rights to dispute the accuracy of any bill or payment after a period of two (2) years from the date on which the first bill was delivered.
Section 4.05. Records Retention and Audit.
(a) Records Retention. Department and Seller, or any third party representative thereof, shall keep complete and accurate records, and shall maintain such records and other data as may be necessary for the purpose of ascertaining the accuracy of all relevant bills, data, estimates, or statements of charges submitted hereunder. Such records shall be maintained for a period of two (2) years after final payment under this Agreement. Within two (2) years from final payment under this Agreement, either Party may request in writing copies of the records of the other Party to the extent reasonably necessary to verify the accuracy of any statement or charge. The Party from which documents or data have been requested shall cooperate in providing the documents and data within a reasonable time period.
(b) Audit. Seller agrees that Department, the Department of General Services, the Bureau of State Audits, or their designated representative shall have the right to review and to copy any records and supporting documentation pertaining to the performance of this Agreement. Seller agrees to maintain such records for possible audit for a minimum of two (2) years after final payment, unless a longer period of records retention is stipulated. Seller agrees to allow the auditor(s) access to such records during normal business hours and to allow interviews of any employees who might reasonably have information related to such records. Further, Seller agrees to include any similar right of the State to audit records and interview staff in any material contract with contractors or suppliers related to performance of this Agreement.
ARTICLE V
UNCONTROLLABLE FORCES
Section 5.01. Definition of Uncontrollable Force. The term "Uncontrollable Force" means any cause beyond the reasonable control of the Party affected, including but not restricted to flood, drought, earthquake, storm, fire, lightning, epidemic, war, riot, civil disturbance or disobedience, labor dispute, labor or material shortage, sabotage, restraint by court order or public authority, and action or nonaction by, or failure to obtain the necessary authorizations or approvals from, any governmental agency or authority which by exercise of due diligence such Party could not reasonably have been expected to avoid and to the extent which by exercise of due diligence it has been unable to overcome. As to Seller, such Uncontrollable Forces shall include: (i) interruption or curtailment of the transportation, distribution, storage or other delivery of Natural Gas by a Natural Gas Service Provider for reliability or other non-economic reasons, provided, however, that Seller has no t failed to make arrangements for such transportation, distribution, storage or other delivery services that are characterized as "firm" or "non-interruptible" under the applicable tariff and/or agreement; (ii) a requirement of the Transmission Provider, Interconnection Service Provider or control area operator not to deliver Energy to the Delivery Point for reliability or other non-economic reasons; or (iii) an outage at a Project caused on short notice by an alarm or a malfunction of generating unit or interconnection equipment. Without limiting the foregoing, the curtailment or interruption of electric transmission (a) for which Seller is responsible under Section 2.04 or (b) as the result of a discriminatory act by an Affiliate of Seller shall not constitute Uncontrollable Forces. Without limiting the foregoing, the price of transmission, Natural Gas (with respect to purchases of Energy prior to June 1, 2003) or Natural Gas transmission, or the cost of variable and fixed operation and maintenance shall not constitute Uncontrollable Forces. No Party shall, however, be relieved of liability for failure of performance to the extent that such failure is due to causes arising out of its own negligence or due to removable or remediable causes which it fails to remove or remedy within a reasonable time period. Nothing contained herein shall be construed to require a Party to settle any strike or labor dispute in which it may be involved. Notwithstanding the foregoing, as to a claim of Uncontrollable Force by either Party, such claim shall not apply to Seller's ability to sell the Energy to persons other than Department at a price greater than the Purchase Price, and as to a claim of Uncontrollable Force by Department, such claim shall not apply to (x) the loss of Department's markets; (y) Department's inability economically to use or resell the Energy purchased hereunder or its ability to purchase comparable Energy from persons other than Seller at a price less than the Pu rchase Price; or (z) any action taken by Department in its governmental capacity.
Section 5.02. Notice of and Response to Uncontrollable Force. A Party rendered unable to fulfill any of its obligations by reason of an Uncontrollable Force shall give prompt notice of such fact and shall exercise due diligence to remove such inability within a reasonable time period. If oral notice is provided, it shall be promptly followed by written notice provided in accordance with Section 10.15.
Section 5.03. Effect of Uncontrollable Force. Neither Party shall be considered to be in breach of this Agreement to the extent that a failure to perform its obligations under this Agreement shall be due to an Uncontrollable Force and the Party claiming an inability to perform due to an Uncontrollable Force gives notice and details of the Uncontrollable Force to the other Party as soon as practicable. Department shall not be relieved by operation of this Article V of any liability to pay for Energy delivered to Department by Seller or to make payments then due or which Department is obligated to make with respect to performance which occurred prior to the Uncontrollable Force. Seller shall not be relieved by operation of this Article V of any liability to make payments then due or which Seller is obligated to make to Department with respect to performance which occurred prior to the Uncontrollable Force.
ARTICLE VI
DEFAULT AND EARLY TERMINATION
Section 6.01. Events of Default. An Event of Default shall mean, with respect to a Party (the "Defaulting Party"), the occurrence of any of the following:
(a) Failure to make any payment required hereunder within thirty (30) days of receiving written notice from the other Party;
(b) A material failure in the performance of any of the Defaulting Party's obligations hereunder (except to the extent constituting a separate Event of Default under Section 6.01(a), and except for such Party's obligations to deliver or receive Energy, the exclusive remedy for which is provided in Article VIII), and the Defaulting Party does not cure such failure within sixty (60) days from the date of receipt of notice from the other Party demanding such cure.
Section 6.02. No Cross-Defaults. The occurrence of an Event of Default with respect to one Transaction shall not be an Event of Default with respect to any other Transaction. In no event, however, shall SER be relieved of its obligations under this Agreement with respect to a Project or any Energy therefrom as a result of an assignment made pursuant to Section 9.02(a).
Section 6.03. Remedies for Events of Default.
(a) If an Event of Default with respect to a Defaulting Party shall have occurred and be continuing with respect to a Transaction, the other Party (the "Non-Defaulting Party") shall possess the right to terminate such Transaction (a "Terminated Transaction") thirty (30) days after receipt of written notice of such termination provided in accordance with Section 10.15 by the Non-Defaulting Party. The payment associated with termination ("Termination Payment") shall be the aggregate of the Market Value and Costs calculated in accordance with Section 6.04 which shall be paid no later than one hundred eighty (180) days after receipt of written notice of such termination. Subject to the provisions of Section 6.03(b) and except as provided in Section 6.05, the Termination Payment shall be the sole and exclusive remedy for the Non-Defaulting Party for a termination of a Terminated Transaction hereunder. Prior to receipt of su ch notice of termination by the Defaulting Party, the Non-Defaulting Party may exercise any remedies available to it at law or otherwise, including the right to seek injunctive relief to prevent irreparable injury to the Non-Defaulting Party.
(b) Upon termination, the Non-Defaulting Party may withhold any payments it owes the Defaulting Party for any obligations incurred prior to termination of a Terminated Transaction until the Defaulting Party pays the Termination Payment to the Non-Defaulting Party.
Section 6.04. Termination Payment Calculations. The Non-Defaulting Party shall calculate the Termination Payment in accordance with the following formula:
Termination Payment = Market Value + Costs
WHERE:
(a) "Market Value" shall be (i) in the case Department is the Non-Defaulting Party, the present value of the positive difference, if any, of (A) payments under a Replacement Contract based on the Per Unit Market Price, and (B) payments under a Terminated Transaction; or (ii) in the case Seller is the Non-Defaulting Party, the present value of the positive difference, if any, of (A) payments under a Terminated Transaction, and (B) payments under a Replacement Contract based on the Per Unit Market Price, in each case using the Present Value Rate as of the time of termination (to take account of the period between the time notice of termination was effective and when such amount would have otherwise been due pursuant to the relevant transaction). The "Present Value Rate" shall mean the sum of 0.50% plus the yield reported on page "USD" of the Bloomberg Financial Markets Services Screen (or, if not available, any other nationally recognized trading screen re porting on-line intra-day trading in United States government securities) at 11:00 a.m. (Eastern Time) for United States government securities having a maturity that matches the average remaining term of a Terminated Transaction. It is expressly agreed that the Non-Defaulting Party shall not be required to enter into a Replacement Contract in order to determine the Termination Payment.
(y) To ascertain the Per Unit Market Price of a Replacement Contract with a term of less than one year, the Non-Defaulting Party may consider, among other valuations, quotations from leading dealers in energy contracts, any or all of the settlement prices of the New York Mercantile Exchange power futures contracts, any or all of the settlement prices on other established power exchanges and other bona fide third party offers; provided, however, that if there is no actively traded market for such Replacement Contract, the Non-Defaulting Party shall use the methodology set forth in paragraph (z).
(z) To ascertain the Per Unit Market Price of a Replacement Contract with a term of one year or more, the Non-Defaulting Party shall use the Market Quotation Average Price; provided, however, that if there is an actively traded market for such Replacement Contract, the Non-Defaulting Party shall use the methodology set forth in paragraph (y).
(b) "Costs" means brokerage fees, commissions and other similar transaction costs and expenses incurred in terminating any related arrangements pursuant to which the Non-Defaulting Party has hedged its obligations or entering into new arrangements which replace a Terminated Transaction, and transmission and ancillary service costs caused by the termination of a Terminated Transaction incurred in connection with the Non-Defaulting Party enforcing its rights with regard to the termination of a Terminated Transaction. Costs shall include: (i) costs incurred by the Non-Defaulting Party to acquire quantities of Natural Gas and associated firm transportation of Natural Gas as necessary to supply Energy from a Project to Department for the Term of a Terminated Transaction and any costs incurred by the Non-Defaulting Party in terminating arrangements such Non-Defaulting Party may have made for such acquisitions, including reasonably incurred contract buyout and/or buydown costs; and (ii ) costs incurred by the Non-Defaulting Party to acquire the amounts of firm electric transmission service necessary to supply Energy to Department for the Term of the Terminated Transaction and any costs incurred by Non-Defaulting Party in terminating arrangements such Non-Defaulting Party may have made for such acquisitions, including reasonably incurred contract buyout and/or buydown costs. The Non-Defaulting Party shall use reasonable efforts to mitigate or eliminate Costs, including efforts to reassign electric transmission or Natural Gas transportation rights and/or to re-sell Natural Gas.
In no event, however, shall a Party's Market Value or Costs include any penalties or similar charges imposed by the Non-Defaulting Party. If the Defaulting Party disagrees with the calculation of the Termination Payment and the Parties cannot otherwise resolve their differences, the calculation issue shall be subject to dispute resolution as provided in Article VII of this Agreement. Pending resolution of the dispute, the Defaulting Party shall pay the full amount of the Termination Payment calculated by the Non-Defaulting Party no later than one hundred eighty (180) days after receipt of written notice of an early termination.
Section 6.05. Termination Without Recourse. In addition to any other termination rights herein, Seller shall have the right, but not the obligation, to terminate this Agreement without recourse against Department for any Termination Payment or other costs and without any further obligation or liability of either Seller or Department, except as provided in this Section 6.05, upon twenty (20) days notice if Department (i) fails to complete the Bond Offering by September 30, 2001; (ii) fails, after September 30, 2001, for thirty (30) or more consecutive days to maintain an Investment Grade rating on its bonds; or (iii) if, after the date of this Agreement, the United States or any agency thereof, including FERC, imposes a tax or other imposition materially reducing the benefits of this Agreement to Seller and such tax or imposition is not of general applicability and is instead directed at the generation, sale, purchase, ownership and/or transmission of electric power, Natural Gas and/or othe r utility or energy goods and services; provided, however, that Department shall: (a) pay to Seller within five (5) Business Days any payments it owes Seller for any Energy provided prior to termination under Section 6.05(i), Section 6.05(ii) or Section 6.05(iii); and (b) pay to Seller the Summer 2001 Short Receivable within one hundred and eighty (180) days after receipt of written notice of a termination under Section 6.05(i).
Section 6.06. Suspension of Performance. The Non-Defaulting Party may suspend performance hereunder so long as an Event of Default has occurred and is continuing.
ARTICLE VII
DISPUTE RESOLUTION
Section 7.01. Mutual Discussion. All disputes shall, to the extent possible, be settled in the first instance by discussions between designated senior officers of each of the Parties. If a dispute cannot be settled by discussions between designated representatives of the Parties within thirty (30) days from the commencement of such discussions (which commencement shall be deemed to occur upon notice from one Party to the other of the dispute), the dispute resolution procedure set forth in Section 7.02 of this Agreement shall be used to settle the matter.
Section 7.02 Arbitration. If a dispute cannot be resolved through mutual discussion pursuant to Section 7.01, then either Party may refer the dispute to arbitration by a tribunal under the AAA Rules, except to the extent such AAA Rules conflict with the provisions of this Section 7.02, in which event the provisions of this Section 7.02 shall prevail.
(a) Selection of Arbitrators and Arbitral Award. All disputes arising under this Agreement shall be exclusively and finally settled under the AAA Rules by three neutral arbitrators chosen pursuant to the AAA Rules, and the seat of the arbitration shall be in either Los Angeles, California or San Francisco, California. Only a natural person who is or has been an engineer, attorney, financial advisor, judge, manager, executive and/or other professional with experience in the electric power industry shall be appointed as an arbitrator. No arbitrator shall be, or have been, an employee or agent of, or consultant or counsel to, either Party or an Affiliate of a Party.
(b) Enforcement of Award. By execution and delivery of this Agreement, each Party hereby (i) accepts and consents to the jurisdiction of the AAA and, solely for purposes of the enforcement of an arbitral award under this Section 7.02, to the jurisdiction of any court of the State of competent jurisdiction, for itself and in respect of its property, and (ii) subject to (i) above, waives, solely for purposes of the enforcement of an arbitral award under this Section 7.02, in respect of both itself and its property, all defenses it may have as to or based on jurisdiction, improper venue or forum non conveniens. Each Party hereby irrevocably consents to the service of process or other papers by the use of any of the methods and to the addresses set out for the giving of notices in Article 10.15. Nothing herein shall affect the right of each Party to serve such process or papers in any other manner permitted by law.
(c) Performance during Arbitration. During the pendency of an arbitration, each Party shall continue to perform its obligations hereunder (unless such Party is otherwise entitled to suspend its performance hereunder or terminate this Agreement in accordance with the terms hereof).
(d) Final and Binding. Awards made by the arbitral tribunal shall be final and binding on the Parties. To the extent applicable, the Parties expressly agree to waive the applicability of all laws which would otherwise give the right to appeal a decision of the arbitral tribunal so that there shall be no appeal to a court in relation to the award of the arbitral tribunal (except that the Parties shall not challenge or resist the enforcement action taken by a Party in whose favor the award of the arbitral tribunal was given). The cost of an arbitration shall be borne equally by both Parties. The laws of the State shall govern the validity, interpretation, construction, performance and enforcement of the arbitration agreement contained in this Section 7.02.
ARTICLE VIII
REMEDIES FOR FAILURE TO DELIVER/RECEIVE
Section 8.01. Seller Failure. If Seller fails to schedule and/or deliver all or part of the Energy, and such failure is not excused under the terms of this Agreement or by Department's failure to perform, then Seller shall pay Department, within five (5) Business Days of invoice receipt, an amount for such deficiency equal to the positive difference, if any, obtained by subtracting the Purchase Price from the Replacement Price. The invoice for such amount shall include a written statement explaining in reasonable detail the calculation of such amount.
Section 8.02. Department Failure. If Department fails to schedule and/or receive all or part of the Energy and such failure is not excused under the terms of this Agreement or by Seller's failure to perform, then Department shall pay Seller, within five (5) Business Days of invoice receipt, an amount for such deficiency equal to the positive difference, if any, obtained by subtracting the Sales Price from the Purchase Price. The invoice for such amount shall include a written statement explaining in reasonable detail the calculation of such amount.
Section 8.03. Exclusive Remedy for Failure to Deliver/Receive. Notwithstanding Article VI or any other provision of this Agreement, this Article VIII shall provide Department's exclusive remedy in the event Seller fails to schedule and/or deliver all or part of the Energy and Seller's exclusive remedy in the event Department fails to schedule and/or to receive all or part of the Energy. Failure to pay amounts due under this Article VIII shall, however, constitute a separate and distinct Event of Default to which Section 6.01 shall apply.
Section 9.01. Assignments Generally. Except for an assignment made pursuant to Section 9.02, neither Party shall assign this Agreement or its rights hereunder without the prior written consent of the other Party, which consent may be withheld in the exercise of its sole discretion; provided, however, Seller (or, with respect to clause (iii), Department) may, without the consent of the other Party (i) transfer or assign this Agreement to an Affiliate of Seller which Affiliate's creditworthiness is equal to or higher than that of Seller; (ii) transfer or assign this Agreement to any person or entity succeeding to all or substantially all of the assets of Seller whose creditworthiness is equal to or higher than that of Seller; (iii) transfer and assign all of its right, title and interest to this Agreement together with the Fund and the Trust Estate in their entirety to another governmental entity created or designated by law to carry out the rights, powers, duties and obligations of Depa rtment under the Act; provided, however, that (x) no such assignment shall be effective for purposes of this Section 9.01 until the transferring Party shall have provided written notice to the other Party of such assignment, which notice shall include the name and address of the assignee; and (y) any such assignee shall agree in writing to be bound by the terms and conditions hereof; and (z) the transferring Party delivers such tax and enforceability assurance as the other Party may reasonably request. Department shall also have the right to transfer or assign (without relieving itself of liability hereunder) this Agreement to any electrical corporation, as defined in the Act; provided, however, that (A) such assignee is not an Affiliate of Seller; (B) such assignee has credit rating equal to or higher than that of Department and a total capitalization equal to or greater than that of Seller and all of its Affiliates at the time of such assignment; (C) such assignee agrees to provide Seller with such credit assurances as Seller may reasonably require; (D) no such assignment shall be effective until Department shall have provided written notice to Seller of such assignment, which notice shall include the name and address of the assignee; (E) any such assignee shall agree in writing to be bound by the terms and conditions hereof; and (F) Department delivers such tax and enforceability assurance as the Seller may reasonably request.
Section 9.02. Assignments in Connection with Financings. The Parties recognize that Seller intends to provide Energy from the Projects and that such Projects, other than the El Dorado Project, do not yet exist. In order to develop and construct these Projects, Seller will need to obtain financing for the Projects from Project Lenders. The Parties further recognize that Department intends to complete the Bond Offering in order to provide for, among other things, payment of a portion of the cost of power purchase agreements entered into by Department, including this Agreement. Accordingly, the Parties agree to the following assignment provisions in order to facilitate the financings described above.
(a) Assignment to Project Companies with Respect to a Project. SER may assign its rights and obligations to a Project Company with respect to the Project and a portion of the Energy for the remainder of the Term by designating as Project Energy an amount of Energy to be determined by SER. Such assignment with respect to a Project shall be made pursuant to a Project Company Assignment and Assumption Agreement substantially in the form contained in Appendix F; provided, however, that no such assignment shall be effective for purposes of this Section 9.02(a) until SER shall have provided written notice to Department of such assignment, which notice shall include the name and address of such Project Company. The Project Company Assignment and Assumption Agreement and this Agreement shall together constitute a new agreement by and between Department and the Project Company with respect to a Project and the Energy produced therefrom (a "Transaction"). Each Transaction shall be treated as a stand-alone Transaction under this Agreement with the terms and provisions of this Agreement applying separately to each Transaction. An Event of Default with respect to a Transaction shall not independently constitute an Event of Default under any other Transaction. Seller shall bear the burden to obtain FERC authorizations necessary to effect the assignment, but Department agrees not to oppose Seller's filings with FERC in connection with any assignment under this Section 9.02(a). Assignments under this Section 9.02(a) shall not affect: (i) SER's obligations and liabilities under this Agreement, including the obligations and liabilities pertaining to the Project Energy; or (ii) Seller's right under Section 2.01 to provide Energy from any Project, Market Source or combination of Projects and/or Market Sources and to deliver all or part of the Energy at any Delivery Point.
(b) Assignments by Seller as Security to Project Lenders. Seller shall have the right to assign this Agreement as security to any Project Lender, and Department agrees to provide a consent to any such Project Lender in the form of consent provided in Appendix D; provided, however, that no such assignment shall be effective for purposes of this Section 9.02(b) until Seller shall have provided written notice to Department of such assignment, which notice shall include the name and address of such Project Lender. So long as an assignment pursuant to this Section 9.02(b) remains in effect, Department shall, upon serving notice to Seller pursuant to Section 10.15, also serve a copy of such notice upon the specified Project Lender at the address provided by Seller in its notice of assignment to such Project Lender.
(c) Assignment by Department as Security to Bond Trustee. Department shall have the right to assign this Agreement as security to any Bond Trustee, and Seller agrees to provide a consent to any such Bond Trustee in the form of consent provided in Appendix E; provided, however, that no such assignment shall be effective for purposes of this Section 9.02(c) until Department shall have provided written notice to Seller of such assignment, which notice shall include the name and address of such Bond Trustee. So long as an assignment pursuant to this Section 9.02(c) remains in effect, Seller shall, upon serving notice to Department pursuant to Section 10.15, also serve a copy of such notice upon the specified Bond Trustee at the address provided by Department in its notice of assignment to such Bond Trustee.
Section 9.03. Mandatory Assignments by Seller. In the event Seller sells or otherwise transfers its interest in a Project that has commenced Commercial Operation through a transaction subject to Section 9.01 with any person other than a Affiliate, Seller shall be required to assign the rights and obligations under this Agreement associated with the relevant Project and Project Energy to the acquiror of the Project. Such assignment shall be in accordance with and subject to the restrictions set forth in Section 9.01, including any applicable requirement for Department's consent to assignment.
Section 10.01. Title, Risk of Loss. Title to and risk of loss related to the Energy shall transfer from Seller to Department at the Delivery Point. Seller warrants that it will deliver the Energy to Department free and clear of all liens, security interest, claims and encumbrances or any interest therein or thereto by any person arising prior to the Delivery Point.
Section 10.02. Governing Law. This Agreement shall be governed by and construed in accordance with the laws of the State, without regard to the conflicts of laws rules thereof.
Section 10.03. FERC. The Parties acknowledge that: (i) this Agreement provides for wholesale power sales subject to the jurisdiction of the FERC under the FPA; and (ii) the rates, terms and conditions of this Agreement are "just" and "reasonable" within the meaning of the FPA and that changes in market conditions will not render such rates, terms or conditions "unjust" or "unreasonable" for purposes of Section 206 of the FPA.
Section 10.04 Waiver of Trial by Jury. The Parties do hereby expressly waive all rights to trial by jury on any cause of action directly or indirectly involving the terms, covenants or conditions of this Agreement or any matters whatsoever arising out of or in any way connected with this Agreement. The provision of this Agreement relating to waiver of a jury trial shall survive the termination or expiration of this Agreement.
Section 10.05. Amendments. Except as provided in Section 10.03, neither this Agreement nor any provision hereof may be amended, waived, discharged or terminated except by an instrument in writing signed by Department and Seller. In the event that changes in laws, regulations or practices, including changes in procedures governing sales into the State's wholesale power markets, materially alter the procedures applicable to the Parties' performance of their respective obligations hereunder, the Parties will endeavor in good faith to negotiate appropriate and mutually agreeable amendments to this Agreement or separate protocols to reflect such changes.
Section 10.06. Counterparts. This Agreement may be executed in any number of counterparts, and upon execution by the Parties, each executed counterpart shall have the same force and effect as an original instrument and as if the Parties had signed the same instrument. Any signature page of this Agreement may be detached from any counterpart of this Agreement without impairing the legal effect of any signatures thereon, and may be attached to another counterpart of this Agreement identical in form hereto but having attached to it one or more signature pages.
Section 10.07. Taxes. The Purchase Price shall include full reimbursement for, and Seller is liable for and shall pay, or cause to be paid, or reimburse Department for if Department has paid, all taxes applicable to the Energy that arise prior to the Delivery Point; provided, however, that the Purchase Price shall be increased or decreased to account for the effect of any liability, loss, cost, damage and expense, including gross-up, arising out of a tax or other imposition or tax credit or other reduction enacted by the State or any agency thereof after the date of this Agreement that is not of general applicability and is instead directed at the generation, sale, purchase, ownership and/or transmission of electric power, Natural Gas and/or other utility or energy goods and services. If Department is required to remit any tax for which Seller is responsible under this Section 10.07, the amount shall be deducted from any sums due to Seller. The Purchase Price does not include reimburseme nt for, and Department is liable for and shall pay, cause to be paid, or reimburse Seller for if Seller has paid, all taxes applicable to the Energy arising at and from the Delivery Point, including any taxes imposed or collected by a taxing authority with jurisdiction over Department. Either Party, upon written request of the other Party, shall provide a certificate of exemption or other reasonably satisfactory evidence of exemption if either Party is exempt from taxes, and shall use reasonable efforts to obtain and cooperate with the other Party in obtaining any exemption from or reduction of any tax. Taxes are any amounts imposed by a taxing authority with respect to the Energy.
Section 10.08. Severability. In the event that any of the terms, covenants or conditions of this Agreement, or the application of any such term, covenant or condition, shall be held invalid as to any person or circumstance by any court, regulatory agency, or other regulatory body having jurisdiction, all other terms, covenants or conditions of this Agreement and their application shall not be affected thereby, but shall remain in force and effect unless a court, regulatory agency, or other regulatory body holds that the provisions are not separable from all other provisions of this Agreement.
Section 10.09. Relationship of the Parties.
(a) Nothing contained herein shall be construed to create an association, joint venture, trust, or partnership, or impose a trust or partnership covenant, obligation, or liability on or with regard to any one or more of the Parties. Each Party shall be individually responsible for its own covenants, obligations, and liabilities under this Agreement.
(b) All rights of the Parties are several, not joint. No Party shall be under the control of or shall be deemed to control another Party. Except as expressly provided in this Agreement, no Party shall have a right or power to bind another Party without its express written consent.
Section 10.10. No Dedication of Facilities. Seller's undertaking hereunder shall not constitute the dedication of the electric system or any portion thereof of Seller to the public or to the other Party and it is understood and agreed that any undertaking under this Agreement by Seller shall cease upon the termination of Seller's obligations under this Agreement.
Section 10.11. No Retail Services; No Agency.
(a) Nothing contained in this Agreement shall grant any rights to or obligate Seller to provide any services hereunder directly to or for retail customers of any person.
(b) In performing their respective obligations hereunder, neither Party is acting, or is authorized to act, as agent of the other Party.
Section 10.12. Third Party Beneficiaries. Except for the provisions of this Agreement which set forth certain rights and obligations of Project Lenders, this Agreement shall not be construed to create rights in, or to grant remedies to, any third party as a beneficiary of this Agreement or of any duty, obligation or undertaking established herein.
Section 10.13. Liability and Damages. No Party's directors, members of its governing bodies, officers or employees shall be liable to any other person for any loss or damage to property, loss of earnings or revenues, personal injury, or any other direct, indirect, or consequential damages or injury, or punitive damages, which may occur or result from the performance or non-performance of this Agreement, including any negligence arising hereunder.
Section 10.14. Waivers. Any waiver at any time by any Party of its rights with respect to a default under this Agreement, or any other matter under this Agreement, shall not be deemed a waiver with respect to any subsequent default of the same or any other matter.
Section 10.15. Notices. Any formal notice, demand or request provided for in this Agreement shall be in writing and shall be deemed properly served, given or made if delivered in person, or sent by either registered or certified mail, postage prepaid, or prepaid telegram or fax or other means agreed to by the Parties to the addresses set forth in Appendix A.
Section 10.16. Waiver of Consequential Damages. In no event, whether based on contract, indemnity, warranty, tort (including, as the case may be, a Party's own negligence) or otherwise, shall either Party be liable to the other Party or to any other person or Party for or with respect to any claims for consequential, indirect, punitive, exemplary, special or incidental damages or otherwise; provided, however, that this provision shall not limit in any way a Party's right to payment of the Termination Payment pursuant to Section 6.03 hereof or payments pursuant to Section 6.05 or Article VIII hereof.
Section 10.17. Governing Terms. This Agreement, SER's Tariff and the Enabling Agreement shall form a single integrated agreement between the Parties. Any inconsistency between any terms of SER's Tariff and the Enabling Agreement, on the one hand, and any terms of the Agreement, on the other hand, shall be resolved in favor of this Agreement.
Section 10.18. Further Assurances. Each Party agrees to execute and deliver such other instruments and documents and to take such other actions as may be reasonably necessary to complete performance hereunder and otherwise to further the purposes and intent of this Agreement.
Section 10.19. No Immunity Claim. The law of the State authorizes suits based on contract against the State or its agencies, and Department agrees that it will not assert any immunity it may have as a State agency against such lawsuits filed in State court.
Section 10.20. No More Favorable Terms. Department shall not provide in any power purchase agreement payable from the Trust Estate for (i) collateral or other security or credit support with respect thereto, (ii) a pledge or assignment of the Trust Estate for the payment thereof, or (iii) payment priority with respect thereto superior to that of Seller, without in each case offering such arrangements to Seller.
Section 10.21. Payments Under Agreement an Operating Expense. Payments by Department under this Agreement shall constitute an operating expense of the Fund payable prior to all bonds, notes or other indebtedness secured by a pledge or assignment of the Trust Estate or payments to the general fund. The foregoing provision shall be reflected in any indenture or resolution providing for the issuance of bonds by Department.
Section 10.22. Rate Covenant; No Impairment. In accordance with Section 80134 of the Water Code, Department covenants that it will, at least annually, and more frequently as required, establish and revise revenue requirements sufficient, together with any moneys on deposit in the Fund, to provide for the timely payment of all obligations which it has incurred pursuant to the Act, including any payments required to be made by Department pursuant to this Agreement. As provided in Section 80200 of the Water Code, while any obligations of Department pursuant to this Agreement remain outstanding and not fully performed or discharged, the rights, powers, duties and existence of Department and the CPUC shall not be diminished or impaired in any manner that will affect adversely the interests and rights of Seller under this Agreement.
Section 10.23. Application of Government Code and Public Contracts Code. Seller has stated that, because of the administrative burden and delays associated with such requirements, it would not enter into this Agreement if the provisions of the Government Code and the Public Contracts Code applicable to state contracts, including, but not limited to, advertising and competitive bidding requirements and prompt payment requirements would apply to or be required to be incorporated in this Agreement. Accordingly, pursuant to Section 80014(b) of the Water Code, Department has determined that it would be detrimental to accomplishing the purposes of Division 27 (commencing with Section 80000) of the Water Code to make such provisions applicable to this Agreement and that such provisions and requirements are therefore not applicable to or incorporated in this Agreement.
IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by their duly authorized representative as of the 4th day of May, 2001.
|
DEPARTMENT OF WATER RESOURCES with respect to the Department of Water Resources Electric Power Fund separate and apart from its powers and responsibilities with respect to the State Water Resources Development System |
|
By:________________________________ |
|
Name: Raymond D. Hart |
|
Title: Deputy Director |
|
SEMPRA ENERGY RESOURCES |
|
By:________________________________ |
|
Name: Michael R. Niggli |
|
Title: President |
|
By:________________________________ |
|
Name: Dwain M. Boettcher |
|
Title: Vice President |
Appendix A
Addresses
|
SER |
Department |
|
|
Billing Address: |
Sempra Energy Resources |
Department of Water Resources |
|
Notice Address: |
Sempra Energy Resources |
Department of Water Resources |
|
Authorized Representative: |
William R. Engelbrecht Director, Portfolio Asset Management |
Raymond D. Hart |
Appendix B
Description of the Projects and Delivery Points
|
|
|
Commercial Operation Target Date |
|
|
Maximum Capacity |
|
(A) |
(B) |
(C) |
(D) |
(E) |
(F) |
|
Market Sources |
-- |
-- |
Cal ISO Delivery Points |
SP15, NP15 or ZP26 |
300 |
|
El Dorado |
Boulder City, Nevada |
in service |
Merchant 230-kV |
SP15 |
250 |
|
Elk Hills (SC) |
Bakersfield, California |
4/1/02 |
Midway 230-kV |
ZP26 |
300 |
|
Elk Hills (CC)2 |
Bakersfield California |
6/1/03 |
Midway 230-kV |
ZP26 |
600 |
|
Mesquite I |
Arlington, Arizona |
6/1/03 |
Hassayampa 500-kV |
SP15 |
625 |
|
Mexicali |
Mexicali, Baja California, Mexico |
6/1/03 |
Imperial Valley 230-kV |
SP15 |
650 |
|
Mesquite II |
Arlington, Arizona |
1/1/04 |
Hassayampa 500-kV |
SP15 |
625 |
|
Copper Mountain |
Boulder City, Nevada |
6/1/04 |
Merchant 230-kV1 |
SP15 |
650 |
|
Citracado |
Escondido, California |
6/1/04 |
Escondido 230-kV |
SP15 |
600 |
Appendix C
Energy and Purchase Price by Time Period
|
|
7 x 24 |
|
6 x 16 Capacity (MW) |
|
||
6/1/01-9/30/01 |
-- |
-- |
250 |
1 |
||
10/1/01-3/31/02 |
-- |
-- |
-- |
-- |
||
4/1/02-9/30/02 |
150 |
$100 |
300 |
$160 |
||
10/1/02-5/31/03 |
220 |
$69 |
-- |
-- |
||
6/1/03-12/31/03 |
1,000 |
2 |
350 |
3 |
||
1/1/04-2/29/04 |
1,200 |
2 |
700 |
3 |
||
3/1/04-5/31/04 |
800 |
2 |
400 |
3 |
||
6/1/04-2/28/05 |
1,200 |
2 |
700 |
3 |
||
3/1/05-5/31/05 |
800 |
2 |
400 |
3 |
||
6/1/05-2/28/06 |
1,200 |
2 |
700 |
3 |
||
3/1/06-5/31/06 |
800 |
2 |
400 |
3 |
||
6/1/06-2/28/07 |
1,200 |
2 |
700 |
3 |
||
3/1/07-5/31/07 |
800 |
2 |
400 |
3 |
||
6/1/07-12/31/07 |
1,200 |
2 |
700 |
3 |
||
1/1/08-9/30/11 |
1,200 |
2 |
400 |
3 |
1
6 x 16 Price for this period is determined in accordance with Section 2.02(a).2 7 x 24 Price for this period is determined in accordance with Section 2.02(c).
3 6 x 16 Price for this period is determined in accordance with Section 2.02(c).
Appendix D
FORM OF DEPARTMENT'S
CONSENT AND AGREEMENT
This CONSENT AND AGREEMENT (this "Consent and Agreement"), dated as of _______________, 20__, is executed by the Department of Water Resources, an agency of the State of California, with respect to the Department of Water Resources Electric Power Fund separate and apart from its powers and responsibilities with respect to the State Water Resources Development System ("Department"), and [Sempra Energy Resources ("SER")] [PROJECT SUBSIDIARY], a _______________ [corporation] [limited partnership] [general partnership] ("Borrower") for the benefit of [AGENT], a _______________ corporation ("Agent"), as Agent for the Lenders under the Loan Agreement (as defined below).
A. Borrower has entered into that certain [Construction Loan][,] [and] [Term Loan] [and Reimbursement] Agreement, dated as of ______________, 20__, among Borrower, Agent and the Lenders named therein (the "Loan Agreement")].
B. Department and [SER] [Sempra Energy Resources ("SER")] entered into that certain Energy Purchase Agreement, dated as of May 4, 2001 [and SER has made an assignment of its rights under the Agreement with respect to a Project to Borrower pursuant to the Project Company Assignment and Assumption Agreement dated as of ______________, 20__, by and between SER and Borrower (the "Assignment Agreement")] ([together,] the "Agreement").
C. Pursuant to the Security Agreement, dated as of __________, 20__ (the "Security Agreement"), between Borrower and Agent, Borrower has assigned its interest under the Agreement to the Lenders.
NOW THEREFORE, Department hereby agrees as follows:
1. Department acknowledges the assignment referred to in paragraph C above and consents to such assignment and agrees with Agent for the benefit of the Lenders as follows:
(a) Unless otherwise defined, all terms used herein which are defined in the Security Agreement or, if not defined therein, in the Loan Agreement, shall have their respective meanings as used therein.
(b) Agent shall be entitled to exercise all rights and to cure any defaults of Borrower under the Agreement. Upon receipt of notice from Agent, Department agrees to accept such exercise and cure by Agent and to render all performance due by it under the Agreement and this Consent and Agreement to the Lenders. Department agrees to make all payments (if any) to be made by it under the Agreement directly to Agent for the benefit of the Lenders upon receipt of Agent's written instructions.
(c) Department will not, (i) without the prior written consent of Agent, cancel or terminate the Agreement except as provided in the Agreement and in accordance with Section 1(d) hereof, or consent to or accept any cancellation or termination thereof by Borrower, or (ii) without the prior written consent of Agent (such consent not to be unreasonably withheld), amend or modify the Agreement in any material respect. Department agrees promptly to deliver duplicates or copies of all notices of default sent under or pursuant to the Agreement to Agent.
(d) Department will not terminate the Agreement on account of any default or breach of Borrower thereunder without written notice to Agent and first providing to Agent (i) thirty (30) days from the date notice of default or breach is delivered to Agent to cure such default if such default is the failure to pay amounts to Department which are due and payable under the Agreement or (ii) a reasonable opportunity, but not fewer than thirty (30) days, to cure such breach or default if the breach or default cannot be cured by the payment of money to Department so long as Agent or its designee shall have commenced to cure the breach or default within such thirty (30) day period and thereafter diligently pursues such cure to completion and continues to perform any monetary obligations under the Agreement and all other obligations under the Agreement are performed by Borrower or Agent. If possession of the Project is necessary to cure such breach or default, and Agent or its designee(s) or assignee(s) declare Borrower in default and commence foreclosure proceedings, Agent or its designee(s) or assignee(s) will be allowed a reasonable period to complete such proceedings. If Agent or its designee(s) or assignee(s) are prohibited by any court order or bankruptcy or insolvency proceedings from curing the default or from commencing or prosecuting foreclosure proceedings, the foregoing time periods shall be extended by the period of such prohibition. Department consents to the transfer of Borrower's interest under the Agreement to the Lenders or any of them or a purchaser or grantee at a foreclosure sale by judicial or non-judicial foreclosure and sale or by a conveyance by Borrower in lieu of foreclosure and agrees that upon such foreclosure, sale or conveyance, Department shall recognize the Lenders or any of them or other purchaser or grantee as the applicable party under the Agreement (provided that such Lenders or purchaser or grantee assumes the obligations of Borrower under the Agreement).
(e) In the event that the Agreement is rejected by a trustee or debtor-in-possession in any bankruptcy or insolvency proceeding, or if the Agreement is terminated for any reason other than a default which could have been but was not cured by Agent as provided in paragraph 1(d) above, and if, within forty-five (45) days after such rejection or termination, the Lenders or their successors or assigns shall so request, Department will execute and deliver to the Lenders a new Agreement, which Agreement shall be on the terms and conditions as the original Agreement for the remaining term of the Agreement before giving effect to such termination.
(f) In the event the Lenders or their designee(s) or assignee(s) elect to perform Borrower's obligations under the Agreement or to enter into a new Agreement as provided in subparagraph (d) or (e) respectively above, the Lenders, their designee(s) and assignee(s), shall not have personal liability to Department for the performance of such obligations, and the sole recourse of Department in seeking the enforcement of such obligations shall be to such parties' interest in the Project.
(g) In the event the Lenders or their designee(s) or assignee(s) succeed to Borrower's interest under the Agreement, the Lenders or their designee(s) or assignee(s) shall cure any defaults for failure to pay amounts owed under the Agreement, but shall not otherwise be required to perform or be subject to any defenses or offsets by reason of any of Borrower's other obligations under the Agreement that were unperformed at such time. The Lenders shall have the right to assign all or a pro rata interest in the Agreement or a new Agreement entered into pursuant to subparagraph (e) to a person or entity to whom the Project is transferred, provided such transferee assumes the obligations of Borrower (or the Lenders) under the Agreement. Upon such assignment, Agent and, if applicable, the Lenders (including their agents and employees) shall be released from any further liability thereunder to the extent of the interest assigned.
2. Department hereby represents and warrants that:
(a) The execution, delivery and performance by Department of the Agreement and this Consent and Agreement have been duly authorized by all necessary corporate action, and do not and will not require any further consents or approvals which have not been obtained, or violate any provision of any law, regulation, order, judgment, injunction or similar matters or breach any agreement presently in effect with respect to or binding on Department;
(b) This Consent and Agreement and the Agreement are legal, valid and binding obligations of Department enforceable against Department in accordance with their respective terms except as enforceability thereof may be limited by bankruptcy, insolvency, reorganization, moratorium, or other laws affecting the enforcement of creditors' rights generally or by general principles of equity, including the possible unavailability of specific performance or injunctive relief, regardless of whether such enforceability is considered in proceeding in equity or at law, or by principles of public policy;
(c) All government approvals necessary for the execution, delivery and performance by Department of its obligations under the Agreement have been obtained and are in full force and effect;
(d) As of the date hereof, the Agreement is in full force and effect and has not been amended, supplemented or modified; and
(e) To the best of Department's knowledge Borrower has fulfilled all of its obligations under the Agreement, and there are no breaches or unsatisfied conditions presently existing (or which would exist after the passage of time and/or giving of notice) that would allow Department to terminate the Agreement.
3. All Notices required or permitted hereunder shall be in writing and shall be effective (a) upon receipt if hand delivered, (b) upon telephonic verification of receipt if sent by facsimile and (c) if otherwise delivered, upon the earlier of receipt or two (2) Banking Days after being sent registered or certified mail, return receipt requested, with proper postage affixed thereto, or by private courier or delivery service with charges prepaid, and addressed as specified below:
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If to Department: |
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If to Agent: |
4. This Consent and Agreement shall be binding upon and benefit the successors and assigns of Department, Borrower, the Lenders and their respective successors, transferees and assigns (including without limitation, any entity that refinances all or any portion of the Obligations under the Loan Agreement). Department agrees to confirm such continuing obligation in writing upon the reasonable request of Borrower or the Lenders or any of their respective successors, transferees or assigns. No termination, amendment, variation or waiver of any provisions of this Consent and Agreement shall be effective unless in writing and signed by Department, Borrower and Agent. This Consent and Agreement shall be governed by the laws of the State of California.
5. This Consent and Agreement may be executed in one or more duplicate counterparts, and when executed and delivered by all the parties listed below, shall constitute a single binding agreement.
IN WITNESS WHEREOF, Department by its officer thereunto duly authorized, has duly executed this Consent and Agreement as of the date set forth below.
Dated as of: ______________, 20__
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DEPARTMENT OF WATER RESOURCES with respect to the Department of Water Resources Electric Power Fund separate and apart from its powers and responsibilities with respect to the State Water Resources Development System |
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By: |
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Accepted and agreed to: |
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[AGENT], a _________________ corporation, as Agent |
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By: |
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[SEMPRA ENERGY RESOURCES |
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By: |
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[[PROJECT SUBSIDIARY], a _____ [general] [limited] partnership |
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By: [PARTNER], a __________ corporation, |
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By: |
Appendix E
FORM OF SELLER'S
'
CONSENT AND AGREEMENT
This CONSENT AND AGREEMENT (this "Consent and Agreement"), dated as of _______________, 20__, is executed by the Department of Water Resources, an agency of the State of California, with respect to the Department of Water Resources Electric Power Fund separate and apart from its powers and responsibilities with respect to the State Water Resources Development System ("Department"), and [Sempra Energy Resources ("SER")] [PROJECT SUBSIDIARY], a _______________ [corporation] [limited partnership] [general partnership] ("Power Seller") for the benefit of [BANK] as bond trustee under the Bond Document (as defined below) (the "Bond Trustee")].
A. Department has [adopted a bond resolution][entered into an indenture] dated ______, 20__ (the "Bond Document").
B. Department and [SER] [Sempra Energy Resources ("SER")] entered into that certain Energy Purchase Agreement, dated as of May 4, 2001 [and SER has made an assignment of its rights under the Agreement with respect to a Project to Power Seller pursuant to the Project Company Assignment and Assumption Agreement dated as of ______________, 20__, by and between SER and Power Seller (the "Assignment Agreement")] ([together,] the "Agreement").
C. Pursuant to the Bond Document, Department has assigned its interest under the Agreement to the Bond Trustee for the benefit of bondholders.
NOW THEREFORE, Power Seller hereby agrees as follows:
1. Power Seller acknowledges the assignment referred to in paragraph C above and consents to such assignment and agrees with Bond Trustee for the benefit of bondholders as follows:
(a) Unless otherwise defined, all terms used herein which are defined in the Bond Document shall have their respective meanings as used therein.
(b) Bond Trustee shall be entitled to exercise all rights and to cure any defaults of Department under the Agreement. Upon receipt of notice from Bond Trustee, Power Seller agrees to accept such exercise and cure by Bond Trustee and to render all performance due by it under the Agreement and this Consent and Agreement to the Bond Trustee. Power Seller agrees to make all payments (if any) to be made by it under the Agreement directly to Bond Trustee for the benefit of bondholders upon receipt of Bond Trustee's written instructions.
(c) Power Seller will not, (i) without the prior written consent of Bond Trustee, cancel or terminate the Agreement except as provided in the Agreement and in accordance with Section 1(d) hereof, or consent to or accept any cancellation or termination thereof by Department, or (ii) without the prior written consent of Bond Trustee (such consent not to be unreasonably withheld), amend or modify the Agreement in any material respect. Power Seller agrees promptly to deliver duplicates or copies of all notices of default sent under or pursuant to the Agreement to Bond Trustee.
(d) Power Seller will not terminate the Agreement on account of any default or breach of Department thereunder without written notice to Bond Trustee and first providing to Bond Trustee (i) thirty (30) days from the date notice of default or breach is delivered to Bond Trustee to cure such default if such default is the failure to pay amounts to Power Seller which are due and payable under the Agreement or (ii) a reasonable opportunity, but not fewer than thirty (30) days, to cure such breach or default if the breach or default cannot be cured by the payment of money to Power Seller so long as Bond Trustee or its designee shall have commenced to cure the breach or default within such thirty (30) day period and thereafter diligently pursues such cure to completion and continues to perform any monetary obligations under the Agreement and all other obligations under the Agreement are performed by Department or Bond Trustee. Power Seller consents to the transfer of Department's interest under the Agreemen t to the Bond Trustee or a purchaser or grantee at a foreclosure sale by judicial or non-judicial foreclosure and sale or by a conveyance by Department in lieu of foreclosure and agrees that upon such foreclosure, sale or conveyance, Power Seller shall recognize the Bond Trustee or other purchaser or grantee as the applicable party under the Agreement (provided that such Bond Trustee or purchaser or grantee assumes the obligations of Department under the Agreement).
(e) In the event that the Agreement is rejected by a trustee or debtor-in-possession in any bankruptcy or insolvency proceeding, or if the Agreement is terminated for any reason other than a default which could have been but was not cured by Bond Trustee as provided in paragraph 1(d) above, and if, within forty-five (45) days after such rejection or termination, the Bond Trustee or its successors or assigns shall so request, Power Seller will execute and deliver to the Bond Trustee a new Agreement, which Agreement shall be on the terms and conditions as the original Agreement for the remaining term of the Agreement before giving effect to such termination.
(f) In the event the Bond Trustee or its designee(s) or assignee(s) elect to perform Department's obligations under the Agreement or to enter into a new Agreement as provided in subparagraph (d) or (e) respectively above, the Bond Trustee, its designee(s) and assignee(s), shall not have personal liability to Power Seller for the performance of such obligations, and the sole recourse of Power Seller in seeking the enforcement of such obligations shall be to such parties' interest in the Trust Estate.
(g) In the event the Bond Trustee or its designee(s) or assignee(s) succeed to Department's interest under the Agreement, the Bond Trustee or their designee(s) or assignee(s) shall cure any defaults for failure to pay amounts owed under the Agreement, but shall not otherwise be required to perform or be subject to any defenses or offsets by reason of any of Department's other obligations under the Agreement that were unperformed at such time.
2. Power Seller hereby represents and warrants that:
(a) The execution, delivery and performance by Power Seller of the Agreement and this Consent and Agreement have been duly authorized by all necessary corporate action, and do not and will not require any further consents or approvals which have not been obtained, or violate any provision of any law, regulation, order, judgment, injunction or similar matters or breach any agreement presently in effect with respect to or binding on Power Seller;
(b) This Consent and Agreement and the Agreement are legal, valid and binding obligations of Power Seller enforceable against Power Seller in accordance with their respective terms except as enforceability thereof may be limited by bankruptcy, insolvency, reorganization, moratorium, or other laws affecting the enforcement of creditors' rights generally or by general principles of equity, including the possible unavailability of specific performance or injunctive relief, regardless of whether such enforceability is considered in proceeding in equity or at law, or by principles of public policy;
(c) All government approvals necessary for the execution, delivery and performance by Power Seller of its obligations under the Agreement have been obtained and are in full force and effect;
(d) As of the date hereof, the Agreement is in full force and effect and has not been amended, supplemented or modified; and
(e) To the best of Power Seller's knowledge Department has fulfilled all of its obligations under the Agreement, and there are no breaches or unsatisfied conditions presently existing (or which would exist after the passage of time and/or giving of notice) that would allow Power Seller to terminate the Agreement.
3. All Notices required or permitted hereunder shall be in writing and shall be effective (a) upon receipt if hand delivered, (b) upon telephonic verification of receipt if sent by facsimile and (c) if otherwise delivered, upon the earlier of receipt or two (2) Banking Days after being sent registered or certified mail, return receipt requested, with proper postage affixed thereto, or by private courier or delivery service with charges prepaid, and addressed as specified below:
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If to Power Seller: |
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If to Bond Trustee: |
4. This Consent and Agreement shall be binding upon and benefit the successors and assigns of Department, Power Seller and the Bond Trustee and their respective successors, transferees and assigns (including without limitation, any entity that refinances all or any portion of the Obligations under the Bond Document). Power Seller agrees to confirm such continuing obligation in writing upon the reasonable request of Department or the Bond Trustee or any of their respective successors, transferees or assigns. No termination, amendment, variation or waiver of any provisions of this Consent and Agreement shall be effective unless in writing and signed by Department, Power Seller and Bond Trustee. This Consent and Agreement shall be governed by the laws of the State of California.
5. This Consent and Agreement may be executed in one or more duplicate counterparts, and when executed and delivered by all the parties listed below, shall constitute a single binding agreement.
IN WITNESS WHEREOF, Power Seller by its officer thereunto duly authorized, has duly executed this Energy Purchase Agreement Consent and Agreement as of the date set forth below.
Dated as of: ______________, 20__
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[SEMPRA ENERGY RESOURCES, a California Corporation] |
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By: |
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[[PROJECT SUBSIDIARY], a _____ [general] [limited] partnership |
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By: [PARTNER], a __________ corporation, |
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By: |
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Accepted and agreed to: |
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TRUSTEE, a _________________ corporation, as Trustee |
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By: |
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DEPARTMENT OF WATER RESOURCES |
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By: |
Appendix F
FORM OF
PROJECT SUBSIDIARY ASSIGNMENT AND ASSUMPTION AGREEMENT
This PROJECT SUBSIDIARY ASSIGNMENT AND ASSUMPTION AGREEMENT (the "Assignment and Assumption Agreement"), dated as of _______________, 20__, is executed by and between Sempra Energy Resources, a California corporation, ("Assignor"), and [PROJECT SUBSIDIARY NAME], a _______________ [limited] [general] partnership ("Assignee").
A. Assignor is a party to the Energy Purchase Agreement, dated as of April __, 2001, by and between the Department of Water Resources, an agency of the State of California, and Assignor (the "Agreement"), which contemplates the assignment of Assignor's rights and obligations thereunder to certain affiliates of Assignor;
B. Assignee is a single purpose subsidiary of Assignor that [owns] [will own] [leases] [will lease] and [operates] [will operate] the Project known as ________________, a ____ megawatt power plant in ____________ (the "[PROJECT NAME] Project").
NOW, THEREFORE, in consideration of the foregoing premises and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, Assignor and Assignee hereby agree as follows:
1. Capitalized terms which are used in this Assignment and Assumption Agreement but are not defined herein shall have the same meanings ascribed to such terms in the Agreement.
2. Assignor hereby assigns, sells, conveys, transfers, delivers and sets over to Assignee, free and clear of all liens and encumbrances, all right, title and interest with respect to the [PROJECT NAME] Project that the Assignor possesses and has the right to transfer in, to and under the Agreement.
3. Assignee hereby assumes all liabilities and obligations under the Agreement with respect to the [PROJECT NAME] Project and agrees to perform fully and faithfully the same according to its terms. Assignee hereby agrees to indemnify, defend and hold harmless Assignor from and against any and all claims hereafter arising under the Agreement with respect to the [PROJECT NAME] Project and Project Energy to be provided therefrom.
4. Assignee hereby agrees with Assignor to execute and deliver to Assignee such further documents and instruments as may be necessary or reasonably requested by Assignee to further confirm and perfect the assignment and transfer of the Agreement with respect to the Project to Assignee.
5. In the event that any provision of this Assignment and Assumption Agreement is construed to conflict with a provision of the Agreement, the provision in the Agreement shall be deemed to be controlling.
6. This Assignment and Assumption Agreement shall bind and shall inure to the benefit of the respective parties and their assigns, transferees and successors.
7. This Assignment and Assumption Agreement may be executed in one or more counterparts, each of which shall be deemed an original but all of which together will constitute one and the same instrument.
IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by their duly authorized representative as of the __th day of ____, 20__.
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SEMPRA ENERGY RESOURCES |
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By:________________________________ |
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Name: |
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[PROJECT SUBSIDIARY NAME] |
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By: [PARTNER], a __________ corporation, |
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By:________________________________ |
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Name: |
ARTICLE I DEFINITIONS AND INTERPRETATION
*ARTICLE II PURCHASE AND SALE OF ENERGY
*ARTICLE III REPRESENTATIONS AND WARRANTIES
*ARTICLE IV PAYMENTS
*ARTICLE V UNCONTROLLABLE FORCES
*ARTICLE
VI DEFAULT AND EARLY TERMINATION *ARTICLE
VII DISPUTE RESOLUTION *ARTICLE VIII REMEDIES FOR FAILURE TO DELIVER/RECEIVE
*ARTICLE IX ASSIGNMENT
*ARTICLE X MISCELLANEOUS
* AppendicesAppendix A. Addresses
Appendix B. Description of the Projects and Delivery Points
Appendix C. Energy and Purchase Price by Time Period
Appendix D. Form of Department's Consent and Agreement
Appendix E. Form of Seller's Consent and Agreement
Appendix F. Form of Project Company Assignment and Assumption Agreement
ENABLING AGREEMENT
This Agreement is entered into this 4th day of May, 2001, by and between the Department of Water Resources, an agency of the State of California, with respect to the Department of Water Resources Electric Power Fund separate and apart from its powers and responsibilities with respect to the State Water Resources Development System ("Department") and Sempra Energy Resources ("Seller"). In consideration of mutual covenants and agreements herein, Department and Seller (collectively the "Parties" and each individually a "Party") hereby agree as follows:
Article 1: Service
1.1 Seller agrees, during the time of this Agreement, to sell electric energy to Department, and Department agrees to pay for such sales at prices agrees upon by the Parties in accordance with Seller's FERC Electric Rate Schedule No. 1 (the "Rate Schedule") on file with the Federal Energy Regulatory Commission ("FERC").
1.2 The product, rates, terms and conditions for such service shall be in accordance with the Rate Schedule as provided in the Energy Purchase Agreement by and between Department and Seller dated May 4, 2001 (the "Purchase Agreement").
Article 2: Effective Date and Term of Agreement
2.1 This Agreement shall become effective on the date first specified above. However, if FERC or any reviewing court imposes any condition, limitation or qualification under any of the provisions of the Federal Power Act which, individually or in the aggregate, either of the Parties determines to be adverse to such Party, such Party may, at its option, terminate or renegotiate the terms of this Agreement in light of such FERC or court action.
2.2 This Agreement shall remain effective until terminated by either Party on thirty (30) days' written notice; provided, however, that neither Party may terminate this Agreement prior to the termination of the Energy Purchase Agreement.
IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by their respective authorized officials as of the date first above written.
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SEMPRA ENERGY RESOURCES, a California corporation |
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_____________________________ |
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_____________________________ |
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DEPARTMENT OF WATER RESOURCES, an agency of the State of California, with respect to the Department of Water Resources Electric Power Fund separate and apart from its powers and responsibilities with respect to the State Water Resources Development System |
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_____________________________ |
Restated Letter Agreement
This Restated Letter Agreement supercedes the Amended Letter Agreement, dated April 5, 2001 and the February 5, 2001 Letter Agreement, between San Diego Gas & Electric Company ("SDG&E") and the California Department of Water Resources ("DWR") (jointly referred to as "Parties" or individually as "Party"), for purchasing the full net-short Power requirements, defined herein, by DWR for end-use retail Customers within SDG&E's service area ("Customers") as set forth in Chapter 4 of Statutes of 2001 (Assembly Bill 1 of the First 2001-02 Extraordinary Session) of the State of California (the "Act"), as amended.
Whereas, this Restated Letter Agreement will provide for a procurement and payment process applicable for DWR purchases of Power, as defined in the Act, for Customers and also takes into account the California Public Utilities Commission ("CPUC") Decision 01-03-081, which was issued by the CPUC on March 27, 2001, and the provisions of the Act and the provisions of Chapter 6 of Statutes of 2001 (Assembly Bill 43 of the First 2001-02 Extraordinary Session).
Therefore, effective February 7, 2001 the Parties agree as follows:
- This Restated Letter Agreement shall terminate as of January 1, 2003, or such later date as may be directed through legislation or by mutual agreement of the Parties.
- Through the later of December 31, 2002, or such later date as may be directed through legislation or by mutual agreement of the Parties, DWR shall purchase and pay for SDG&E Customers' full net-short Power requirements ("Customers' Full Net-Short Power Requirements") as hereinafter defined. DWR has developed or shall promptly develop with the California ISO ("ISO") protocols satisfactory to DWR that govern when DWR purchases the net-short Power requirements of customers through forward markets and the ISO's imbalance energy market to meet the net-short Power requirements of all electric corporations and public agencies requesting DWR Power for retail end use customers' requirements (the "State's Net-Short Power Requirements") pursuant to the Act, as amended, and other applicable law. If appropriate, DWR shall further cooperate with the ISO to develop dispatch protocols by which the ISO effects load curtailments in the event there are inadequate supplies of Power purcha sed by DWR to meet the State's Net-Short Power Requirements. If there is a shortage of Power supplies to meet the State's Net-Short Power Requirements, DWR shall allocate such DWR Power on a basis determined by DWR in conjunction with the ISO. In the event that the delivery of Power to SDG&E's Customers is curtailed pursuant to a Stage 3 emergency, as ordered by the ISO, the DWR shall not be liable to SDG&E for its role in the procurement of Customers' Full Net-Short Power Requirements.
- Customers' Full Net-Short Power Requirements shall have the following meanings for the time periods specified below:
- From February 7, 2001 through April 5, 2001 Customers' Full Net-Short Power Requirements shall mean only the electric energy purchased and scheduled by DWR for Customers, which is included by DWR in the ISO's final Day-Ahead and Hour-Ahead ISO schedules, and, as applicable, purchased by DWR from the ISO's imbalance energy market. SDG&E shall pay or accept payment from the ISO for all ISO charges and credits it has or will present to SDG&E for transactions occurring during this period. Concurrent with the signing of this Restated Letter Agreement, the DWR shall instruct the ISO to pay to SDG&E those amounts that would otherwise be paid to DWR under ISO Charge Types #401 and 481, that are intended to compensate DWR for the electric energy purchased and scheduled by DWR for Customers. In the event that the ISO pays any portion of these ISO Charge Types to DWR, then after receipt of proceeds from the ISO for ISO Charge Types # 401 and 481 that compensate DWR for the electric energy purchased an d scheduled by DWR for Customers, DWR shall promptly provide to SDG&E a notice stating when such payment was made and the amount of the payment. SDG&E shall thereafter invoice DWR for reimbursement of amounts it has previously paid to ISO for imbalance energy (ISO Charge Types #407 and 487) for this period. Any such invoiced amount shall be due and payable within 3 Business Days after presentation, and shall be considered past due 10 Business Days after presentation. Provided, however, SDG&E recognizes that delays of up to 3 Business Days may occur due to, e.g., processing errors or processing system failures. Such delays shall not constitute a default of DWR's obligations pursuant to this Restated Letter Agreement. DWR shall promptly notify SDG&E when any such delay occurs and the expected date of returning to normal schedules.
- From and after April 6, 2001 the Customers' Full Net-Short Power Requirements will include Power to serve SDG&E Customers' Full Net-Short Power Requirements that DWR (i) purchases and schedules to satisfy such requirements in the Day-Ahead and Hour Ahead ISO markets and (ii) purchases from the ISO's imbalance energy market. Those Power services costs that DWR shall be responsible to pay to the ISO are set forth in Schedule 1, which is incorporated herein by reference. Such costs reflect that SDG&E does not currently provide these services with its retained generation, including qualifying facilities contracts or bilateral contracts, that is to be utilized by SDG&E to serve its retail end use Customers (the "Utility Retained Generation"). For this period and until such time as the ISO is able to directly invoice DWR, SDG&E shall promptly submit to DWR for timely payment to the ISO on behalf of SDG&E the ISO invoice pertaining to those charges set forth in Schedule 1. If D WR does not timely pay such invoiced amounts, then SDG&E may make payment to the ISO on behalf of the DWR, and the DWR shall immediately pay SDG&E for the full amount paid plus interest at the Prime Rate as published by the Wall Street Journal, plus 3%. Concurrent with the signing of this Restated Letter Agreement, the DWR shall instruct the ISO to invoice the DWR directly for all charges identified in Schedule 1. Such instruction shall be consistent with the term contained herein and shall request that the ISO seek any necessary approvals from the FERC to implement this change.
- The Parties agree to negotiate mutually acceptable revisions to Schedule 1 hereto when the ISO modifies or adds additional charges and charge types in order to allocate responsibility between SDG&E and DWR.
- SDG&E shall coordinate with DWR to identify the costs associated with DWR's procurement responsibilities hereunder so that SDG&E and DWR can take these costs into account in their corresponding or related filings with the CPUC.
- SDG&E shall provide to DWR forecasts of Customers' load and Customers' Full Net-Short Power Requirements. In the event that such forecast for any hour falls outside of the applicable limit set forth in Section 2.2.13.2.3.1 of the ISO Tariff, as it may be amended, or applicable order issued by the Federal Energy Regulatory Commission, then SDG&E shall be responsible for and pay any resulting penalty. In the event that actual loads are outside of the limits stated above, as applied to SDG&E's forecast load, and such deviation between load and forecast results from the negligence of SDG&E, SDG&E shall pay DWR the incremental cost as determined by DWR. If a dispute arises out of or relates to this subparagraph iii and if the dispute cannot be settled through negotiation within 20 days of a Party providing the other Party a notice of dispute, the Parties may first agree to try in good faith to settle the dispute by mediation before resorting to binding arbitration. If the Parties elect not to resort to mediation or if the dispute is not resolved within 20 days after first meeting with a mediator, a Party shall submit to the other Party and the American Arbitration Association ("AAA") a demand for binding arbitration to be administered by the AAA pursuant to the AAA's Commercial Arbitration Rules. The demand for arbitration shall set forth in reasonable detail (A) each claim, (B) the relief sought, including the proposed award, if applicable, and (C) a summary of the grounds for such relief and the basis for each claim. The other Party shall similarly submit its statement of claim to the disputing Party and the AAA within 7 days of the initial demand for arbitration. If the other Party wishes to submit a counterclaim in response to the statement of claim, it shall be included in such Party's responsive statement of claim. After submission of a demand for arbitration 1 neutral arbitrator shall be selected pursuant to the AAA commercial arbitration rules. The Parties agree to direct the arbitrator to issue an arbitration award no later than 45 days after the selection of the arbitrator. Each Party agrees that it shall utilize its best efforts to conclude any arbitration process as promptly as possible within this period. Neither Party nor an arbitrator may disclose the existence, content, or results of any arbitration hereunder without the prior written consent of the Parties. All fees and expenses of the arbitration shall be borne by the Parties equally. The Parties agree that a judgment on the award rendered by the arbitrators may be entered in any court having jurisdiction.
- SDG&E shall maintain its status as a scheduling coordinator with the ISO.
- The Parties acknowledge that any ISO Grid Management Charges ("GMC") as well as those charges identified on Schedule 1 that are excluded from "Net Short" for DWR associated with SDG&E Customers' Full Net-Short Power Requirements and the Utility Retained Generation are presently reimbursable in full as a commodity charge through applicable SDG&E rate schedules pertaining to Utility Retained Generation. If the CPUC determines that any portion of the GMC or such other ISO charges should not be recovered through a component of SDG&E's rates and charges, then DWR shall pay the portion determined by the CPUC not to be the responsibility of SDG&E provided such ISO charges pertain to DWR's obligation to purchase Power to meet Customers' Full Net-Short Power requirements.
- DWR will not pay any ISO penalties on behalf of SDG&E for any generator/supplier surcharge imposed on SDG&E to the extent that any such surcharge arises from SDG&E's failure fully to pay such generator/supplier for Power supplied to SDG&E.
- It is the intent of both SDG&E and DWR that the overall costs to SDG&E's retail Customers be minimized, and accordingly SDG&E and DWR agree that SDG&E's operation of Utility Retained Generation and DWR's net-short procurement should be coordinated. SDG&E agrees to continue to provide and schedule all services from its Utility Retained Generation as provided in the past. If permitted by the CPUC, should SDG&E have a surplus of any Utility Retained Generation, DWR has the right of first refusal to purchase that surplus Power at SDG&E's costs of procurement or production.
- Charges for DWR Power delivered to the retail end use Customers of SDG&E shall be billed to and collected from such Customers by SDG&E and remitted to DWR by SDG&E in accordance with applicable CPUC decisions and any servicing agreement hereafter entered into by DWR and SDG&E. Remittance provisions for this Restated Letter Agreement are attached as Schedule 2, which is incorporated herein by reference.
- If DWR enters into an agreement pursuant to which it obtains Power to service the net-short Power requirements of another electrical corporation or local publicly owned electric utility under terms and conditions different than those contained herein, then DWR and SDG&E agree to meet and confer to determine if it is appropriate for amendments to this Restated Letter Agreement to be made.
- This Restated Letter Agreement may be executed by both Parties in several counterparts.
Executed on June 18, 2001 by:
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Name: ____________________________ |
Name: ____________________________ |
|
Title: _____________________________ |
Title: _____________________________ |
|
California Department of Water Resources |
San Diego Gas & Electric Company |
SCHEDULE 1
|
ISO Charges to be included in |
ISO Charges to be excluded from |
||
|
ISO Charge Type |
Description |
ISO Charge Type |
Description |
|
115 |
Regulation Up due ISO |
521 |
GMC - Control Area Services |
|
116 |
Regulation Down due ISO |
522 |
GMC - Inter Zonal Scheduling |
|
111 |
Spinning Reserve due ISO |
523 |
GMC - Market Operations |
|
112 |
Non-spinning Reserve due ISO |
3351 |
GMC adjustment charge/refund |
|
114 |
Replacement Reserve due ISO |
7 |
Demand relief monthly payment |
|
1011 |
AS Rational Buyer Adjustment |
||
|
1030 |
No Pay Provision Market Refund |
||
|
406 |
UFE Settlement |
||
|
407 |
Uninstructed Energy |
||
|
487 |
Allocation of IE Cost above soft cap |
||
|
1010 |
Neutrality Adjustment Charge/Refund |
||
|
1210 |
Existing Contracts Cash Neutrality Charge |
||
|
1065 |
RMR Preemption Distribution - Reg Up |
||
|
1066 |
RMR Preemption Distribution - Reg Down |
||
|
1061 |
RMR Preemption Distribution - Spin |
||
|
1062 |
RMR Preemption Distribution - Non Spin |
||
|
1064 |
RMR Preemption Distribution - Repl Res |
||
|
452 |
RT Intra-Zonal Congestion Mgmt Charge |
||
|
203 |
Day-Ahead Inter-Zonal Congestion Settlem |
||
|
253 |
Hour-Ahead Inter-Zonal Congestion Settle |
||
|
256 |
Hour-Ahead Inter-Zonal Congestion Debit due SC |
||
|
117 |
Demand relief monthly charge |
||
SCHEDULE 2
SDG&E/DWR Restated Letter Agreement
1. Definitions
All terms not defined in this Paragraph 1 shall have the meanings set forth in the Restated Letter Agreement or elsewhere in this Schedule 2.
- Applicable Law - The Act, Applicable Commission Orders and any other applicable statute, rule, regulation, ordinance, order, decision or code of a governmental authority.
- Applicable Tariffs -- SDG&E's tariffs, including all rules, rates, schedules and preliminary statements, governing electric service to Customers in SDG&E's service territory, as filed with and approved by the CPUC and, if applicable, the Federal Energy Regulatory Commission.
- Billing Effective Date -- the date on which SDG&E mails a consolidated utility bill which reflects a separate line item or denotation of DWR Charge.
- Business Day - Regular Monday through Friday weekdays which are customary working days, excluding holidays, as established by Applicable Tariffs.
- DWR Charges -- Charges assessed to Customers for DWR Power and any other amounts authorized to be collected pursuant to Section 80110 and 80134 of the California Water Code in order to meet DWR's revenue requirements under the Act, as calculated pursuant to Applicable Law.
- DWR Revenues -- Those amounts required to be remitted to DWR by SDG&E pursuant to Applicable Law.
- Governmental Authority -- Any nation or government, any state or other political subdivision thereof, any entity exercising executive, legislative, judicial, regulatory or administrative functions of or pertaining to a government, including the CPUC.
- SDG&E Charges -- Charges incurred by Customer for electricity-related services and products provided by SDG&E to the Customer, as approved by the CPUC or the Federal Regulatory Commission or other Governmental Authority (including, but not limited to, any Competition Transition Charges or Fixed Transition Amount Charges owing to SDG&E or its affiliates as those terms are defined under the California Public Utilities Code. SDG&E Charges shall not include DWR Charges or charges related to natural gas related services and products.
- Servicing Agreement -- The agreement to be negotiated between the Parties for the transmission and distribution of DWR Power as well as billing and related services.
2. Processing of ISO Invoices and Statements and of Disputes Pertaining to ISO Charges
a. For the period commencing April 6, 2001 and until such time as DWR and the ISO arrange for direct invoicing and payments between DWR and the ISO, SDG&E shall within 1 Business Day after receipt forward to DWR any ISO preliminary and final invoices and settlement statements for all charges/credits SDG&E has received from the ISO for DWR purchases of Customers' Full Net-Short Power Requirements delivered to SDG&E's Customers pursuant to the Restated Letter Agreement.
b. Until such time as DWR and the ISO arrange for direct invoicing and payments between DWR and the ISO pertaining to DWR's purchases of SDG&E Customer's Full Net-Short Power Requirements for ISO charges described in the Restated Letter Agreement, SDG&E shall submit disputes to the ISO, when appropriate as determined by SDG&E or DWR, of any amount shown on the ISO's preliminary and final settlement statements. After such direct DWR-ISO invoicing and payment arrangements have been made, DWR shall submit such disputes to the ISO. During all periods, DWR and SDG&E shall promptly develop mutually acceptable procedures to cause timely disputes to be made by SDG&E or DWR, as applicable, of any preliminary and final and settlement statements, to process any dispute through the ISO's good faith negotiation process and, if necessary, to litigate either through the ISO alternative dispute resolution process or before the Federal Energy Regulatory Commission. Such procedures shall include a process to develop mutually agreeable work plans for processing disputes and the review and approval of all costs applicable to SDG&E's involvement in the ISO's dispute resolution process or in resulting litigation. If SDG&E submits a dispute to the ISO at the request of DWR or if DWR submits a dispute, DWR shall reimburse SDG&E as an Additional Charge for all reasonable out of pocket costs, including consultants and in-house or retained counsel, incurred by SDG&E that arise from disputes of ISO charges or credits involving costs for DWR purchases of Customers' Full Net-Short Power Requirements.
3. Calculation, Remittance, and True-up of SDG&E's Payments For DWR Power Supplied Prior To The Billing Effective Date
Prior to the Billing Effective Date, payments made by SDG&E to DWR are calculated based upon actual purchased DWR Power by DWR for SDG&E Customers. The SDG&E payment will be based on the product of multiplying $65/MWh, or the effective rate as it may be changed pursuant to Applicable Law, by the number of kilowatt-hours of DWR Power purchased by DWR on behalf of SDG&E's Customers. The kWh used in the SDG&E payment will be derived from DWR's statement of actual DWR Power purchases. The amount of actual DWR Revenues shall be equal to the amount of DWR Charges billed to and paid by SDG&E Customers using the processes stated in SDG&E's CPUC-approved electric rules and in paragraph 3 hereto. The SDG&E payment will be later reconciled to actual DWR Revenues.
a. DWR will submit an invoice to SDG&E that specifies actual DWR Power purchased on behalf of SDG&E's Customers and the dollar amount of the SDG&E payment. DWR may invoice SDG&E daily for DWR Power supplied by DWR to SDG&E's Customers.
b. Upon receipt from DWR of a statement of actual purchases for the day, SDG&E will validate and approve the invoice prior to paying such invoice. If SDG&E has validated and approved the DWR invoice, then SDG&E shall cause its payment to be made. If SDG&E determines an invoice is incorrect, SDG&E will immediately provide DWR a written or electronic notice describing such inaccuracies or material errors contained in its invoice. DWR shall prepare and submit to SDG&E a corrected invoice. Upon SDG&E's receipt of a corrected invoice, SDG&E will promptly cause its payment to be made.
c. SDG&E will remit to DWR SDG&E's payment 1 business day following the receipt either (i) of a DWR invoice that SDG&E has validated and approved or (ii) of a correct invoice. DWR recognizes that delays of up to 3 business days may occur due to, e.g., processing errors or processing system failures. Such delays shall not constitute a default of SDG&E's obligations pursuant to the Restated Letter Agreement or these additional implementing provisions. SDG&E shall promptly notify DWR when any such delay occurs and the expected date of returning to the normal schedule.
d. SDG&E will remit SDG&E's payment to DWR via electronic funds transfer. The Parties' first preference for payment by electronic funds transfer is ACH and the Parties' secondary preference will be wire transfer. SDG&E's process timing will dictate which electronic funds transfer will be used. The choice of electronic funds transfer will be mutually agreed upon. During the initial 60 days of the Restated Letter Agreement, wire transfer will be used as the electronic funds transfer.
e. SDG&E will reconcile actual Customer payments to SDG&E's payments. The reconciliation will true-up SDG&E's payment to actual DWR Revenues and may result in either an excess remittance or remittance shortfall. SDG&E will reconcile DWR previous SDG&E's payments to adjust for distribution loss factors, including unaccounted for energy ("DLFs") and uncollectibles expense factor associated with DWR's purchases of Customers' Full Net-Short Power Requirements billed during the period of February 7, 2001 to the Billing Effective Date. This reconciliation shall also include the difference between the scheduled DWR deliveries and actual DWR deliveries, including imbalance energy. SDG&E's electric energy commodity cost ("EECC") Schedule shall set forth the DLFs and uncollectibles expense factor, which SDG&E will apply to calculate the adjustment for actual customer payments during this period of billing. SDG&E's payment to DWR on the next remittanc e date shall be further increased or decreased, as the case may be, by any excess remittance or remittance shortfall. If SDG&E experiences a higher uncollectible expense factor than specified in its EECC Schedule, SDG&E shall provide to DWR documentation that supports a revised factor based on actual uncollectible experience for the period commencing February 7, 2001. Final reconciliation will occur 180 days after the last SDG&E payment.
f. Daily Remittance Report -- SDG&E will provide the following information with each SDG&E payment:
- DWR invoice reference number shall accompany the DWR remittance payment.
- Any deduction from or adjustment to the SDG&E's payment will be identified and accompanied by supporting documentation.
g. SDG&E will provide reconciliation reports, which include:
- Dates and amounts of payments.
4. Calculation and Remittance of DWR Revenues Post Billing Effective Date Until Such Time as a Servicing Agreement Becomes Effective
a. Remittance and Reporting Upon Billing Effective Date
Upon the implementation of the Billing Effective Date, which separates DWR Charges and SDG&E Charges respectively for DWR's purchases of Customers' Full Net-Short Power Requirements and Utility Retained Generation, SDG&E will utilize the remittance and reporting processes set forth below until such time as a servicing agreement between the Parties becomes effective.
b. Summer 2001 Demand Relief Program
Concerning the "Summer 2001 Demand Relief Program" or any other similar program, which provides reimbursement to SDG&E through the ISO bill, SDG&E's participation in this program will result in program credits being applied either to the ISO bills submitted to SDG&E or paid directly by DWR to SDG&E. To the extent these credits appear on the ISO bill and exceed SDG&E's ISO charges, SDG&E shall invoice DWR and DWR shall pay SDG&E within 5 business days after presentation, and shall be considered past due thereafter, after which interest shall accrue at the prime rate as published by the Wall Street Journal, plus 3%.
c. Daily Remittances
Payments will be collected by SDG&E as an agent for DWR. Payments shall be allocated and applied using SDG&E's payment posting priority process (described below). All partial payments to SDG&E will be prorated based on the payment posting priority. During SDG&E's nightly processing during any Business Day, payments for DWR Charges that the SDG&E collects on behalf of DWR will be identified and credited to DWR's account and will be transmitted on the next Business Day, by an electronic funds transfer credit to DWR for settlement. The Parties first preference for electronic funds transfer will be by Automated Clearing House (ACH) and its secondary preference will be by wire transfer. SDG&E's process timing will dictate which electronic funds transfer will be used. During the first 60 day start-up period, wire transfer will be used exclusively.
d. Proposed Process and Sample Timeline for DWR Automated Daily Remittance
(i) Day (-19) - Customer statements are sent out.
(ii) Business Day 0 - Customer makes payment and payment is allocated per payment posting priority.
(iii) Business Day 0 - SDG&E's billing system identifies payments and applies DWR portion based on pre-established payment posting criteria, representing a constructive account for DWR. The parties acknowledge that payments received from Customers consist of payments to SDG&E and payments to DWR and that until DWR's portion is remitted to DWR, such funds will be held together by SDG&E. Until remitted to DWR, SDG&E shall hold DWR's portion of payments in trust for the benefit of DWR (whether or not held with other monies).
(iv) Business Day 1 - Payment is sent to DWR based on remittance schedule. DWR acknowledges delays of up to 3 Business Days may occur due to errors, system failures and other factors. DWR agrees that such delays shall not constitute a default, however SDG&E shall undertake commercially reasonable efforts to rectify any cause for such delay. SDG&E shall promptly notify DWR when any such delay occurs and the expected date for returning to the normal schedule. In cases where ACH electronic payment is remitted, SDG&E will remit to its bank on Business Day 1. DWR agrees that this payment meets SDG&E's remittance schedule requirements.
(v) Adjustments for misapplied payments, returned checks, payment transfers, and miscellaneous adjustments will be reflected in the daily remittance as those adjustments are made in SDG&E's billing system.
e. Collection of DWR Charges
(i) As permitted by Applicable Law, SDG&E will disconnect Customers' electric service for unpaid DWR Charges. Disconnection for DWR charges will be performed in the same manner as SDG&E disconnects for its own charges and consistent with applicable tariffs.
(ii) Responsibility for collection of any DWR Charges that remain unpaid 145 calendar days after the final statement was issued shall become the sole responsibility of DWR. However, Customer payments received by SDG&E after such reversion to DWR will continue to be applied on a pro-rata basis to DWR Charges for a period of no longer than 3 years after the customer's account was closed and final bill rendered by SDG&E
(iii) SDG&E may use collection agency services to recover outstanding balances on customer's closed accounts. When DWR receives benefit of such services through recovery of payments to customer accounts, Parties agree that DWR's payment remittances will be adjusted to account for the pro-rata share of collection agency fees associated with DWR's portion of recovered charges
5. Survival of Payment Obligations
SDG&E has the right but not the obligation to pursue collection of DWR Charges after 180 calendar days following termination of the Restated Letter Agreement. Provided, however, SDG&E may continue collection services for a period of 3 years after the Customer's account was closed if prior to the termination of the Restated Letter Agreement the Parties reach a mutually satisfactory arrangement either to (i) reimburse SDG&E for its estimated reasonable costs to continue with collection and allocation activities for such period or (ii) estimate the amount of collections reasonably likely can be recovered, which amount (including discounts for cash flow impacts) SDG&E shall promptly remit to DWR in full satisfaction of its collection services.
6. Deposits Securing DWR Charges Until Such Time as a Servicing Agreement Becomes Effective
In accordance with Applicable Tariffs, SDG&E shall collect security deposits from Customers and return those security deposits to Customers. Such security deposits will be applied pro rata to DWR Charges in the event a Customers billing account is closed with SDG&E.
- Records; Audit Rights
- Records.
- Audit Rights.
- Confidentiality.
- Additional Applicable Laws.
- Other Information.
- Customer Confidentiality.
- Confidentiality.
- Proprietary Information.
- Nothing in the Restated Letter Agreement shall affect SDG&E's obligations to observe any Applicable Law prohibiting the disclosure of Confidential Information regarding its Customers.
- The Parties acknowledge that each Party may acquire information and material that is the other Party's confidential, proprietary or trade secret information. As used herein, "Confidential Information" means any and all technical, commercial, financial and customer information disclosed by one Party to the other (or obtained from one Party's inspection of the other Party's records or documents), including any patents, patent applications, copyrights, trade secrets and proprietary information, techniques, sketches, drawings, maps, reports, specifications, designs, records, data, models, inventions, know-how, processes, apparatus, equipment, algorithms, software programs, software source documents, object code, source code, and information related to the current, future and proposed products and services of each of the Parties, and includes, without limitation, the Parties' respective information concerning research, experimental work, development, design details and specifications, engineering, financial information, procurement requirements, purchasing, manufacturing, business forecasts, sales and merchandising, and marketing plans and information. In all cases, Confidential Information includes proprietary or confidential information of any third party disclosing such information to either Party in the course of such third party's business or relationship with such Party. SDG&E's Confidential Information also includes any and all lists of Customers, and any and all information about Customers, both individually and aggregated, including but not limited to Customers' names, street addresses of Customer residences and/or facilities, email addresses, identification numbers, SDG&E account numbers and passwords, payment histories, energy usage, rate schedule history, allocation of energy uses among Customer residences and/or facilities, and usage of DWR Power. All Confidential Information disclosed by the disclosing Party ("Discloser") will be considered Confidential Information b y the receiving Party ("Recipient") if identified as confidential and received from Discloser.
- Each Party agrees to take all steps reasonably necessary to hold in trust and confidence the other Party's Confidential Information. Without limiting the generality of the immediately preceding sentence, each Party agrees (i) to hold the other Party's Confidential Information in strict confidence, not to disclose it to third parties or to use it in any way, commercially or otherwise, other than as permitted under the Restated Letter Agreement; and (ii) to limit the disclosure of the Confidential Information to those of its employees, agents or directly related subcontractors with a need to know who have been advised of the confidential nature thereof and who have acknowledged their express obligation to maintain such confidentiality.
- The foregoing two paragraphs will not apply to any item of Confidential Information if: (i) it has been published or is otherwise readily available to the public other than by a breach of the Restated Letter Agreement; (ii) it has been rightfully received by Recipient from a third party without breach of confidentiality obligations of such third party and outside the context of the provision of services under the Restated Letter Agreement; (iii) it has been independently developed by Recipient personnel having no access to the Confidential Information; or (iv) it was known to Recipient prior to its first receipt from Discloser. In addition, Recipient may disclose Confidential Information if and to the extent required by law or a Governmental Authority, provided that (x) Recipient shall give Discloser a reasonable opportunity to review and object to the disclosure of such Confidential Information, (y) Discloser may seek a protective order or confidential treatment of such Confidentia l Information, and (z) Recipient shall make commercially reasonable efforts to cooperate with Discloser in seeking such protective order or confidential treatment. Discloser shall pay Recipient its reasonable costs of cooperating.
- No License.
SDG&E shall maintain accurate records and accounts relating to DWR Charges in sufficient detail to permit recordation of DWR Charges billed to Customers and DWR Revenues remitted by SDG&E to DWR. SDG&E shall provide to DWR and its Assign(s) access to such records. Access to such records and accounts shall be afforded without charge, upon reasonable request made pursuant to Section 7.b. Access shall be afforded only during business hours and in such a manner so as not to interfere unreasonably with SDG&E's normal operations. SDG&E shall not treat DWR Revenues as income or assets of the SDG&E or any affiliate for any tax, financial reporting or regulatory purposes, and the financial books or records of SDG&E and affiliates shall be maintained in a manner consistent with the absolute ownership of DWR Revenues by DWR and SDG&E's holding of DWR Revenues in trust for DWR (whether or not held together with other monies).
Upon 30 calendar days' prior written notice, DWR may request an audit, conducted by DWR or its agents (at DWR's expense), of SDG&E's records and procedures, which shall be limited to records and procedures containing information bearing upon: (i) DWR Charges being billed to Customers by SDG&E (and Customer payments of DWR Charges); (ii) fees to SDG&E for services provided by SDG&E pursuant to the Restated Letter Agreement; (iii) SDG&E's performance of its obligations under the Restated Letter Agreement; (iv) allocation of DWR Power pursuant hereto or Applicable Law; (v) projection or calculation of DWR's revenue requirements as described in Sections 80110 and 80134 of the California Water Code from time to time; and (vi) such other matters as may be permitted by Applicable Commission Orders, Applicable Tariffs or as DWR or its Assign(s) may reasonably request. The audit shall be conducted during business hours without interference with SDG&E's normal operations, and in compliance with SDG&E's security procedures.
As provided in the Act, the State of California Bureau of State Audits (the "Bureau") shall conduct a financial and performance audit of DWR's implementation of Division 27 (commencing with Section 80000) of the California Water Code, such audit to be completed prior to December 31, 2001, and the Bureau shall issue a final report on or before March 31, 2003. In addition, as provided in Section 8546.7 of the California Government Code, SDG&E agrees that, pursuant to this Section 7.b, DWR or the State of California Department of General Services, the State of California Bureau of State Audits, or their designated representative ("DWR's Agent") shall have the right to review and to copy (at DWR's expense) any non-confidential records and supporting documentation pertaining to the performance of the Restated Letter Agreement and to conduct an on-site review of any Confidential Information (as defined in Section 8) pursuant to Sections 7.c. and 7.f. hereof. SDG&E ag rees to maintain such records for such possible audit for three years after final remittance to DWR. SDG&E agrees to allow such auditor(s) access to such records during business hours and to allow interviews of any employees who might reasonably have information related to such records. Further, SDG&E agrees to include a similar right for DWR or DWR's Agent to audit records and interview staff in any contract between SDG&E and a subcontractor related to performance of the Restated Letter Agreement.
Materials reviewed by either Party or its agents in the course of an audit may contain Confidential Information subject to Section 8 below. The use of all materials provided to DWR or SDG&E or their agents, as the case may be pursuant to this Section 7, shall comply with the provisions in Section 8 and shall be limited to use in conjunction with the conduct of the audit and preparation of a report for appropriate distribution of the results of the audit consistent with Applicable Law.
Each Party shall make an effort to promptly notify the other Party in writing to the extent such Party becomes aware of any new Applicable Laws or changes (or proposed changes) in Applicable Tariffs hereafter enacted, adopted or promulgated that may have a material adverse effect on either Party's ability to perform its duties under the Restated Letter Agreement. A Party's failure to so notify the other Party pursuant to this Section 7.d. will not constitute a material breach of the Restated Letter Agreement, and will not give rise to any right to terminate the Restated Letter Agreement or cause either Party to incur any liability to the other Party or any third party.
Upon the reasonable request of DWR or its Assign(s), SDG&E shall provide to the CPUC and to DWR or its Assign(s) any public financial information in respect of the SDG&E applicable to Services provided by SDG&E under the Restated Letter Agreement, or any material information regarding the sale of DWR Power, to the extent such information is reasonably available to SDG&E, which (i) is reasonably necessary and permitted by Applicable Law to monitor the performance by SDG&E hereunder, or (ii) otherwise relates to the exercise of DWR's rights or the discharge of DWR's duties under the Restated Letter Agreement or any Applicable Law. In particular, but without limiting the foregoing, SDG&E shall provide to DWR, with a copy to the CPUC, any such information that is necessary or useful to calculate DWR's revenue requirements (as described in Sections 80110 and 80134 of the California Water Code) or DWR Charges.
Nothing in this Section 7 shall affect the obligation of SDG&E to observe any Applicable Law prohibiting disclosure of information regarding Customers, and the failure of SDG&E to provide access to such information as a result of such obligation shall not constitute a breach of this Section 7 or the Restated Letter Agreement.
Nothing contained in the Restated Letter Agreement shall be construed as granting to a Party a license, either express or implied, under any patent, copyright, trademark, service mark, trade dress or other intellectual property right, or to any Confidential Information now or hereafter owned, obtained, controlled by, or which is or may be licensable by, the other Party.
c. Survival of Provisions.
The provisions of this Section 8 shall survive the termination of the Restated Letter Agreement.
9. Other Operating Revenue Collected by SDG&E Until Such Time as a Servicing Agreement Becomes Effective
DWR shall have no rights in or entitlements to charges associated with SDG&E's collection or payment activities, including but not limited to, returned check charge, reconnection of service charge, field assignment charge, and other service charges related to billing, payment or collections. However, late payment interest charges will be applied pro-rata to DWR Charges.
10. Payment Posting Priority Until Such Time as a Servicing Agreement Becomes Effective
a. Priority
SDG&E payment posting rules will assign equal priority to SDG&E gas and electric energy and service charges, and DWR Charges. Payments will be prorated among all categories of unpaid disconnectible charges and DWR Charges based on the amount owing in each statement, beginning with the oldest amounts outstanding. SDG&E's payment posting priority enables SDG&E to make timely payments to SDG&E, DWR, and other agencies/Cities where SDG&E is required to collect surcharges, fees and taxes. Any non-disconnectible charges outstanding, will be paid with any remaining credit balance.
b. Payment Posting Rules
(i) Payments will be applied to the oldest statements first.
(ii) Payments will be applied on a pro-rata basis between SDG&E gas and electric energy/service charges in the following illustrative manner:
|
Sample: |
Electric |
Gas |
Total |
|
Bill Date 6/10/01 |
$100.00 |
$100.00 |
$200.00 |
|
% of Total |
50% |
50% |
100% |
|
Payment 6/25/01 |
$50.00 |
$50.00 |
$100.00 |
|
% of Total |
50% |
50% |
100% |
c. Proration
(i) Within the SDG&E Charges shown on each statement, the payment/credit will be prorated among all unpaid charges based on the amount owing in each category in the following illustrative manner:
|
Sample: |
SDG&E |
DWR |
FF/Taxes |
Total |
|
Bill Due 6/10/01 |
$35.00 |
$60.00 |
$5.00 |
$100.00 |
|
% of Total |
35% |
60% |
5% |
100% |
|
Payment 6/25/01 |
$17.50 |
$30.00 |
$2.50 |
$50.00 |
|
% of Total |
35% |
60% |
5% |
100% |
11. Daily and Monthly Cash Receipt Reports, Monthly Remittance Reports, and Daily and Monthly Billing Reports to be Provided by SDG&E to DWR After Billing Effective Date
Until Such Time as a Servicing Agreement Becomes EffectiveSDG&E shall provide to DWR the following reports, which are depicted in illustrative form:
a. Sample Daily Cash Receipts Report:
PGM ID: XXXXXX DWR NET CASH POSITION Run Date: XX/XX/XXXX Time: XX:XX
FOR THE DAY ENDING XX/XX/XXXX
TOTAL DWR CHARGES PAID: $ 55.00
b. Sample Monthly Remittance Report:
|
San Diego Gas and Electric |
||||||
|
Summary of DWR Energy Billings/Payments/Chargeoffs |
||||||
|
Business Month: |
mm/yyyy |
|||||
|
Beginning DWR Balance |
$x,xxx,xxx.xx |
|||||
|
New Billings to Customers |
$x,xxx,xxx.xx |
ADD |
||||
|
Payments by Customers |
$x,xxx,xxx.xx |
SUBTRACT |
||||
|
Bad Debts charged off |
$x,xxx,xxx.xx |
SUBTRACT |
||||
|
other program (I.e. 20/20) adjustments |
$x,xxx,xxx.xx |
|||||
|
Ending DWR Balance |
$x,xxx,xxx.xx |
|||||
c. Daily and Monthly Billing Report:
|
San Diego Gas & Electric |
|||||
|
LINE |
DESCRIPTION |
System |
DWR |
DWR Billed Amount |
|
|
1 |
SCHEDULE DR |
408,114,064 |
|||
|
2 |
SCHEDULE DR-LI |
38,868,773 |
|||
|
3 |
SCHEDULE DM |
5,026,286 |
|||
|
4 |
SCHEDULE DS |
1,504,629 |
|||
|
5 |
SCHEDULE DT |
10,515,864 |
|||
|
6 |
SCHEDULE DT-RV |
33,744 |
|||
|
7 |
SCHEDULE D-SMF |
122,400 |
|||
|
8 |
SCHEDULE DR-TOU |
556,184 |
|||
|
9 |
SCHEDULE DR-TOU-2 |
2,877,813 |
|||
|
10 |
SCHEDULE EV-TOU |
646 |
|||
|
11 |
SCHEDULE EV-TOU-2 |
19,615 |
|||
|
12 |
SCHEDULE EV-TOU-3 |
2,307 |
|||
|
13 |
SCHEDULE A |
138,814,727 |
|||
|
14 |
SCHEDULE A-TC |
5,088,043 |
|||
|
15 |
SCHEDULE A-TOU |
8,907,573 |
|||
|
16 |
SCHEDULE AD |
8,229,616 |
|||
|
17 |
SCHEDULE AL-TOU |
503,329,542 |
|||
|
18 |
SCHEDULE A6-TOU |
51,554,931 |
|||
|
19 |
SCHEDULE AO-TOU |
91,812,295 |
|||
|
20 |
SCHEDULE NJ |
269,052 |
|||
|
21 |
SCHEDULE AY-TOU |
38,339,179 |
|||
|
22 |
SCHEDULE A-V1 |
4,836,881 |
|||
|
23 |
SCHEDULE A-V2 |
1,011,902 |
|||
|
24 |
SCHEDULE A-V3 |
0 |
|||
|
25 |
SCHEDULE RTP-1 |
0 |
|||
|
26 |
SCHEDULE RTP-2 |
3,480,041 |
|||
|
27 |
SCHEDULE S |
0 |
|||
|
28 |
SCHEDULE I-3 |
0 |
|||
|
29 |
SCHEDULE PA |
4,487,637 |
|||
|
30 |
SCHEDULE PA-TOU |
39,153 |
|||
|
31 |
SCHEDULE PA-T-1 |
7,542,121 |
|||
|
32 |
SCHEDULE SPEC |
14,000 |
|||
|
33 |
SCHEDULE LS1 |
2,251,691 |
|||
|
34 |
SCHEDULE LS2 |
6,402,566 |
|||
|
35 |
SCHEDULE LS3 |
214,720 |
|||
|
36 |
SCHEDULE OL1 |
619,634 |
|||
|
37 |
SCHEDULE DWL |
19,000 |
|||
|
38 |
SCHEDULE ATS |
89,790 |
|||
|
39 |
SCHEDULE ART |
(573,761) |
|||
|
40 |
SCHEDULE DG6 |
2,652 |
|||
|
41 |
UNDEFINED RATE |
0 |
|||
|
42 |
Total |
1,344,425,310 |
|||
SEMPRA ENERGY
SEVERANCE PAY AGREEMENT
THIS AGREEMENT (this "Agreement"), dated as of [Effective Date]_________, 1998 (the "Effective Date") is made by and between SEMPRA ENERGY, a California corporation, and
[Name of Executive]_________ (the "Executive").
WHEREAS, the Executive is currently employed by Sempra Energy or a subsidiary of Sempra Energy (Sempra Energy and its subsidiaries are hereinafter collectively referred to as the "Company") as [Position Title of Executive]____________; and
WHEREAS, the Board of Directors of Sempra Energy (the "Board") has determined that it is in the best interests of the Company to institute formalized severance arrangements for certain of the executives of the Company, including the Executive.
NOW, THEREFORE, in consideration of the premises and mutual covenants herein contained, the Company and the Executive hereby agree as follows:
Section 1. Definitions. For purposes of this Agreement, the following capitalized terms have the meanings set forth below:
"Affiliate" has the meaning ascribed to such term in Rule 12b-2 promulgated under the Exchange Act.
"Beneficial Owner" has the meaning set forth in Rule 13d-3 under the Exchange Act.
"Cause" means (a) Prior to a Change in Control, (i) the willful failure by the Executive to substantially perform the Executive's duties with the Company (other than any such failure resulting from the Executive's incapacity due to physical or mental illness), (ii) the grossly negligent performance of such obligations referenced in clause (i) of this definition, (iii) the Executive's gross insubordination; and/or (iv) the Executive's commission of one or more acts of moral turpitude that constitute a violation of applicable law (including but not limited to a felony) which have or result in an adverse effect on the Company, monetarily or otherwise, or one or more significant acts of dishonesty. For purposes of clause (i) of this definition, no act, or failure to act, on the Executive's part shall be deemed "willful" unless done, or omitted to be done, by the Executive not in good faith and without reasonable belief that the Executive's act, or failure to act, was in the best interests of the Company. (b) From and after a Change in Control, (i) the willful and continued failure by the Executive to substantially perform the Executive's duties with the Company (other than any such failure resulting from the Executive's incapacity due to physical or mental illness or any such actual or anticipated failure after the issuance of a Notice of Termination for Good Reason by the Executive pursuant to Section 2 hereof), and/or (ii) the Executive's commission of one or more acts of moral turpitude that constitute a violation of applicable law (including but not limited to a felony) which have or result in an adverse effect on the Company, monetarily or otherwise, or one or more significant acts of dishonesty. For purposes of clause (i) of this definition, no act, or failure to act, on the Executive's part shall be deemed "willful" unless done, or omitted to be done, by the Executive not in good faith and without reasonable belief that the Executive's act, or failure to act, was in the best interests of the Company. Notwithstanding the foregoing, the Executive shall not be deemed terminated for Cause pursuant to clause (i) of this definition unless and until the Executive shall have been provided with reasonable notice of and, if possible, a reasonable opportunity to cure the facts and circumstances claimed to provide a basis for termination of the Executive's employment for Cause.
"Cause" means (i) the willful and continued failure by the Executive to substantially perform the Executive's duties with the Company (other than any such failure resulting from the Executive's incapacity due to physical or mental illness or any such actual or anticipated failure after the issuance of a Notice of Termination for Good Reason by the Executive pursuant to Section 2 hereof), or (ii) the Executive's commission of one or more acts of moral turpitude that constitute a violation of applicable law (including but not limited to a felony) which have or result in an adverse effect on the Company, monetarily or otherwise, or one or more significant acts of dishonesty. For purposes of clause (i) of this definition, no act, or failure to act, on the Executive's part shall be deemed "willful" unless done, or omitted to be done, by the Executive not in good faith and without reasonable belief that the Executive's act, or failure to act, was in the best interests of the Company. Notwithstanding the foregoing, the Executive shall not be deemed terminated for Cause pursuant to clause (i) of this definition unless and until the Executive shall have been provided with reasonable notice of and, if possible, a reasonable opportunity to cure the facts and circumstances claimed to provide a basis for termination of the Executive's employment for Cause.
A "Change in Control" of Sempra Energy shall be deemed to have occurred when:
(a) Any Person is or becomes the Beneficial Owner, directly or indirectly, of securities of Sempra Energy representing twenty percent (20%) or more of the combined voting power of Sempra Energy's then outstanding securities; or
(b) The following individuals cease for any reason to constitute a majority of the number of directors then serving: individuals who, on the Effective Date, constitute the Board and any new director (other than a director whose initial assumption of office is in connection with an actual or threatened election contest, including, but not limited to, a consent solicitation, relating to the election of directors of Sempra Energy) whose appointment or election by the Board or nomination for election by Sempra Energy's shareholders was approved or recommended by a vote of at least two-thirds (2/3) of the directors then still in office who either were directors on the date hereof or whose appointment, election or nomination for election was previously so approved or recommended; or
(c) There is consummated a merger or consolidation of Sempra Energy or any direct or indirect subsidiary of Sempra Energy with any other corporation, other than (A) a merger or consolidation which would result in the voting securities of Sempra Energy outstanding immediately prior to such merger or consolidation continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof), in combination with the ownership of any trustee or other fiduciary holding securities under an employee benefit plan of Sempra Energy or any subsidiary of Sempra Energy, at least sixty percent (60%) of the combined voting power of the securities of Sempra Energy or such surviving entity or any parent thereof outstanding immediately after such merger or consolidation, or (B) a merger or consolidation effected to implement a recapitalization of Sempra Energy (or similar transaction) in which no Person is or becomes the Beneficial Owner, directly or indirectly, of securities of Sempra Energy (not including in the securities beneficially owned by such Person any securities acquired directly from Sempra Energy or its affiliates other than in connection with the acquisition by Sempra Energy or its affiliates of a business) representing twenty percent (20%) or more of the combined voting power of Sempra Energy's then outstanding securities; or
(d) The shareholders of Sempra Energy approve a plan of complete liquidation or dissolution of Sempra Energy or there is consummated an agreement for the sale or disposition by Sempra Energy of all or substantially all of Sempra Energy's assets, other than a sale or disposition by Sempra Energy of all or substantially all of Sempra Energy's assets to an entity, at least sixty percent (60%) of the combined voting power of the voting securities of which are owned by shareholders of Sempra Energy in substantially the same proportions as their ownership of Sempra Energy immediately prior to such sale.
"Change in Control Date" means the date on which a Change in Control occurs.
"Code" means the Internal Revenue Code of 1986, as amended.
"Date of Termination" has the meaning assigned thereto in Section 2 hereof.
"Disability" has the meaning set forth in the SERP (as defined below), as in effect from time to time; provided, however, that in no event shall the Executive be deemed to have incurred a Disability hereunder if there exists a reasonable expectation that the Executive will return to work on a full-time basis within ninety (90) days of the events giving rise to the Disability.
"Exchange Act" means the Securities Exchange Act of 1934, as amended, and the applicable rulings and regulations thereunder.
"Good Reason" means:
(a) Prior to a Change in Control, the occurrence of any of the following without the prior written consent of the Executive, unless such act or failure to act is corrected prior to the Date of Termination specified in the Notice of Termination (as discussed in Section 2 below):
(i) the assignment to the Executive of any duties materially inconsistent with the range of duties and responsibilities appropriate to a senior executive within the Company (such range determined by reference to past, current and reasonable practices within the Company);
(ii) a material reduction in the Executive's overall standing and responsibilities within the Company, but not including (A) a mere change in title, or (B) a transfer within Company, which, in the case of both (A) and (B), does not adversely affect the Executive's overall status within the Company;
(iii) a material reduction by the Company in the Executive's aggregate annualized compensation and benefits opportunities, except for across-the-board reductions (or modifications of benefit plans) similarly affecting all similarly situated executives (both of the Company and of any Person then in control of the Company) of comparable rank with the Executive;
(iv) the failure by the Company to pay to the Executive any portion of the Executive's current compensation and benefits or any portion of an installment of deferred compensation under any deferred compensation program of the Company within thirty (30) days of the date such compensation is due;
(v) any purported termination of the Executive's employment that is not effected pursuant to a Notice of Termination satisfying the requirements of Section 2 hereof; for purposes of this Agreement, no such purported termination shall be effective;
(vi) the failure by the Company to obtain a satisfactory agreement from any successor of the Company requiring such successor to assume and agree to perform the Company's obligations under this Agreement, as contemplated in Section 8(a) hereof; or
(vii) the failure by the Company to comply with any material provision of this Agreement.
(b) From and after a Change in Control, the occurrence of any of the following without the prior written consent of the Executive, unless such act or failure to act is corrected prior to the Date of Termination specified in the Notice of Termination (as discussed in Section 2 below):
(i) an adverse change in the Executive's title, authority, duties, responsibilities or reporting lines as in effect immediately prior to the Change in Control;
(ii) a reduction of ten percent (10%) or more by the Company in the Executive's aggregate annualized compensation and benefits opportunities, except for across-the-board reductions (or modifications of benefit plans) of less than ten percent (10%) similarly affecting all similarly situated executives (both of the Company and of any Person then in control of the Company) of comparable rank with the Executive;
(iii) the relocation of the Executive's principal place of employment immediately prior to the Change in Control Date (the "Principal Location") to a location which is both further away from Executive's residence and more than thirty (30) miles from such Principal Location, or the Company's requiring the Executive to be based anywhere other than such Principal Location (or permitted relocation thereof), or a substantial increase in the Executive's business travel obligations outside of the Southern California area as of the Effective Date other than any such increase that (A) arises in connection with extraordinary business activities of the Company and (B) is understood not to be part of the Executive's regular duties with the Company;
(iv) the failure by the Company to pay to the Executive any portion of the Executive's current compensation and benefits or any portion of an installment of deferred compensation under any deferred compensation program of the Company within thirty (30) days of the date such compensation is due;
(v) any purported termination of the Executive's employment that is not effected pursuant to a Notice of Termination satisfying the requirements of Section 2 hereof; for purposes of this Agreement, no such purported termination shall be effective;
(vi) the failure by the Company to obtain a satisfactory agreement from any successor of the Company requiring such successor to assume and agree to perform the Company's obligations under this Agreement, as contemplated in Section 8(a) hereof; or
(vii) the failure by the Company to comply with any material provision of this Agreement.
From and after a Change in Control, the Executive's determination that an act or failure to act constitutes Good Reason shall be presumed to be valid unless such determination is deemed to be unreasonable by an arbitrator. The Executive's right to terminate the Executive's employment for Good Reason shall not be affected by the Executive's incapacity due to physical or mental illness. The Executive's continued employment shall not constitute consent to, or a waiver of rights with respect to, any act or failure to act constituting Good Reason hereunder.
"Involuntary Termination" means (a) a termination of employment by the Company other than for Cause, death, or Disability, or (b) the Executive's resignation of employment with the Company for Good Reason; provided, however, that, except as provided in the last paragraph of Section 4, a termination of the Executive's employment by reason of his or her retirement prior to a Change in Control shall not constitute an Involuntary Termination hereunder.
"Notice of Termination" has the meaning assigned thereto in Section 2 hereof.
"Person" means any person, entity or "group" within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act, except that such term shall not include (i) the Company or any of its Affiliates, (ii) a trustee or other fiduciary holding securities under an employee benefit plan of the Company or any of its Affiliates, (iii) an underwriter temporarily holding securities pursuant to an offering of such securities, (iv) a corporation owned, directly or indirectly, by the shareholders of Sempra Energy in substantially the same proportions as their ownership of stock of Sempra Energy, or (v) a person or group as used in Rule 13d-1(b) under the Exchange Act.
Section 2. Date and Notice of Termination. Any termination of the Executive's employment by the Company or by the Executive shall be communicated by a written notice of termination to the other party (the "Notice of Termination"). Where applicable, the Notice of Termination shall indicate the specific termination provision in this Agreement relied upon and shall set forth in reasonable detail the facts and circumstances claimed to provide a basis for termination of the Executive's employment under the provision so indicated. The date of the Executive's termination of employment with the Company (the "Date of Termination") shall be determined as follows: (i) if the Executive's employment is terminated by the Company, either with or without Cause, the Date of Termination shall be the date specified in the Notice of Termination (which, in the case of a termination by the Company other than for Cause, shall not be less than two (2) wee ks from the date such Notice of Termination is given unless the Company elects to pay the Executive, in addition to any other amounts payable hereunder, an amount equal to two (2) weeks of the Executive's base salary in effect on the Date of Termination), and (ii) if the basis for the Executive's Involuntary Termination is his or her resignation for Good Reason, the Date of Termination shall be determined by the Company, but shall not in any event be less than fifteen (15) days nor more than sixty (60) days from the date such Notice of Termination is given. Unless the Board determines otherwise, notice by Executive of his or her resignation for Good Reason must be made within 180 days of the act or failure to act the Executive alleges to constitute Good Reason.
Section 3. Severance Benefits Prior to Change in Control. Except as provided in Section 4 and Section 12(g) hereof, in the event of the Involuntary Termination of the Executive, the Company shall pay the Executive, in one lump sum cash payment as soon as practicable following such Involuntary Termination, (A) the full amount of any earned but unpaid base salary through the Date of Termination at the rate in effect on such date, plus (B) an amount (the "Severance Payment") equal to [Enter Applicable Multiplier]1.5 times the sum of (X) the Executive's annual base salary as in effect on the Date of Termination and (Y) his or her average annual bonus payment for the two years immediately preceding the Date of Termination (or in the event that the Executive has not been employed for two years, then his target bonus for the year in which the termination occurs). In addition to the Severance Payment, the Executive shall be entitled to the following additional benefits:
(i) Equity Based Compensation. The Executive shall retain all rights to any equity-based compensation awards to the extent set forth in the applicable plan and/or award agreement.
(ii) Welfare Benefits. Subject to Section 6 below, for a period of eighteen (18) months following the Date of Termination, the Executive and his or her dependents shall be provided with health insurance benefits substantially similar to those provided to the Executive and his or her dependents immediately prior to the Date of Termination; provided, however, that such benefits shall be provided on substantially the same terms and conditions and at the same cost to the Executive as in effect immediately prior to the Date of Termination.
(iii) Outplacement Services. The Executive shall receive outplacement services suitable to his or her position for a period of eighteen (18) months following the Date of Termination, or if earlier, until the first acceptance of an offer of employment with a subsequent employer, in an aggregate amount not to exceed $50,000.
(iv) Financial Planning Services. The Executive shall receive financial planning services for a period of eighteen (18) months following the Date of Termination at a level consistent with the benefits provided under the Company's financial planning program for the Executive, as in effect immediately prior to the Date of Termination.
Section 4. Severance Benefits in Connection with and After Change in Control. Notwithstanding the provisions of Section 3 above, in the event of the Involuntary Termination of the Executive within two years following a Change in Control, in lieu of the payments described in Section 3 above, the Company shall pay the Executive, in one lump sum cash payment as soon as practicable following such Involuntary Termination, (A) the full amount of any earned but unpaid base salary through the Date of Termination at the rate in effect on such date, plus (B) an amount (the "Change in Control Severance Payment") equal to [Enter Applicable Multiplier]two times the sum of (X) the Executive's annual base salary as in effect immediately prior to the Change in Control or the Date of Termination, whichever is greater, and (Y) his or her average annual bonus payment for the two years immediately preceding the Change in Control Date or the Date of Termination, whichever is greater (or in t he event that the Executive has not been employed for two years, then his target bonus for the year in which the Change in Control or in which the termination occurs, whichever is greater). In addition to the Change in Control Severance Payment, the Executive shall be entitled to the following additional benefits:
(i) Equity-Based Compensation. Notwithstanding the provisions of any applicable equity-compensation plan or award agreement to the contrary, all equity-based incentive compensation awards (including, without limitation, stock options, stock appreciation rights, restricted stock awards, restricted stock units, performance share awards, section 162(m) awards, and dividend equivalents) held by the Executive under any annual incentive compensation plan or long-term incentive compensation plan maintained by the Company shall immediately vest and become exercisable or payable, as the case may be, as of the Date of Termination, to be exercised or paid, as the case may be, in accordance with the terms of the applicable plan and award agreement, and any restrictions on any such awards shall automatically lapse; provided, however, that any such awards granted on or after the Effective Date shall remain outstanding and exercisable until the earlier of (A) eighteen (18) months fo llowing the Date of Termination or (B) the expiration of the original term of such award (it being understood that all awards granted prior to the Effective Date shall remain outstanding and exercisable for a period that is no less than that provided for in the applicable agreement in effect as of the date of grant).
(ii) SERP. The Executive shall receive a lump sum cash payment representing the present value as of the Date of Termination of his or her Supplemental Executive Retirement Plan ("SERP") benefits, to be calculated as if the Executive had reached age 62 (or his or her actual age if older), and applying either the applicable early retirement factors under the Company's tax-qualified retirement plan, if the Executive is less than age 62 but at least 55, or actuarially determined early retirement factors if the Executive is less than age 55 and the applicable lump-sum factors under the Company's tax-qualified retirement plan.
(iii) Welfare Benefits. Subject to Section 6 below, for a period of two years following the Date of Termination, the Executive and his or her dependents shall be provided with life, disability, accident and health insurance benefits substantially similar to those provided to the Executive and his or her dependents immediately prior to the Date of Termination or the Change in Control Date, whichever is more favorable to the Executive; provided, however, that such benefits shall be provided on substantially the same terms and conditions and at the same cost to the Executive as in effect immediately prior to the Date of Termination or the Change in Control Date, whichever is more favorable to the Executive.
(iv) Outplacement Services. The Executive shall receive outplacement services suitable to his or her position for a period of eighteen (18) months following the Date of Termination, or if earlier, until the first acceptance of an offer of employment with a subsequent employer, in an aggregate amount not to exceed $50,000.
(v) Financial Planning Services. The Executive shall receive financial planning services for a period of eighteen (18) months following the Date of Termination at a level consistent with the benefits provided under the Company's financial planning program for the Executive, as in effect immediately prior to the Date of Termination or the Change in Control Date, whichever is more favorable to the Executive.
(vi) Deferred Compensation. Notwithstanding any election heretofore or hereafter made by the Executive under any deferred compensation plan of the Company, the Executive shall receive a lump sum cash payment in an amount equal to any compensation previously deferred by the Executive (together with any accrued interest or earnings thereon) under any deferred compensation plan of the Company.
Notwithstanding anything contained herein, if a Change in Control occurs and the Executive's employment with the Company is terminated by reason of an Involuntary Termination prior to the Change in Control Date, and if such termination of employment (i) was at the request of a third party who has taken steps reasonably calculated to effect the Change in Control or (ii) otherwise arose in connection with or in anticipation of the Change in Control, then the Executive shall, in lieu of the payments described in Section 3 above, be entitled to the Change in Control Severance Payment and the additional benefits described in this Section 4 as if such Involuntary Termination had occurred within two years following the Change in Control.
Section 5. Release. Notwithstanding anything herein to the contrary, the Company's obligation to make the payments provided for in this Agreement is expressly made subject to and conditioned upon (i) the Executive's prior execution of a release substantially in the form attached hereto as Exhibit A within forty-five (45) days after the applicable Date of Termination and (ii) the Executive's non-revocation of such release in accordance with the terms thereof.
Section 6. No Mitigation or Offset.
(a) No Mitigation by Executive. Except as otherwise expressly provided herein, the Executive shall not be required to mitigate the amount of any payment provided for in this Agreement by seeking other employment or otherwise, nor shall the amount of any payment provided for herein be reduced by any compensation earned by the Executive as the result of employment by another employer; provided, however, that if the Executive becomes employed with another employer and is eligible to receive life, disability, accident and health insurance benefits under another employer-provided plan, the Executive's continued plan coverage as set forth in Section 3(ii) or 4(iii) hereof, as the case may be, shall be secondary to the coverage provided under such other plan(s) during such applicable period of eligibility.
(b) No Offset by Company. The Company's obligation to make the payments provided for in this Agreement and otherwise to perform its obligations hereunder shall not be affected by any set-off, counterclaim, recoupment, defense or other claim, right or action which the Company may have against the Executive or others, provided that nothing herein shall preclude the Company from separately pursuing recovery from the Executive based on any such claim.
Section 7. Section 280G
(a) Gross-Up. Notwithstanding any other provisions of this Agreement, in the event that any payment or benefit received or to be received by the Executive (whether pursuant to the terms of this Agreement or any other plan, arrangement or agreement with (A) the Company, (B) any Person whose actions result in a Change in Control or (C) any Person affiliated with the Company or such Person) (all such payments and benefits, including the Change in Control Severance Payments, being hereinafter called the "Total Payments") would be subject (in whole or part) to the tax (the "Excise Tax") imposed under section 4999 of the Code, the Company shall pay to the Executive such additional amounts (the "Gross-Up Payment") such that the net amount retained by the Executive, after deduction of any Excise Tax on the Total Payments and any federal, state and local income and employment taxes and Excise Tax upon the Gross-Up Payment, shall be equal to the Total Payments. For purposes of determining the amount of the Gross-Up Payment, the Executive shall be deemed to pay federal income tax at the highest marginal rate of federal income taxation in the calendar year in which the Gross-Up Payment is to be made and state and local income taxes at the highest marginal rate of taxation in the state and locality of the Executive's residence on the date on which the Gross-Up Payment is calculated for purposes of this section, net of the maximum reduction in federal income taxes which could be obtained from deduction of such state and local taxes. In the event that the Excise Tax is subsequently determined to be less than the amount taken into account hereunder, the Executive shall repay to the Company, at the time that the amount of such reduction in Excise Tax is finally determined, the portion of the Gross-Up Payment attributable to such reduction (plus that portion of the Gross-Up Payment attributable to the Excise Tax and federal, state and loca l income tax imposed on the Gross-Up Payment being repaid by the Executive to the extent that such repayment results in a reduction in Excise Tax and/or a federal, state or local income tax deduction) plus interest on the amount of such repayment at the rate provided in section 1274(b)(2)(B) of the Code. In the event that the Excise Tax is determined to exceed the amount taken into account hereunder (including by reason of any payment the existence or amount of which cannot be determined at the time of the Gross-Up Payment), the Company shall make an additional Gross-Up Payment in respect of such excess (plus any interest, penalties or additions payable by the Executive with respect to such excess) at the time that the amount of such excess is finally determined. The Executive and the Company shall each reasonably cooperate with the other in connection with any administrative or judicial proceedings concerning the existence or amount of liability for Excise Tax with respect to the Total Payments.
(b) Accounting Firm. All determinations to be made with respect to this Section 7 shall be made by the Company's independent accounting firm (or, in the case of a payment following a Change in Control, the accounting firm that was, immediately prior to the Change in Control, the Company's independent auditor). The accounting firm shall be paid by the Company for its services performed hereunder.
Section 8. Successors; Binding Agreement.
(a) Assumption by Successor. Sempra Energy will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business or assets of Sempra Energy expressly to assume and to agree to perform its obligations under this Agreement in the same manner and to the same extent that Sempra Energy would be required to perform such obligations if no such succession had taken place; provided, however, that no such assumption shall relieve Sempra Energy of its obligations hereunder. As used herein, the "Company" shall mean the Company as hereinbefore defined and any successor to its business and/or assets as aforesaid that assumes and agrees to perform its obligations by operation of law or otherwise.
(b) Enforceability; Beneficiaries. This Agreement shall be binding upon and inure to the benefit of the Executive (and the Executive's personal representatives and heirs) and the Company and any organization which succeeds to substantially all of the business or assets of Sempra Energy, whether by means of merger, consolidation, acquisition of all or substantially all of the assets of Sempra Energy or otherwise, including, without limitation, as a result of a Change in Control or by operation of law. This Agreement shall inure to the benefit of and be enforceable by the Executive's personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees. If the Executive should die while any amount would still be payable to such Executive hereunder if he or she had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Agreement to his or her devisee, legatee or other designee or, if there is no such designee, to his or her estate.
Section 9. Confidentiality; Non Solicitation.
(a) Confidentiality. The Executive acknowledges that in the course of his or her employment within the Company, he or she has acquired non-public privileged or confidential information and trade secrets concerning the operations, future plans and methods of doing business ("Proprietary Information") of the Company; and the Executive agrees that it would be extremely damaging to the Company if such Proprietary Information were disclosed to a competitor of the Company or to any other person or corporation. The Executive understands and agrees that all Proprietary Information the Executive has acquired during the course of such employment has been divulged to the Executive in confidence and further understands and agrees to keep all Proprietary Information secret and confidential (except for such information which is or becomes publicly available other than as a result of a breach by the Executive of this provision) without limitation in time. In view of the nature of the Execut ive's employment and the Proprietary Information the Executive has acquired during the course of such employment, the Executive likewise agrees that the Company would be irreparably harmed by any disclosure of Proprietary Information in violation of the terms of this paragraph and that the Company shall therefore be entitled to preliminary and/or permanent injunctive relief prohibiting the Executive from engaging in any activity or threatened activity in violation of the terms of this paragraph and to any other judicial relief available to it. Inquiries regarding whether specific information constitutes Proprietary Information shall be directed to the Company's General Counsel (or, if such position is vacant, the Company's Chief Executive Officer); provided, however, that the Company shall not unreasonably classify information as Proprietary Information.
(b) Non-Solicitation of Employees. The Executive recognizes that he or she possesses and will possess confidential information about other employees of the Company, relating to their education, experience, skills, abilities, compensation and benefits, and interpersonal relationships with customers of the Company. The Executive recognizes that the information he or she possesses and will possess about these other employees is not generally known, is of substantial value to the Company in developing their business and in securing and retaining customers, and has been and will be acquired by him or her because of his or her business position within the Company. The Executive agrees that for a period of one (1) year following the Date of Termination, he or she will not, directly or indirectly, solicit or recruit any employee of the Company for the purpose of being employed by him or her or by any other competitor of the Company on whose behalf he or she is acting as an agent, representative or em ployee and that he or she will not convey any such confidential information or trade secrets about other employees of the Company to any other person; provided, however, that it shall not constitute a solicitation or recruitment of employment in violation of this paragraph to discuss employment opportunities with any employee of the Company who has either first contacted the Executive or regarding whose employment the Executive has discussed with and received written approval of the Company's Senior Vice President, Human Resources (or, if such position is vacant, the Company's Chief Executive Officer), prior to making such solicitation or recruitment. In view of the nature of the Executive's employment with the Company, the Executive likewise agrees that the Company would be irreparably harmed by any solicitation or recruitment in violation of the terms of this paragraph and that the Company shall therefore be entitled to preliminary and/or permanent injunctive relief prohibiting the Executive from e ngaging in any activity or threatened activity in violation of the terms of this paragraph and to any other judicial relief available to it.
(c) Survival of Provisions. The obligations contained in this Section 9 shall survive the termination or expiration of the Executive's employment within the Company and shall be fully enforceable thereafter. If it is determined by a court of competent jurisdiction in any state that any restriction in this Section 9 is excessive in duration or scope or is unreasonable or unenforceable under the laws of that state, it is the intention of the parties that such restriction may be modified or amended by the court to render it enforceable to the maximum extent permitted by the law of that state.
Section 10. Notices. For the purpose of this Agreement, notices and all other communications provided for in this Agreement shall be in writing and shall be deemed to have been duly given when delivered or mailed by United States registered mail, return receipt requested, postage prepaid, addressed to Sempra Energy, 101 Ash Street, San Diego, CA 92101, Attn: Human Resources Administrator, or to the Executive at the address in the records of the Company, or to such other address as either party may have furnished to the other in writing in accordance herewith, except that notice of change of address shall be effective only upon receipt.
Section 11. Administration Prior to Change in Control. Prior to a Change in Control, the compensation committee of the Board (the "Compensation Committee") shall have full and complete authority to construe and interpret the provisions of this Agreement, to determine an individual's entitlement to benefits under this Agreement, to make in its sole and absolute discretion all determinations contemplated under this Agreement, to investigate and make factual determinations necessary or advisable to administer or implement this Agreement, and to adopt such rules and procedures as it deems necessary or advisable for the administration or implementation of this Agreement. All determinations made under this Agreement by the Compensation Committee shall be final and binding on all interested persons. Prior to a Change in Control, the Compensation Committee may delegate responsibilities for the operation and administration of this Agreement to one or more officers or employees of the Company. The provisions of this Section 11 shall terminate and be of no further force and effect upon the occurrence of a Change in Control.
Section 12. Miscellaneous.
(a) No Right of Employment. Nothing in this Agreement shall be construed as giving the Executive any right to be retained in the employ of the Company or shall interfere in any way with the right of the Company to terminate the Executive's employment at any time, with or without Cause.
(b) Unfunded Obligation. The obligations under this Agreement shall be unfunded. Benefits payable under this Agreement shall be paid from the general assets of the Company. The Company shall have no obligation to establish any fund or to set aside any assets to provide benefits under this Agreement.
(c) Rules of Construction. As used herein, the masculine gender shall be deemed to include the feminine and the singular form shall be deemed to encompass the plural, unless the context requires otherwise. Headings of sections (other than the definitions) are included solely for convenience of reference and shall not govern or control the meaning of the text of this Agreement. The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect.
(d) Tax Withholding. All amounts paid under this Agreement shall be subject to all applicable federal, state and local wage and employment tax withholding.
(e) Exclusive Benefit. The Severance Payment, the Change in Control Severance Payment and all other benefits provided hereunder shall be in lieu of any other severance payments to which the Executive is entitled under any other severance plan or arrangement sponsored by the Company, as well as pursuant to any individual employment or severance agreement that was entered by the Executive and the Company, and, upon the Effective Date of this Agreement, all such plans, programs, agreements and arrangements are hereby automatically superseded and terminated.
(f) Dispute Resolution. Any disagreement, dispute, controversy or claim arising out of or relating to this Agreement or the interpretation of this Agreement or any arrangements relating to this Agreement or contemplated in this Agreement or the breach, termination or invalidity thereof shall be settled by final and binding arbitration administered by JAMS/Endispute in San Diego, California in accordance with the then existing JAMS/Endispute Arbitration Rules and Procedures for Employment Disputes. In the event of such an arbitration proceeding, the Executive and the Company shall select a mutually acceptable neutral arbitrator from among the JAMS/Endispute panel of arbitrators. In the event the Executive and the Company cannot agree on an arbitrator, the Administrator of JAMS/Endispute will appoint an arbitrator. Neither the Executive nor the Company nor the arbitrator shall disclose the existence, content, or results of any arbitration hereunder without the prior written consent of all part ies. Except as provided herein, the Federal Arbitration Act shall govern the interpretation, enforcement and all proceedings. The arbitrator shall apply the substantive law (and the law of remedies, if applicable) of the state of California, or federal law, or both, as applicable and the arbitrator is without jurisdiction to apply any different substantive law. The arbitrator shall have the authority to entertain a motion to dismiss and/or a motion for summary judgment by any party and shall apply the standards governing such motions under the Federal Rules of Civil Procedure. The arbitrator shall render an award and a written, reasoned opinion in support thereof. Judgment upon the award may be entered in any court having jurisdiction thereof. The Executive and the Company shall generally each be responsible for payment of one-half the amount of the arbitrator's fee; provided, however, that the Company shall pay to the Executive all legal fees and expenses (including but not limited to fees and expenses in connection with any arbitration) incurred by the Executive in disputing in good faith any issue arising under this Agreement relating to the termination of the Executive's employment in connection with a Change in Control or in seeking in good faith to obtain or enforce any benefit or right provided by this Agreement on account of a Change in Control unless the arbitrator or court determines that the Executive had no reasonable basis for such claim.
(g) Amendment and Termination. No provision of this Agreement may be amended or terminated unless it is agreed to in writing and signed by both parties hereto. Notwithstanding anything contained herein, this Agreement shall automatically terminate and be of no further force and effect and no benefits shall be payable hereunder in the event that the Company sells or otherwise disposes of any part of the business or assets of Sempra Energy or a subsidiary of Sempra Energy (other than such a sale or disposition which is part of a transaction or series of transactions which would result in a Change in Control) and as a result of such transaction, the Executive is no longer employed by the Company or any of its Affiliates.
(h) Counterparts. This Agreement may be executed in several counterparts, each of which shall be deemed to be an original but all of which together shall constitute one and the same instrument.
(i) Governing Law. This Agreement shall be governed by the laws of the State of California, without giving effect to conflicts of laws principles thereof.
(j) Nonexclusivity of Rights. Nothing in this Agreement shall prevent or limit the Executive's continuing or future participation in any benefit, plan, program, policy or practice provided by the Company and for which the Executive may qualify (except with respect to any benefit to which the Executive has waived his rights in writing), nor shall anything herein limit or otherwise affect such rights as the Executive may have under any other contract or agreement entered into after the Effective Date with the Company. Amounts which are vested benefits or which the Executive is otherwise entitled to receive under any benefit, plan, policy, practice or program of, or any contract or agreement entered into with, the Company shall be payable in accordance with such benefit, plan, policy, practice or program or contract or agreement except as explicitly modified by this Agreement.
IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first written above.
SEMPRA ENERGY
By: ________________________
Stephen L. Baum[Name]
Chairman of the Board, President & Chief Executive Officer[Title]
EXECUTIVE
________________________
[Name of Executive][Name]
SEMPRA ENERGY
EXECUTIVE SECURITY BONUS PLAN
PURPOSE
The purpose of this Plan is to provide specified benefits to a select group of management and highly compensated employees and directors who contribute materially to the continued growth, development and future business success of Sempra Energy, a California corporation, and its subsidiaries. It is intended to be a bonus plan outside the scope of Title I of ERISA.
For purposes hereof, unless otherwise clearly apparent from the context, the following phrases or terms shall have the following indicated meaning:
1.1 "Account Balance" shall mean a dollar amount determined by the Committee, in its sole discretion and in accordance with Section 3.2 below, that is equal to that portion of the Trust's assets that have been allocated on the books of the Trust to a Participant as of an Account Balance Determination Date. In accordance with Section 8.3 of this Plan and the provisions of the Trust, this account balance shall be a bookkeeping entry and shall be utilized as a device for the measurement and determination of the amount to be paid to a Participant pursuant to this Plan and his or her respective Plan Agreement.
1.2 "Account Balance Determination Date" shall mean January 1 or July 1 of each Plan Year.
1.3 "Account Balance Fraction" shall mean a fraction determined as of a specified date, (i) the numerator of which is a specified Participant's Account Balance as of the Account Balance Determination Date that immediately precedes a Change in Control, and (ii) the denominator of which is the sum of the Account Balances, determined as of the Account Balance Determination Date that immediately precedes a Change in Control, of all Participants who have an unforfeited Account Balance as of that Account Balance Determination Date.
1.4 "Beneficiary" shall mean one or more persons, trusts, estates or other entities, designated in accordance with Article 5 below, that are entitled to receive benefits under this Plan upon the death of a Participant.
1.5 "Beneficiary Designation Form" shall mean the form established from time to time by the Committee that a Participant completes, signs and returns to the Committee to designate one or more Beneficiaries.
1.6 "Board" shall mean the Board of Directors of the Company.
1.7 "Change in Control" shall mean the date upon which the first of the following events occurs:
(a) Any Person is or becomes the Beneficial Owner, directly or indirectly, of securities of Sempra Energy representing twenty percent (20%) or more of the combined voting power of Sempra Energy's then outstanding securities; provided that such event shall not constitute a Change in Control if a majority of the members of the Board, as constituted immediately prior to such event, resolves that such event shall not be treated as a Change in Control for purposes of this Plan; or
(b) The following individuals cease for any reason to constitute a majority of the number of directors then serving: individuals who, on January 1, 2000, constitute the Board and any new director (other than a director whose initial assumption of office is in connection with an actual or threatened election contest, including, but not limited to, a consent solicitation, relating to the election of directors of Sempra Energy) whose appointment or election by the Board or nomination for election by Sempra Energy's shareholders was approved or recommended by a vote of at least two-third (2/3) of the directors then still in office who either were directors on the date hereof or whose appointment, election or nomination for election was previously so approved or recommended; provided that such event shall not constitute a Change in Control if a majority of the members of the Board, as constituted immediately prior to such event, resolves that such event shall not be treated as a Change in Control for purpo ses of this Plan; or
(c) There is consummated a merger or consolidation of Sempra Energy or any direct or indirect subsidiary of Sempra Energy with any other corporation, other than (i) a merger or consolidation which would result in the voting securities of Sempra Energy outstanding immediately prior to such merger or consolidation continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving entity or any parent thereof), in combination with the ownership of any trustee or other fiduciary holding securities under an employee benefit plan of Sempra Energy or any subsidiary of Sempra Energy, at least sixty percent (60%) of the combined voting power of the securities of Sempra Energy or such surviving entity or any parent thereof outstanding immediately after such merger or consolidation, or (ii) a merger or consolidation effected to implement a recapitalization of Sempra Energy (or similar transaction) in which no Person is or becomes the Beneficial Owner, direc tly or indirectly, of securities of Sempra Energy (not including in the securities beneficially owned by such Person any securities acquired directly from Sempra Energy or its affiliates other than in connection with the acquisition by Sempra Energy or its affiliates of a business) representing twenty percent (20%) or more of the combined voting power of Sempra Energy's then outstanding securities; provided that such event shall not constitute a Change in Control if a majority of the members of the Board, as constituted immediately prior to such event, resolves that such event shall not be treated as a Change in Control for purposes of this Plan; or
(d) The shareholders of Sempra Energy approve a plan of complete liquidation or dissolution of Sempra Energy or there is consummated an agreement for the sale or disposition by Sempra Energy of all or substantially all of Sempra Energy's assets, other than a sale or disposition by Sempra Energy of all or substantially all of Sempra Energy's assets to an entity, at least sixty percent (60%) of the combined voting power of the voting securities of which are owned by shareholders of Sempra Energy in substantially the same proportions as their ownership of Sempra Energy immediately prior to such sale; provided that such event shall not constitute a Change in Control if a majority of the members of the Board, as constituted immediately prior to such event, resolves that such event shall not be treated as a Change in Control for purposes of this Plan; or
(e) Sempra Energy voluntarily files a petition for bankruptcy under federal bankruptcy law, or an involuntary bankruptcy petition is filed against Sempra Energy under federal bankruptcy law, which involuntary petition is not dismissed within 120 days of the filing; or
(f) Sempra Energy makes a general assignment for the benefit of creditors; or
(g) Sempra Energy seeks or consents to the appointment of a trustee, receiver, liquidator or similar person.
An event described in Section 1.7(e), (f), or (g) may hereafter be referred to as a "Bankruptcy Event." For purposes of this Section 1.7: "Beneficial Owner" has the meaning set forth in Rule 13d-3 under the Securities Exchange Act of 1934 (the "Exchange Act"); and "Person" means any person, entity or "group" within the meaning of Section 13(d)(3) or Section 14(d)(2) of the Exchange Act, except that such term shall not include (v) the Company or any of its Affiliates (as defined in Rule 12b-2 under the Exchange Act), (w) a trustee or other fiduciary holding securities under an employee benefit plan of the Company or any of its Affiliates, (x) an underwriter temporarily holding securities pursuant to an offering of such securities, (y) a corporation owned, directly or indirectly, by the shareholders of Sempra Energy in substantially the same proportions as their ownership of stock of Sempra Energy, or (z) a person or group as used in Rule 13d-1(b) under the Exchange Act.
1.8 "Change in Control Benefit" shall mean the benefit set forth in Section 4.1 below.
1.9 "Claimant" shall have the meaning set forth in Section 11.1 below.
1.10 "Code" shall mean the Internal Revenue Code of 1986, as amended from time to time.
1.11 "Committee" shall mean the Compensation Committee of the Board which shall manage and administer the Plan in accordance with the provisions of Article 10 below.
1.12 "Company" shall mean Sempra Energy, a California corporation.
1.13 "Death Proceeds" shall mean, with respect to a deceased Participant, the death proceeds that the Trustee has or shall receive under one or more Policies as a result of a Participant's death.
1.14 "Disability" shall mean a period of disability during which a Participant qualifies for benefits under the Participant's Employer's long-term disability plan or, if a Participant does not participate in such a plan, a period of disability during which the Participant would have qualified for benefits under such a plan, as determined in the sole discretion of the Committee, had the Participant been a participant in such a plan.
1.15 "Employer" shall mean the Company and/or any of its subsidiaries that have been selected by the Board to participate in the Plan.
1.16 "Employer Benefit" shall mean the benefit set forth in Section 4.2 below.
1.17 "ERISA" shall mean the Employee Retirement Income Security Act of 1974, as amended from time to time.
1.18 "Excess Death Benefit" shall mean, with respect to a deceased Participant, a dollar amount determined as of the date of his or her death that is equal to (but not below zero) 75 percent of:
(a) the fair market value of the Trust's assets determined immediately after a Participant's death, after taking into account all Death Proceeds, if any, with respect to that Participant, less
(b) the fair market value of the Trust's assets determined immediately prior to that Participant's death, without taking into account any Death Proceeds, if any, with respect to that Participant.
1.19 "Insurer" shall mean the insurance company or companies that issue one or more Policies.
1 .20 "Participant" shall mean any employee or director of an Employer (a) who is selected to participate in the Plan, (b) who elects to participate in the Plan, (c) who signs a Plan Agreement and a Beneficiary Designation Form, (d) whose signed Plan Agreement and Beneficiary Designation Form are accepted by the Committee, and (e) whose Plan Agreement has not terminated.
1.21 "Plan" shall mean the Company's Executive Security Bonus Plan, which is defined by this instrument and by each Plan Agreement, all as may be amended from time to time.
1.22 "Plan Agreement" shall mean a written agreement, as may be amended from time to time, which is entered into by and between an Employer and a Participant. Each Plan Agreement executed by a Participant shall provide for the entire benefit to which such Participant is entitled to under the Plan, and the Plan Agreement bearing the latest date of acceptance by the Committee shall govern such entitlement.
1.23 "Plan Year" shall, for the first Plan Year, begin on January 1, 2001, and end on December 31, 2001. For each Plan Year thereafter, the Plan Year shall begin on January 1 of each year and continue through December 31 of that year.
1.24 "Policy" or "Policies" shall mean the policy or policies issued in the name of the Trustee in accordance with the terms and conditions of this Plan and each respective Plan Agreement.
1.25 "Retirement", "Retires" or "Retired" shall mean (a) in the case of an employee, the termination of a Participant's employment with all Employers after five years of service under the Sempra Energy Cash Balance Plan, or where applicable, the pension plan of a subsidiary of Sempra Energy, on or after the Participant attains age 55, or (b) in the case of a nonemployee director, the termination of a Participant's service as a director for any reason.
1.26 "Termination of Employment" shall mean, in the case of an employee, the ceasing of employment with all Employers, voluntarily or involuntarily, for any reason other than Retirement, Disability or death.
1.27 "Trust" shall mean the trust established pursuant to that certain Trust Agreement, dated as of January 1, 2001, between the Company and the Trustee, as amended from time to time.
1.28 "Trust Value Increase" shall mean, with respect to a Participant who vests in his or her Employer Benefit, a certain dollar amount that is equal to:
(a) the fair market value of the Trust's assets on the earlier of (i) the date of a Change in Control or (ii) the date a Participant Retires, dies, suffers a Disability or experiences an involuntary termination of employment with all Employers (which assets shall be determined after taking into account all distributions made on the specified date), plus
(b) the sum of the distributions, if any, made under Sections 4.1 and 4.2 below during the period of time that starts with the Account Balance Determination Date that immediately precedes the date of a Change in Control and ceases on the earlier of (i) the date of the Change in Control or (ii) the date of the Participant's Retirement, death, Disability or involuntary Termination of Employment with all Employers, less
(c) the fair market value of the Trust's assets as of the Account Balance Determination Date that immediately precedes the date of a Change in Control (which assets shall be determined after taking into account all distributions made on that Account Balance Determination Date), less
(d) that portion of all distributions described in Section 1.28(b) above that were determined under Sections 4. l(b)(ii)(2), 4.2(b)(ii)(2) and 4.2(b)(iii)(2) below, less
(e) that portion of all distributions described in Section 1.28(b) above that constitute Excess Death Benefits, less
(f) that portion of all Death Proceeds received by the Trustee that constitute Excess Death Proceeds and that are not distributed during the time period that starts on the Account Balance Determination Date that immediately precedes the date of the Change in Control and ceases on the earlier of (i) the date of the Change in Control or (ii) the date of the Participant's Retirement, death, Disability or involuntary Termination of Employment with all Employers.
1.29 "Trust Value Increase For Death" shall mean, with respect to a deceased Participant, a certain dollar amount that is equal to:
(a) the fair market value of the Trust's assets immediately preceding the Participant's death, without taking into account any Death Proceeds with respect to that Participant, if any, plus
(b) the sum of the distributions, if any, made under Sections 4.1 and 4.2 during the period of time that starts with the Account Balance Determination Date that coincides with or immediately precedes the deceased Participant's death and ceases with the deceased Participant's death, less
(c) the fair market value of the Trust's assets as of the Account Balance Determination Date that coincides or immediately precedes the Participant's death (which assets shall be determined after taking into account all distributions made on that Account Balance Determination Date), less
(d) that portion of all distributions described in Section 1.29(b) above that were determined under Sections 4.1(b)(ii)(2), 4.2(b)(ii)(2) and 4.2(b)(iii)(2) below, less
(e) that portion of all distributions described in Section 1.29(b) above that constitute Excess Death Benefits, less
(f) that portion of all Death Proceeds received by the Trustee that constitutes Excess Death Proceeds and that are not distributed during the time period that starts on the Account Balance Determination Date that coincides with or immediately precedes the date of the Change in Control and ceases immediately prior to the Participant's death.
1.30 "Trustee" shall mean the trustee named in the Trust and any successor trustee.
Article 2
Selection, Enrollment and Eligibility
2.1 Selection by Committee. Participation in the Plan shall be limited to (a) a select group of management and highly compensated employees of the Employers and (b) nonemployee directors of the Company. From that group, the Committee shall select, in its sole discretion, employees to participate in the Plan.
2.2 Enrollment Requirements. As a condition to participation, each selected employee, or director shall complete, execute and return to the Committee a Plan Agreement and a Beneficiary Designation Form. In addition, the Committee, in its sole discretion, shall establish from time to time such other enrollment requirements as it determines in its sole discretion are necessary.
2.3 Eligibility; Commencement of Participation. Provided an employee or director selected to participate in the Plan has met all enrollment requirements set forth in this Plan and required by the Committee, that employee or director shall commence participation in the Plan on the date specified by the Committee. If a selected employee or director fails to meet all such requirements prior to that date, that employee or director shall not be eligible to participate in the Plan until the completion of those requirements.
Article 3
Vesting; Account Balance Allocation
3.1 Vesting in Change in Control Benefit.
Any Participant actively employed by or in the service of an Employer on the date of a Change in Control shall become 100% vested in his or her Change in Control Benefit on the date of the Change in Control (the "Vesting Date"). Any Participant whose employment with all Employers terminates prior to the date of a Change in Control shall forfeit as of the date of termination all right to benefits under this Plan; provided, however, that if a Participant's employment or service terminates within 90 days of the Change in Control by reason of Retirement, death, disability or involuntary Termination of Employment, he or she shall become 100% vested in his or her Change in Control Benefit on the date of the Change in Control. In addition, a Participant's benefit hereunder shall be reduced dollar for dollar by the amount he or she receives under the Sempra Energy Deferred Compensation and Excess Savings Plan while still employed by or in the service of an Employer.
3.2 Account Balance Allocations. Within 60 days of an Account Balance Determination Date, each Participant with an Account Balance shall receive a statement of the dollar amount of his or her Account Balance. A Participant's Account Balance shall never be reduced below the amount of his or her Account Balance determined as of the most recent Account Balance Determination Date unless (a) a distribution is made under this Plan to the Participant or his or her Beneficiary or (b) the Participant forfeits his or her Account Balance in accordance with Section 3.1 above. On or after a Change in Control, no new statements will be sent to a Participant, and his or her benefits, if any, shall be determined and paid in accordance with Article 4.
Article 4
Benefits
4.1 Change in Control Benefit.
(a) Eligibility. On the Vesting Date, a Participant or the Participant's Beneficiary shall become entitled to the Change in Control Benefit described in this Section 4.1.
(b) Benefit and Payment. The "Change in Control Benefit" shall be a dollar amount that is equal to one of the following amounts:
(i) if the Participant does not Retire, die, suffer a Disability or experience an involuntary Termination of Employment with all Employers prior to the date of the Change in Control, the sum of:
(1) the Participant's Account Balance as of the Account Balance Determination Date that immediately precedes the date of the Change in Control, plus
(2) an amount equal to the result of multiplying the Trust Value Increase by the Participant's Account Balance Fraction determined as of the date of the Change in Control.
This benefit shall be paid to the Participant, or his or her Beneficiary, as soon as practicable following the Change in Control but in no event later than 90 days following the date of the Change in Control.
(ii) if the Participant Retires, dies, suffers a Disability or experiences an involuntary Termination of Employment with all Employers at any time within 90 days prior to a Change in Control, the sum of:
(1) the Participant's Account Balance as of the Account Balance Determination Date that immediately precedes the Change in Control, plus
(2) an amount equal to the result of multiplying the Trust Value Increase by the Participant's Account Balance Fraction determined as of the date the Participant Retired, died, suffered a Disability or experienced an involuntary Termination of Employment with all Employers.
This benefit shall be paid to the Participant, or his or her Beneficiary as soon as practicable following the date of the Change in Control but in no event later than 90 days following the date of the Change in Control.
4.2 Employer Benefit.
(a) Eligibility. The Participant's Employer shall be entitled to the Employer Benefit if:
(i) A Participant Retires, suffers a Disability or experiences a Termination of Employment prior to 90 days prior to a Change in Control;
(ii) A Participant has a voluntary Termination of Employment with all Employers at any time within 90 days prior to the date of a Change in Control;
(iii) A Participant dies at any time; or
(iv) A Participant receives any payment under the Sempra Energy Deferred Compensation and Excess Savings Plan while still employed by or in the service of an Employer.
(b) Benefit and Payment. The "Employer Benefit" shall be a dollar amount that is equal to one of the following amounts:
(i) If an event described in Section 4.2(a)(i) occurs in a Plan Year and the Change in Control does not occur on or prior to April 1 of the Plan Year following that event, 75 percent of the Participant's Account Balance as of January 1 of the Plan Year following that event. This benefit shall be paid to the Participant's Employer within 120 days of January 1 of the Plan Year following that event.
Despite the foregoing, if a former Participant dies at any time after the occurrence of an event described in Section 4.2(a)(i) and prior to January 1 of the Plan Year following that event, the Employer Benefit shall be determined and paid in accordance with Section 4.2(b)(iii) below rather than this Section 4.2(b)(i).
(ii) If an event described in Section 4.2(a)(ii) occurs, or if both an event described in Section 4.2(a)(i) above occurs in a Plan Year and a Change in Control occurs on or prior to April 1 of the Plan Year following that event, an amount equal to the sum of:
(1) 75 percent of the Participant's Account Balance as of the Account Balance Determination Date that immediately precedes the date of the Change in Control, plus
(2) an amount equal to the result of multiplying the Trust Value Increase by 75 percent of the Participant's Account Balance Fraction determined as of January 1 of the Plan Year following the event.
This benefit shall be paid to the Participant's Employer within 120 days of January 1 of the Plan Year that follows the Plan Year in which the event described in Section 4.2(a)(i) or (ii) above occurs.
(iii) If an event described in Section 4.2(a)(iii) occurs prior to 90 days prior to a Change in Control, an amount equal to the sum of:
(1) 75 percent of the deceased Participant's Account Balance as of the Account Balance Determination Date that coincides or immediately precedes the Participant's death, plus
(2) an amount equal to the result of multiplying the Trust Value Increase For Death by 75 percent of the deceased Participant's Account Balance Fraction determined as of the Participant's death, plus
(3) the Excess Death Benefit.
This benefit shall be paid to the Participant's Employer within 30 days of the date that the Trust receives the Death Proceeds, or if no such proceeds are to be received, within 90 days of the Participant's death.
(iv) If an event described in Section 4.2(a)(iii) occurs within 90 days prior to a Change in Control, an amount equal to the Excess Death Benefit, if any. This Employer benefit, if any, shall be paid to the Participant's Employer within 30 days of the date that the Trustee receives the Death Proceeds.
(v) If an event described in Section 4.2(a)(iv) occurs, the Employer shall receive as soon as practicable 75 percent of the amount by which the Participant's benefit hereunder is reduced as described in Section 3.1 hereof.
(c) Form of Payment. At the election of the Participant's Employer, the Employer Benefit shall be paid in the form of: (i) one or more Policies held in the Trust, (ii) other assets held in the Trust and/or (iii) immediately available funds.
4.3 Continuation of Account Balance. For purposes of Section 4.2 above only, if a Participant forfeits his or her interest in this Plan, his or her account shall continued to be maintained as if the Participant had not forfeited his or her interest, but only for the purpose of determining the Employer Benefit in accordance with Section 4.2 above. However, for purposes of Section 4.1, if a Participant forfeits his or her interest in the Plan, the Participant's Account Balance shall be treated as zero.
4.4 Withholding and Payroll Taxes. The Trustee shall withhold from any and all benefit payments made under this Article 4, all federal, state and local income, employment and other taxes required to be withheld in connection with the payment of benefits hereunder, in amounts to be determined in the sole discretion of the Participant's Employer.
5.1 Beneficiary. Each Participant shall have the right, at anytime, to designate his or her Beneficiary (both primary as well as contingent) to receive any benefits payable under the Plan to a Beneficiary upon the death of a Participant.
5.2 Beneficiary Designation; Change; Spousal Consent. A Participant shall designate his or her Beneficiary by completing and signing the Beneficiary Designation Form, and returning it to the Committee or its designated agent. A Participant shall have the right to change a Beneficiary by completing, signing and otherwise complying with the terms of the Beneficiary Designation Form and the Committee's rules and procedures, as in effect from time to time. If the Participant names someone other than his or her spouse as a Beneficiary, a spousal consent, in the form designated by the Committee, must be signed by that Participant's spouse and returned to the Committee. Upon the acceptance by the Committee of a new Beneficiary Designation Form, all Beneficiary designations previously filed shall be cancelled. The Committee shall be entitled to rely on the last Beneficiary Designation Form filed by the Participant and accepted by the Committee before his or her death.
5.3 Acknowledgment. No designation or change in designation of a Beneficiary shall be effective until received, accepted and acknowledged in writing by the Committee or its designated agent.
5.4 No Beneficiary Designation. If a Participant fails to designate a Beneficiary as provided in Sections 5.1, 5.2 and 5.3 above or, if all designated Beneficiaries predecease the Participant or die prior to complete distribution of the Participant's benefits, then the Participant's designated Beneficiary shall be deemed to be his or her surviving spouse. If the Participant has no surviving spouse, the benefits remaining under the Plan to be paid to a Beneficiary shall be payable to the executor or personal representative of the Participant's estate.
5.5 Doubt as to Beneficiary. If the Committee has any doubt as to the proper Beneficiary to receive payments pursuant to this Plan, the Committee shall have the right, exercisable in its discretion, before a Change in Control, to cause the Trustee to withhold such payments until this matter is resolved to the Committee's satisfaction.
5.6 Discharge of Obligations. The payment of benefits under the Plan to a Beneficiary shall fully and completely discharge all Employers and the Committee from all further obligations under this Plan with respect to the Participant, and that Participants Plan Agreement shall terminate upon such full payment of benefits.
Article 6
Termination, Amendment or
Modification of the Plan
6.1 Termination, Amendment or Modification Prior to One Year Before Change in Control. Prior to one year before a Change in Control, the Company reserves the right to terminate, amend or modify the Plan in whole or in part, and each Employer reserves the right to terminate, modify or amend a related Plan Agreement, in whole or in part, with respect to Participants employed by such Employer. Notwithstanding the foregoing, no termination, amendment or modification shall be effective to decrease or reduce a Participant's potential benefits under this Plan below his or her Account Balance as of the Account Balance Determination Date that coincides or immediately precedes the effective date of the termination, amendment or modification.
6.2 Termination, Amendment or Modification Within One Year Before Change of Control or Following Change in Control.
(a) General. Within one year before a Change in Control and thereafter, neither the Company, any subsidiary of the Company nor any corporation, trust or other person that succeeds to all or any substantial portion of the assets of the Company shall have the right to terminate, amend or modify the Plan and/or any Plan Agreement in effect prior to such Change in Control, and all benefits under the Plan and any such Plan Agreement shall thereafter be paid in accordance with the terms of the Plan and such Plan Agreement, as in effect immediately prior to such Change in Control. If the Plan is terminated, amended, or modified within one year before the Change in Control, such termination, amendment or modification shall be considered void as of the date of the termination, amendment or modification. Subject to Section 6.2(b) below, any provision of this Plan or any Plan Agreement to the contrary shall be construed in accordance with this Section 6.2(a).
(b) Compliance with ERISA and the Code.
(i) Notwithstanding any other provision of this Plan, if, at any time within one year before a Change in Control or following a Change in Control, counsel to the Company advises the Company in writing that it is counsel's opinion that the provisions of this Plan and/or any related Plan Agreement are not in compliance with ERISA or the Code or any final or proposed regulation or ruling under ERISA or the Code promulgated by the Department of Labor or the Internal Revenue Service, the Company shall have the right, in its sole discretion, to terminate, amend or modify this Plan and/or any related Plan Agreement in order to comply with such applicable law, to minimize the Plan's noncompliance with such applicable law and/or to prevent the Plan from failing to comply with such applicable law.
(ii) If the Company elects to terminate, amend or modify the Plan and/or any Plan Agreement under this Section 6.2(b), the Company may do so only to the extent that such amendment, modification or termination does not decrease or reduce a Participant's potential benefit under this Plan below his or her Account Balance as of the Account Balance Determination Date that coincides or immediately precedes the effective date of the termination, amendment or modification.
6.3 Termination of Plan Agreement. Absent the earlier termination, modification or amendment of the Plan, the Plan Agreement of any Participant shall terminate upon the full payment of the applicable benefit provided under Article 4.
Article 7
Other Benefits and Agreements
7.1 Coordination with Other Benefits. The benefits provided for a Participant and Participant's Beneficiary under the Plan are in addition to any other benefits available to such Participant under any other plan or program for employees. The Plan shall supplement and shall not supersede, modify or amend any other such plan or program except as may otherwise be expressly provided.
8.1 Establishment of the Trust; Premiums. The Employers shall establish the Trust and shall at least annually transfer over to the Trust such assets as the Committee determines, prior to a Change in Control, or the Trustee determines, after a Change in Control, are necessary to provide for the Employers' future liabilities created with respect to the benefits provided under the Plan and the Plan Agreements, including, without limitation, the payment of insurance premiums in amounts sufficient to acquire and maintain all Policies held by the Trustee. At the direction of the Committee, prior to a Change in Control, or the Trustee, after a Change in Control, the Employers shall pay any and all Policy premiums and other costs directly to the Insurer.
8.2 Interrelationship of the Plan and the Trust. The provisions of the Plan and a Plan Agreement shall govern the rights of a Participant and the Employers to receive distributions pursuant to the Plan. The provisions of the Trust shall govern the rights of the Trustee, Employers, Participant and a Participant's Beneficiary as to the assets of the Trust. The Employers shall at all times remain liable to carry out their obligations under the Plan.
8.3 Accounts.
(a) The Trustee shall establish and maintain the following separate accounts:
(i) A "Participant's Account" for each Participant to which the Employers' contributions, or a portion thereof, and earnings (or losses) thereon shall be allocated to and held, the assets of which are to be used to pay the Change in Control Benefit or the Employer Benefit in accordance with this Plan and the Trust; and
(ii) An "Administrative Account" for the administrative expenses of the Trust to which a portion of the Employers' contributions and earnings thereon may be allocated to and held in the event of a Change in Control pending payment by the Employer as provided in Section 3.6 of the Trust Agreement, the assets of which are to be used to pay the administrative expenses, including without limitation all taxes and legal expenses, of the Trust in accordance with the terms and provisions of this Plan and the Trust.
(iii) A "Reserve Account" to which shall be allocated all Employer contributions pending allocation to individual Participant accounts, Participant forfeitures not forming part of the Employer Benefit and any gains described further in this subsection. In the event of the death of a Participant or a former Participant whose life is insured by a Policy, the excess of (a) the life insurance proceeds received from such Policy over (b) the cash value of such Policy as of the date immediately preceding the Participant's death shall constitute a gain allocable to the Reserve Account.
(b) Prior to a Change in Control, the Committee shall direct the Trustee in writing as to:
(i) the allocation of the Employers' contributions to the accounts described in Section 8.3(a) above, and
(ii) the amounts of the earnings on the Employer's contributions held in the accounts described in Section 8.3(a) above. After a Change in Control, the Trustee shall make such allocations in accordance with the terms of the Plan and the Trust. Notwithstanding the foregoing, and except for a payment of benefits in accordance with Article 4 or a forfeiture of benefits, a Participant's Account balance shall not be reduced.
(c) Each of the accounts described in Section 8.3(a) above shall qualify for and be treated as separate shares under Code Section 663(c).
9.1 Policies. Pursuant to instructions given to the Trustee by the Committee, and in accordance with the terms and conditions of the Plan and each Plan Agreement, the Trustee shall acquire one or more Policies in its name.
9.2 Ownership of Insurance. The Trustee shall be the sole and absolute owner and beneficiary of each Policy, with all rights of an owner and beneficiary, including without limitation, the right to surrender Policies for their cash surrender values and to take one or more loans against one or more Policies. Notwithstanding the foregoing, the Trustee shall exercise its ownership rights in each Policy only in accordance with the terms of this Plan, the respective Plan Agreements and the Trust.
9.3 Documents Required By Insurer. The Trustee, the Participant's Employer and the Participant shall sign such documents and provide such information as may be required from time to time by the Insurer.
10.1 Committee Duties. This Plan shall be administered by the Committee. Members of the Committee may be Participants under this Plan. The Committee shall also have the discretion and authority to make, amend, interpret, and enforce all appropriate rules and regulations for the administration of this Plan and decide or resolve any and all questions including interpretations of this Plan, as may arise in connection with the Plan.
10.2 Agents. In the administration of this Plan, the Committee may, from time to time, employ agents and delegate to them such administrative duties as it sees fit and may from time to time consult with counsel who may be counsel to any Employer.
10.3 Binding Effect of Decisions. The decision or action of the Committee with respect to any question arising out of or in connection with the administration, interpretation and application of the Plan and the rules and regulations promulgated hereunder shall be final and conclusive and binding upon all persons having any interest in the Plan.
10.4 Indemnity of Committee. All Employers shall indemnify and hold harmless the members of the Committee against any and all claims, losses, damages, expenses or liabilities arising from any action or failure to act with respect to this Plan, except in the case of willful misconduct by the Committee or any of its members.
10.5 Employer Information. To enable the Committee to perform its functions, each Employer shall supply full and timely information to the Committee on all matters relating to the compensation of its Participants, the date and circumstances of the Retirement, Disability, death or Termination of Employment of its Participants, and such other pertinent information as the Committee may reasonably require.
11.1 Presentation of Claim. Any Participant or Beneficiary of a deceased Participant (such Participant or Beneficiary being referred to below as a "Claimant") may deliver to the Committee a written claim for a determination with respect to the amounts distributable to such Claimant from the Plan. If such a claim relates to the contents of a notice received by the Claimant, the claim must be made within 60 days after such notice was received by the Claimant. All other claims must be made within 180 days of the date on which the event that caused the claim to arise occurred. The claim must state with particularity the determination desired by the Claimant.
11.2 Notification of Decision. The Committee shall consider a Claimant's claim within a reasonable time, and shall notify the Claimant in writing:
(a) that the Claimant's requested determination has been made, and that the claim has been allowed in full; or
(b) that the Committee has reached a conclusion contrary, in whole or in part, to the Claimant's requested determination, and such notice must set forth in a manner calculated to be understood by the Claimant:
(i) the specific reason(s) for the denial of the claim, or any part of it;
(ii) the specific reference(s) to pertinent provisions of the Plan upon which such denial was based;
(iii) a description of any additional material or information necessary for the Claimant to perfect the claim, and an explanation of why such material or information is necessary; and
(iv) an explanation of the claim review procedure set forth in Section 11.3 below.
11.3 Review of a Denied Claim. Within 60 days after receiving a notice from the Committee that a claim has been denied, in whole or in part, a Claimant (or the Claimant's duly authorized representative) may file with the Committee a written request for a review of the denial of the claim. Thereafter, but not later than 30 days after the review procedure began, the Claimant (or the Claimant's duly authorized representative):
(a) may review pertinent documents;
(b) may submit written comments or other documents; and/or
(c) may request a hearing, which the Committee, in its sole discretion, may grant.
11.4 Decision on Review. The Committee shall render its decision on review promptly, and not later than 60 days after the filing of a written request for review of the denial, unless a hearing is held or other special circumstances require additional time, in which case the Committee's decision must be rendered within 120 days after such date. Such decision must be written in a manner calculated to be understood by the Claimant, and it must contain:
(a) specific reasons for the decision;
(b) specific reference(s) to the pertinent Plan provisions upon which the decision was based; and
(c) such other matters as the Committee deems relevant.
11.5 Legal Action. A Claimant's compliance with the foregoing provisions of this Article 11 is a mandatory prerequisite to a Claimant's right to commence any legal action with respect to any claim for benefits under this Plan.
12.1 Employer's Assets. Participants and their Beneficiaries, heirs, successors and assigns shall have no legal or equitable rights, interest or claims in any property or assets of an Employer. With respect to the Plan, any Plan Agreement and the Trust, any and all of an Employer's assets shall be, and shall remain, the general, unpledged and unrestricted assets of the Employer. An Employer's obligation under the Plan shall be merely that of making contributions to the Trust in order to provide benefits under this Plan. This obligation shall be an unfunded and unsecured promise to pay money.
12.2 Employer's Liability. An Employer's liability for the payment of benefits shall be defined only by the Plan and the Plan Agreement, as entered into between the Employer and a Participant. An Employer shall have no obligation to a Participant under the Plan except as expressly provided in the Plan.
12.3 Nonassignability. Neither a Participant nor any other person shall have any right to commute, sell, assign, transfer, pledge, anticipate, mortgage or otherwise encumber, transfer, hypothecate or convey in advance of actual receipt, the amounts, if any, payable hereunder, or any part thereof, which are, and all rights to which are expressly declared to be unassignable and non-transferable, except that the foregoing shall not apply to any family support obligations set forth in a court order. No part of the amounts payable shall, prior to actual payment, be subject to seizure or sequestration for the payment of any debts, judgments, alimony or separate maintenance owed by a Participant or any other person, nor be transferable by operation of law in the event of a Participant's or any other person's bankruptcy or insolvency.
12.4 Not a Contract of Employment. The terms and conditions of this Plan shall not be deemed to constitute a contract of employment or engagement between any Employer and the Participant. Such employment is hereby acknowledged to be an "at will" employment relationship that can be terminated at any time for any reason, with or without cause, unless expressly provided in a written employment agreement. Service as a director is subject to the Company's otherwise applicable rules on such matter. Nothing in this Plan shall be deemed to give a Participant the right to be employed or retained in the service of any Employer, or to interfere with the right of any Employer to discipline or discharge the Participant at any time.
12.5 Furnishing Information. A Participant will cooperate with the Committee by furnishing any and all information requested by the Committee and take such other actions as may be requested in order to facilitate the administration of the Plan and the payments of benefits hereunder, including but not limited to taking such physical examinations as the Committee may deem necessary.
12.6 Terms. Whenever any words are used herein in the singular or in the plural, they shall be construed as though they were used in the plural or the singular, as the case may be, in all cases where they would so apply.
12.7 Captions. The captions of the articles, sections and paragraphs of this Plan are for convenience only and shall not control or affect the meaning or construction of any of its provisions.
12.8 Governing Law. The provisions of this Plan shall be construed and interpreted according to the laws of the State of California.
12.9 Validity. In case any provision of this Plan shall be illegal or invalid for any reason, said illegality or invalidity shall not affect the remaining parts hereof, but this Plan shall be construed and enforced as if such illegal and invalid provision had never been inserted herein.
12.10 Notice. Any notice or filing required or permitted to be given to the Committee under this Plan shall be sufficient if in writing and hand-delivered, or sent by registered or certified mail, to the address below:
Joyce G. Rowland
Senior Vice President, Human Resources
Sempra Energy
101 Ash Street, HQ 18
San Diego, CA 92101
Such notice shall be deemed given as of the date of delivery or, if delivery is made by mail, as of the date shown on the postmark on the receipt for registration or certification.
Any notice or filing required or permitted to be given to a Participant under this Plan shall be sufficient if in writing and hand-delivered, or sent by mail, to the last known address of the Participant.
12.11 Successors. The provisions of this Plan shall bind and inure to the benefit of the Participant's Employer and its successors and assigns and the Participant, the Participant's Beneficiaries, and their permitted successors and assigns.
12.12 Spouse's Interest. The interest in the benefits hereunder of a spouse of a Participant who has predeceased the Participant shall automatically pass to the Participant and shall not be transferable by such spouse in any manner, including but not limited to such spouse's will, nor shall such interest pass under the laws of intestate succession.
12.13 Incompetent. If the Committee determines in its discretion that a benefit under this Plan is to be paid to a minor, a person declared incompetent or to a person incapable of handling the disposition of that person's property, the Committee may direct payment of such benefit to the guardian, legal representative or person having the care and custody of such minor, incompetent or incapable person. The Committee may require proof of minority, incompetency, incapacity or guardianship, as it may deem appropriate prior to distribution of the benefit. Any payment of a benefit shall be a payment for the account of the Participant and the Participant's Beneficiary, as the case may be, and shall be a complete discharge of any liability under the Plan for such payment amount.
12.14 Distribution in the Event of Taxation. If, for any reason, all or any portion of a Participant's benefit under this Plan becomes taxable to the Participant prior to the Vesting Date, a Participant may petition the Committee, if prior to a Change in Control, or the Trustee, after a Change in Control, for a distribution of assets sufficient to meet the Participant's tax liability (including additions to tax, penalties and interest). Upon the grant of such a petition, which grant shall not be unreasonably withheld, the Trustee shall distribute to the Participant from the Trust immediately available funds in an amount equal to that Participant's federal, state and local tax liability associated with such taxation (which amount shall not exceed a Participant's accrued benefit under the Plan), which liability shall be measured by using that Participant's then current highest federal, state and local marginal tax rate, plus the rates or amounts for the applicable additions to tax, penalt ies and interest. If the petition is granted, the tax liability distribution shall be made within 90 days of the date when the Participant's petition is granted.
12.15 Legal Fees To Enforce Rights After Change in Control. The Company is aware that upon the occurrence of a Change in Control, the Board (which might then be composed of new members) or a shareholder of any Employer, or of any successor corporation might then cause or attempt to cause an Employer or such successor to refuse to comply with its obligations under the Plan and might cause or attempt to cause an Employer to institute, or may institute, litigation seeking to deny Participants the benefits intended under the Plan. In these circumstances, the purpose of the Plan could be frustrated. Accordingly, if, following a Change in Control, it should appear to any Participant that the Company or the Participant's Employer has failed to comply with any of its obligations under the Plan or any agreement thereunder or, if the Company, the Participant's Employer or any other person takes any action to declare the Plan void or unenforceable or institutes any litigation or other legal actio n designed to deny, diminish or to recover from any Participant the benefits intended to be provided, then the Company and the Participant's Employer irrevocably authorize such Participant to retain counsel of his or her choice at the expense of the Company and the Participant's Employer to represent such Participant in connection with the initiation or defense of any
litigation or other legal action, whether by or against the Company or the Participant's Employer, or any director, officer, shareholder or other person affiliated with the Company, the Participant's Employer or any successor thereto in any jurisdiction.
IN WITNESS WHEREOF the Company has signed this Plan document as of January 1, 2001.
Sempra Energy,
a California corporation
|
By:__________________________________________ Its:__________________________________________ |
EXHIBIT 13.01
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
INTRODUCTION
The company is a California-based Fortune 500 energy services company whose principal utility subsidiaries are San Diego Gas & Electric (SDG&E), which provides electric and natural gas service in San Diego County and southern Orange County, and Southern California Gas Company (SoCalGas), the nation's largest natural gas distribution utility, serving 18 million customers through 5 million meters throughout most of Southern California and part of central California. Together, the two utilities (the California utilities) serve approximately 21 million customers through 7 million meters.
In addition, Sempra Energy owns and operates other regulated and unregulated subsidiaries. Sempra Energy Global Enterprises (Global) is the holding company for most of these businesses, primarily consisting of the following: Sempra Energy Trading (SET) is engaged in the wholesale trading and marketing of natural gas, power, petroleum and other commodities. Sempra Energy Resources (SER) develops power plants and natural gas storage, production and transportation facilities within the United States and the adjacent portion of Mexico. Sempra Energy International (SEI) develops, operates and invests in energy-infrastructure systems, primarily in Latin America. Sempra Energy Solutions (SES) provides an integrated mix of retail energy services, including facility management, supply and price-risk management, energy efficiency, energy-asset management and infrastructure ownership.
Sempra Energy Financial (SEF) invests in limited partnerships, which own 1,300 affordable-housing properties throughout the United States, Puerto Rico and the Virgin Islands. Through other subsidiaries, the company is involved in other energy-related products and services.
CAPITAL RESOURCES AND LIQUIDITY
The company's California utility operations have historically been a major source of liquidity. However, beginning in the third quarter of 2000 and continuing into the first quarter of 2001, SDG&E's liquidity and its ability to make funds available to Sempra Energy were adversely affected by the electric cost undercollections resulting from a temporary ceiling on electric rates legislatively imposed in response to high electric costs. Significant growth in these undercollections has ceased as a result of an agreement with the California Department of Water and Resources (DWR), under which the DWR is obligated to purchase SDG&E's full net short position consisting of the power and ancillary services required by SDG&E's customers that are not provided by SDG&E's nuclear generating facilities or its previously existing purchase power contracts. The agreement extends through December 31, 2002. In addition, the California Public Utilities Commission (CPUC) is conducting proceedings intended to establish guidelines and procedures for the eventual resumption of electricity procurement by SDG&E and the other California investor-owned utilities (IOUs). In addition, electric costs are now below and are expected to remain below the rates under the rate ceiling. See further discussion in Note 14 of the notes to Consolidated Financial Statements.
In June 2001, representatives of California Governor Davis, the DWR, Sempra Energy and SDG&E entered into a Memorandum of Understanding (MOU) contemplating the implementation of a series of transactions and regulatory settlements and actions to resolve many of the issues affecting SDG&E and its customers arising out of the California energy crisis. Many of the significant elements of the MOU have received the requisite approvals of the CPUC and have been implemented. These include settlement of reasonableness reviews and the application by SDG&E of its $100 million refund involving the prudence of its purchase-power costs and its overcollections in other regulatory balancing accounts to reduce the rate-ceiling balancing account to $392 million at December 31, 2001.
However, in January 2002, the CPUC rejected the MOU's proposed settlement regarding the rate-making treatment of favorably priced intermediate-term electricity purchase contracts held by SDG&E. In May 2001, the CPUC issued a decision that, effective February 1, 2001, electricity purchased under these contracts was to be provided by SDG&E to its customers at cost. This decision is inconsistent with prior CPUC staff positions that the electricity was to be provided at current market prices, with any resulting profits or losses borne by SDG&E.
In accordance with the May 2001 CPUC decision, SDG&E ceased recording profits from these contracts effective February 1, 2001, and none of the profits from the contracts, which have now expired, are included in the rate-ceiling balancing account. SDG&E had appealed the CPUC's decision to the California Court of Appeals, but held the appeal in abeyance pending the settlement contemplated by the MOU, under which $219 million of the contract profits (including those that would have been attributable to periods subsequent to February 1, 2001 and, therefore, are not reflected in income) would have been applied to reduce the rate-ceiling balancing account, with the balance of the profits retained by SDG&E. Following the CPUC rejection of this portion of the MOU in January 2002, SDG&E is proceeding with its appeal and has also filed a complaint in federal district court in San Diego against the CPUC alleging that the Commission's actions constitute an unconstitutional taking and have denied SDG&E its due process rights. The timing and manner of resolution of this issue will affect SDG&E's cash flows from the rate-ceiling balancing account.
For additional discussion, see "Factors Influencing Future Performance-Electric Industry Restructuring and Electric Rates" herein and Note 14 of the notes to Consolidated Financial Statements.
At December 31, 2001, the company had available $605 million in cash and $2.5 billion in unused, committed lines of credit. Management believes these amounts, cash flows from operations and new security issuances will be adequate to finance capital expenditures, shareholder dividends, any new business acquisitions or start-ups, and other commitments. If cash flows from operations were significantly reduced and/or the company were to be unable to issue new securities under acceptable terms, neither of which is considered likely, the company would be required to reduce non-utility capital expenditures and investments in new businesses.
At the California utilities, cash flows from operations and new securities issuances are expected to be adequate to meet utility capital expenditure requirements and provide significant funds to the company, which the company can apply toward shareholder dividend requirements and other needs.
SET provides cash to or requires cash from Sempra Energy as the level of its net trading assets fluctuates with prices, volumes, margin requirements (which are substantially affected by credit ratings and price fluctuations) and the length of its various trading positions. Its status as a source or use of Sempra Energy cash also depends on its level of borrowing from its own sources.
SER's projects are expected to be financed through a combination of a synthetic lease, project financing, SER's borrowings and funds from the company. Its capital expenditures over the next several years are expected to require a significant level of funding.
SEI is expected to require funding from the company and/or external sources to continue the expansion of its existing natural gas distribution operations in Mexico and its planned expansion involving natural gas transportation pipelines. SEI's South American operations are expected to be a net provider of funds for these purposes.
SES is expected to require moderate amounts of cash in the near future as it continues its expansion program. SEF is expected to continue to be a net provider of cash through reductions of consolidated income tax payments resulting from its investments in affordable housing and other ventures.
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by operating activities totaled $732 million, $882 million and $1,188 million for 2001, 2000 and 1999, respectively.
The decrease in cash flows from operating activities in 2001 compared to 2000 was primarily the result of balancing account activity at SoCalGas. This included returns of prior overcollections and the temporary effects of higher-than-expected costs of natural gas and public purpose programs and lower-than-expected sales volumes. The SoCalGas activity was partially offset by the increase in overcollected balancing accounts at SDG&E and lower customer refunds paid by SDG&E in 2001 (see below).
The decrease in cash flows from operating activities in 2000 compared to 1999 was due to increased net trading assets, SDG&E's refunds to customers for surplus rate-reduction-bond proceeds, SDG&E's cost undercollections related to high electric-commodity prices, and energy charges in excess of the 6.5 cents per kilowatt-hour (kWh) ceiling in accordance with AB 265 (see "California Utility Operations" below and Note 14 of the notes to Consolidated Financial Statements) and increased accounts receivable. These factors were partially offset by higher overcollected regulatory balancing accounts at SoCalGas, increased accounts payable and lower income tax payments. The increases in accounts receivable and accounts payable were primarily due to higher sales volumes and higher prices for natural gas and purchased power.
CASH FLOWS USED IN INVESTING ACTIVITIES
Net cash used in investing activities totaled $1,039 million, $924 million and $789 million for 2001, 2000 and 1999, respectively.
For 2001, cash flows used in investing activities primarily consisted of capital expenditures for the upgrade and expansion of California utility plant, construction costs for facilities under development in Mexico, and investments in generating plants being constructed in the western United States, partially offset by net proceeds received from the sale of the company's investment in Energy America, a residential energy-commodity retailer.
For 2000, cash flows from investing activities consisted primarily of capital expenditures of $522 million for utility plant and $167 million for investments in South America.
Capital Expenditures
Capital expenditures increased to $1.1 billion in 2001, compared with $759 million in 2000. The $300 million increase was primarily due to power plant construction costs for Termoelectrica de Mexicali (see further discussion under "Consolidated Subsidiaries" below) and increased costs associated with improving SoCalGas' distribution system. Capital expenditures for property, plant, and equipment by the California utilities were $601 million.
Capital expenditures were $170 million higher in 2000 compared to 1999 due to improvements to SDG&E's electric distribution system and to the California utilities' gas systems, investments in gas distribution facilities in Canada and Mexico and expenditures for gas turbines associated with SER's Elk Hills Power Project (see further discussion under "Unconsolidated Subsidiaries" below and Note 3 of the notes to Consolidated Financial Statements).
Over the next five years, the company expects to make capital expenditures of $3.9 billion at the California utilities and is committed to $1.0 billion of capital expenditures at the other subsidiaries, including $700 million for the four new power plants being constructed by SER. In addition, the company is evaluating an additional $2.5 billion of capital expenditures, which are not yet committed.
Construction, investment and financing programs are continuously reviewed and revised by the company in response to changes in economic conditions, competition, customer growth, inflation, customer rates, the cost of capital, and environmental and regulatory requirements. The construction program is also tied to SER's contract to supply electricity to the DWR, as discussed below under "Sempra Energy Resources."
Capital expenditures in 2002 are expected to be significantly higher than in 2001. Significant capital expenditures are expected to include $1.5 billion for California utility plant improvements and the SER power plant construction. These expenditures are expected to be financed partly by security issuances.
Investments
Investments and acquisition costs were $111 million, $243 million and $639 million for 2001, 2000 and 1999, respectively, as the company has made various investments and entered into several joint ventures over the three-year period.
During 2001, SER invested $91 million into the Elk Hills Power Project (Elk Hills), a $410 million, 570-megawatt power plant near Bakersfield, California. Elk Hills is being developed in a 50/50 joint venture with Occidental Energy Ventures Corporation (Occidental) and will supply electricity to California. Through December 31, 2001, SER had invested a total of $133 million in the project, which is anticipated to be completed during the first half of 2003. Information concerning litigation with Occidental is provided in Note 13 of the notes to Consolidated Financial Statements.
In October 2000, SEI invested an additional $147 million in two Argentine natural gas utility holding companies (Sodigas Pampeana S.A. and Sodigas Sur S.A.). In addition, SES purchased Connectiv Thermal Systems' 50-percent interests in Atlantic-Pacific Las Vegas and Atlantic-Pacific Glendale for a total of $40 million in August 2000, thereby acquiring full ownership of these companies. In September 2000, the company acquired for $8 million a significant interest in Atlantic Electric and Gas in the United Kingdom, a retail energy marketer.
In June 1999, SEI and PSEG Global (PSEG) jointly purchased 90 percent of Chilquinta Energia S.A. (Energia) at a total cost of $840 million. With the January 2000 joint purchase of an additional 9.75 percent, the companies jointly and equally hold 99.98 percent of Energia. In September 1999, SEI and PSEG completed their acquisition of 47.5 percent of Luz del Sur S.A.A. (Luz). SEI's share of the transaction was $108 million. This acquisition, combined with the interest already owned through Energia, increased the companies' total joint and equal ownership to 84.5 percent of Luz. SEI's carrying value of the Luz investment was $114 million and $121 million as of December 31, 2001 and 2000, respectively.
In February 2002, SET acquired London-based Enron Metals Limited, the leading metals trader on the London Metals Exchange, for $145 million and changed its name to Sempra Metals Limited.
The company's level of investments in the next few years may vary substantially and will depend on the availability of financing and business opportunities providing desirable rates of return.
Consolidated Subsidiaries
In addition to its principal, wholly owned subsidiaries, the company has various other investments in which it owns greater than fifty percent of the subsidiary. The acquisitions of these subsidiaries are accounted for under the purchase method of accounting. The subsidiaries in which significant capital commitments exist are noted below. Further information concerning these subsidiaries is provided in Note 3 of the notes to Consolidated Financial Statements.
Sempra Energy International
In June 2000, SEI and PG&E Corporation announced an agreement to construct the North Baja Pipeline, a $230 million, 215-mile natural gas pipeline which will extend from Arizona to the Rosarito Pipeline south of Tijuana. The agreement calls for SEI to construct, own and operate the 135-mile segment of the pipeline within Mexico, and PG&E Corporation to construct, own and operate the 80-mile segment within the United States. The 30-inch pipeline will deliver 500 million cubic feet per day of natural gas to new generation facilities in Baja California, including SER's Termoelectrica de Mexicali power plant discussed below. SEI has begun construction of the pipeline and has recorded capital investments of $75 million as of the end of 2001. Completion of SEI's portion of the project is contemplated for the summer of 2002.
SEI's Mexican subsidiaries Distribuidora de Gas Natural (DGN) de Mexicali, DGN de Chihuahua and DGN de La Laguna Durango are the licensees to build and operate natural gas distribution systems in Mexicali, Chihuahua, and the La Laguna-Durango zone in north-central Mexico, respectively. SEI owns interests of 60, 95 and 100 percent in the projects, respectively. As of December 31, 2001, DGN-Mexicali, DGN-Chihuahua and DGN-La Laguna Durango have capital investments of $22 million, $52 million and $25 million, respectively.
Sempra Energy Resources
In February 2001, the company announced plans to construct Termoelectrica de Mexicali, a $350 million, 600-megawatt power plant near Mexicali, Mexico. Fuel for the plant will be supplied via the planned pipeline from Arizona to Tijuana discussed above. It is anticipated that the electricity produced by the plant will be exported for consumption in the United States via the 230,000-volt transmission line which is also under construction. Construction of the power plant began in the second half of 2001. $135 million has been invested in the project, which is scheduled for completion by mid-2003.
In December 2000, SER obtained approval from the appropriate state agencies to construct the Mesquite Power Plant. Located near Phoenix, Arizona, Mesquite Power is a $700 million, 1,200-megawatt project which will provide electricity to wholesale energy markets in the Southwest region. Ground was broken in March 2001, with project completion anticipated in 2003. The project is being financed partially via the synthetic lease agreement described in Note 13 of the notes to Consolidated Financial Statements.
Unconsolidated Subsidiaries
Investments in which Sempra Energy owns twenty to fifty percent of the affiliated company are accounted for under the equity method. The company's pro rata shares of the net assets of these affiliates are recorded as investments, and are adjusted for the company's share of each affiliate's earnings and dividends. Investments in affiliated companies accounted for under the equity method amounted to $1.1 billion and $1.3 billion at December 31, 2001 and 2000, respectively, which included goodwill of $248 million and $280 million, respectively, as described in Note 3 of the notes to Consolidated Financial Statements. Earnings are recorded as equity earnings on the Statements of Consolidated Income within the caption "other income - net." In 2001, the company recorded $12 million in equity earnings, received dividends of $80 million and, due to a foreign currency translation adjustment, reduced the carrying value of its Argentine investments by $155 million. Investments in unconsolidated subsidiari es or joint ventures in which significant capital commitments exist are noted below.
Sempra Energy International
SEI is involved in several investments and projects. In October 2001, SEI and CMS Energy Corporation announced plans to jointly develop an LNG receiving facility on a 300-acre site along the Pacific coast near Ensenada, Mexico. The joint venture will develop the $400 million facility and related port infrastructure, which will provide one billion cubic feet per day of natural gas. SEI has entered into a memorandum of understanding with a Bolivian consortium for the supply of LNG to the facility. Commercial operation of the facility is scheduled to begin in late 2005.
Sempra Energy Resources
SER has invested $133 million in the Elk Hills Power project described above. SER anticipates its share of the remaining construction costs will be $70 million.
See further discussion of investing activities, including the $155 million adjustment relating to Argentina, in Note 3 of the notes to Consolidated Financial Statements.
CASH FLOWS FROM FINANCING ACTIVITIES
Net cash provided by (used in) financing activities totaled $275 million, $192 million and ($336) million for 2001, 2000 and 1999, respectively.
Net cash provided by financing activities in 2001 was more than that provided in 2000 due to greater issuances of debt (excluding that related to common stock repurchases which occurred in 2000).
Net cash was provided by financing activities in 2000 compared to being used in 1999, due to the issuance of long-term and short-term debt in 2000 (excluding that related to the repurchase of common stock), and lower common stock dividends.
Long-Term and Short-Term Debt
In 2001, the company issued $500 million in long-term debt, primarily for capital expenditures by the Global subsidiaries. The net short-term debt increase of $310 million in 2001 primarily represented borrowings through Global. Funds were used to finance construction costs of various power plant and pipeline projects in Mexico by SEI, and investments by SER for generating plants being constructed in California and Arizona. During 2001, $82 million of the Employee Stock Ownership (ESOP) debt and $25 million of variable-rate unsecured bonds were remarketed at 7.375 percent and 6.75 percent, respectively. $60 million of variable-rate industrial development bonds were put back by holders in 2000 and also remarketed in 2001. In addition, SEI refinanced $160 million of long-term notes through an unconsolidated affiliate. Repayments on long-term debt in 2001 included $150 million of first-mortgage bonds, $66 million of rate-reduction bonds and $120 million of unsecured debt.
In 2000, the company issued $500 million of long-term notes and $200 million of mandatorily redeemable trust preferred securities to finance the repurchase of 36.1 million shares of its outstanding common stock. The company issued an additional $300 million of long-term notes during 2000 to repay a portion of its short-term debt. The net increase in short-term debt primarily represents borrowings through Global, used to finance the construction of natural gas distribution systems by SEI; and borrowings by SET to finance increased trading activities. Repayments on long-term debt in 2000 included $10 million of first-mortgage bonds, $65 million of rate-reduction bonds and $51 million of unsecured debt. In addition, as noted above during December 2000, $60 million of variable-rate industrial development bonds were put back by the holders and subsequently remarketed in February 2001 at a fixed interest rate of 7 percent.
In 1999, repayments on long-term debt included $28 million of first-mortgage bonds, $66 million of rate-reduction bonds and $82 million of unsecured notes. The long-term debt issued in 1999 related primarily to the purchase of Energia. See additional discussion in Note 3 of the notes to Consolidated Financial Statements. The increase in short-term debt primarily represents borrowings through Global to finance a portion of SEI's acquisitions.
Stock Purchases and Redemptions
As noted above, in February 2000, the company completed a self-tender offer, purchasing 36.1 million shares of its outstanding common stock at $20 per share. In March 2000, the company's board of directors authorized the optional expenditure of up to $100 million to repurchase additional shares of common stock from time to time in the open market or in privately negotiated transactions. The company acquired 60,000 shares and 162,400 shares under this authorization in 2001 and 2000, respectively.
Dividends
Dividends paid on common stock amounted to $203 million in 2001, compared to $244 million in 2000 and $368 million in 1999. The lower dividends in 2001 were due to the 36.1 million stock repurchase noted above. The decrease in 2000 was due to a reduction in the quarterly dividend to $0.25 per share from its previous level of $0.39 per share and to the stock repurchase.
The payment of future dividends and the amount thereof are within the discretion of the company's board of directors. The CPUC's regulation of the California utilities' capital structure limits to $458 million the portion of the California utilities' December 31, 2001, retained earnings that is available for dividends to the company.
Capitalization
Total capitalization at December 31, 2001, was $7.6 billion. The debt-to-capitalization ratio was 60 percent at December 31, 2001. Significant changes in capitalization during 2001 include the increase in short-term debt and the effect of the $155 million non-cash reduction to equity to reflect the devaluation of the Argentine peso and its effect on the two Argentine investments held by SEI.
Cash and Cash Equivalents
At December 31, 2001, the company had $2.5 billion of committed lines of credit, none of which were borrowed. Also at December 31, 2001, the company had $548 million of uncommitted lines of credit, of which $261 million was available for additional borrowings or additional letters of credit. A description of the credit lines and other information concerning them and related matters is provided in Notes 4, 5 and 13 of the notes to Consolidated Financial Statements. Management believes these amounts, cash flows from operations and new security issuances will be adequate to finance capital expenditures, shareholder dividends, any new business acquisitions or start-ups, and other commitments.
Commitments
The following is a summary of the company's contractual commitments at December 31, 2001 (in millions of dollars). Additional information concerning these commitments is provided above and in Notes 4, 5, 11 and 13 of the notes to Consolidated Financial Statements.
|
|
|
By Period |
|||||||||||||
|
Description |
|
2002 |
|
2003 and 2004 |
|
2005 and 2006 |
|
Thereafter |
|
Total |
|||||
|
Short-term debt |
|
$ |
875 |
|
$ |
-- |
|
$ |
-- |
|
$ |
-- |
|
$ |
875 |
|
Long-term debt |
|
|
242 |
|
|
883 |
|
|
487 |
|
|
2,066 |
|
|
3,678 |
|
Mandatorily redeemable trust preferred securities |
|
|
-- |
|
|
-- |
|
|
-- |
|
|
200 |
|
|
200 |
|
Preferred stock of subsidiaries subject to mandatory redemption |
|
|
-- |
|
|
3 |
|
|
3 |
|
|
19 |
|
|
25 |
|
Operating leases |
|
|
66 |
|
|
172 |
|
|
186 |
|
|
1,183 |
|
|
1,607 |
|
Purchased power contracts |
|
|
224 |
|
|
390 |
|
|
343 |
|
|
2,000 |
|
|
2,957 |
|
Natural gas contracts |
|
|
649 |
|
|
545 |
|
|
289 |
|
|
155 |
|
|
1,638 |
|
Construction commitments |
|
|
622 |
|
|
130 |
|
|
25 |
|
|
25 |
|
|
802 |
|
Environmental commitments |
|
|
18 |
|
|
29 |
|
|
23 |
|
|
-- |
|
|
70 |
|
Totals |
|
$ |
2,696 |
|
$ |
2,152 |
|
$ |
1,356 |
|
$ |
5,648 |
|
$ |
11,852 |
Credit Ratings
|
(As of March 11, 2002) |
|
S&P |
|
Moody's |
|
Fitch |
|
SEMPRA ENERGY |
|
|
|
|
|
|
|
Unsecured Debt |
|
A |
|
A2 |
|
A |
|
Commercial Paper |
|
A-1 |
|
P-1 |
|
F1 |
|
Trust Preferred Securities |
|
BBB+ |
|
A3 |
|
A- |
|
|
|
|
|
|
|
|
|
SDG&E |
|
|
|
|
|
|
|
Secured Debt |
|
AA- |
|
Aa3 |
|
AA |
|
Unsecured Debt |
|
A+ |
|
A1 |
|
AA- |
|
Preferred Stock |
|
A |
|
A3 |
|
A+ |
|
Commercial Paper |
|
A-1+ |
|
P-1 |
|
F1+ |
|
|
|
|
|
|
|
|
|
SOCALGAS |
|
|
|
|
|
|
|
Secured Debt |
|
AA- |
|
A1 |
|
AA |
|
Unsecured Debt |
|
A+ |
|
A2 |
|
AA- |
|
Preferred Stock |
|
A |
|
Baa1 |
|
A+ |
|
Commercial Paper |
|
A-1+ |
|
P-1 |
|
F1+ |
|
|
|
|
|
|
|
|
|
PACIFIC ENTERPRISES |
|
|
|
|
|
|
|
Preferred Stock |
|
A- |
|
- |
|
A+ |
|
|
|
|
|
|
|
|
|
SEMPRA ENERGY GLOBAL ENTERPRISES |
|
|
|
|
|
|
|
Unsecured Debt |
|
- |
|
A2 |
|
- |
|
Commercial Paper |
|
A-1 |
|
P-1 |
|
F1 |
|
|
|
|
|
|
|
|
RESULTS OF OPERATIONS
2001 Compared to 2000
Net income for 2001 increased to $518 million, or $2.52 per diluted share of common stock, from $429 million, or $2.06 per diluted share of common stock, in 2000.
The $89 million increase in net income was primarily due to higher earnings achieved by SET, as a result of higher volatility in energy markets during the first half of 2001 and a substantial increase in trading volumes. Also contributing to the increase was a $20 million after-tax gain on the sale of Energy America in 2001, and the effect in 2000 of a $30 million after-tax charge at SDG&E for regulatory issues. These factors were partially offset by lower income generated at SER and SEI. The lower income at SER primarily resulted from the contracted sale of electricity to the DWR at a discounted price, as discussed in "Sempra Energy Resources" below. The decrease at SEI was due to a $25 million after-tax charge for its surrender of a natural gas franchise in Nova Scotia. See additional discussion in "California Utility Operations," "Sempra Energy Trading," "Sempra Energy International" and "Other Operations" below.
For the fourth quarter of 2001, net income was $107 million, or $0.52 per diluted share of common stock, compared with $95 million, or $0.47 per diluted share of common stock, for the fourth quarter of 2000. The increase in quarterly earnings was primarily attributable to the favorable settlement of various income tax issues, partially offset by lower prices and reduced volatility in the energy market, and development costs on new power plants.
In 2001, book value per share increased to $13.16 from $12.35 in 2000, primarily because net income exceeded the sum of dividends and the foreign currency translation loss related to the Argentine peso.
2000 Compared to 1999
Net income for 2000 increased to $429 million, or $2.06 per diluted share of common stock, from $394 million, or $1.66 per diluted share of common stock, in 1999.
The $35 million increase in net income was primarily due to higher earnings achieved by SET and, to a much lesser extent, by SEI and SER. These increases were partially offset by lower income generated from the California utility operations and higher interest expense. The lower income at the California utilities resulted primarily from the SDG&E charge noted above.
For the fourth quarter of 2000, net income was $95 million, or $0.47 per diluted share of common stock, compared with $105 million, or $0.44 per diluted share of common stock, for the fourth quarter of 1999. The decrease in earnings was primarily attributable to increased interest costs and income taxes, partially offset by higher earnings from the company's trading and generation operations. The increase in earnings per share was due to the decrease in weighted average shares for the fourth quarter of 2000 in comparison to the corresponding period in 1999, partially offset by the lower net income.
In 2000, book value per share decreased to $12.35 from $12.58 in 1999, due to the repurchase of 36.1 million shares of common stock in February 2000, at a price higher than book value.
CALIFORNIA UTILITY OPERATIONS
To understand the operations and financial results of the California utilities, it is important to understand the ratemaking procedures that they follow.
The California utilities are regulated by the CPUC. It is the responsibility of the CPUC to determine that utilities operate in the best interests of their customers and have the opportunity to earn a reasonable return on investment. In 1996, California enacted legislation restructuring California's investor-owned electric utility industry. The legislation and related decisions of the CPUC were intended to stimulate competition and reduce electric rates. As part of the framework for a competitive electric-generation market, the legislation established the California Power Exchange (PX) and the Independent System Operator (ISO). The PX served as a wholesale power pool and the ISO scheduled power transactions and access to the transmission system. Due to subsequent industry restructuring developments, the PX suspended its trading operations in January 2001.
The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating natural gas sales to noncore customers. In December 2001, the CPUC issued a decision adopting several provisions that the California utilities believe will make gas service more reliable, efficient and better tailored to the desires of customers. The CPUC is still considering the schedule for implementation of these regulatory changes, but it is expected that most of the changes will be implemented during 2002.
In connection with restructuring of the electric and natural gas industries, the California utilities received approval from the CPUC for Performance-Based Ratemaking (PBR). Under PBR, income potential is tied to achieving or exceeding specific performance and productivity measures, rather than to expanding utility plant in a market where a utility already has a highly developed infrastructure.
See additional discussion of these situations under "Factors Influencing Future Performance" and in Notes 14 and 15 of the notes to Consolidated Financial Statements.
The tables below summarize the California utilities' natural gas and electric volumes and revenues by customer class for the years ended December 31, 2001, 2000 and 1999.
GAS SALES, TRANSPORTATION AND EXCHANGE
(Dollars in millions, volumes in billion cubic feet)
for the years ended December 31
|
|
Gas Sales |
Transportation and Exchange |
Total |
||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
|
Volumes |
Revenue |
Volumes |
Revenue |
Volumes |
Revenue |
|||||||||||||||||||||||||||||||||||||||||||||||||||
|
2001: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||||||||||
Residential |
297 |
|
$ |
2,797 |
|
|
2 |
$ |
6 |
|
299 |
|
$ |
2,803 |
|
||||||||||||||||||||||||||||||||||||||||||
Commercial and industrial |
113 |
|
|
903 |
|
|
262 |
|
174 |
|
375 |
|
|
1,077 |
|
||||||||||||||||||||||||||||||||||||||||||
Electric generation plants |
-- |
|
|
-- |
|
|
417 |
|
104 |
|
417 |
|
|
104 |
|
||||||||||||||||||||||||||||||||||||||||||
Wholesale |
-- |
|
|
-- |
|
|
40 |
|
10 |
|
40 |
|
|
10 |
|
||||||||||||||||||||||||||||||||||||||||||
|
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
|
410 |
|
$ |
3,700 |
|
|
721 |
$ |
294 |
|
1,131 |
|
|
3,994 |
|
||||||||||||||||||||||||||||||||||||||||||
Balancing accounts and other |
|
|
|
|
|
|
|
|
|
|
|
|
|
377 |
|
||||||||||||||||||||||||||||||||||||||||||
Total |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
4,371 |
|
||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||||||||||||||||||||||
|
2000: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||||||||||
Residential |
284 |
|
$ |
2,446 |
|
|
3 |
$ |
13 |
|
287 |
|
$ |
2,459 |
|
||||||||||||||||||||||||||||||||||||||||||
Commercial and industrial |
107 |
|
|
760 |
|
|
339 |
|
225 |
|
446 |
|
|
985 |
|
||||||||||||||||||||||||||||||||||||||||||
Electric generation plants |
-- |
|
|
-- |
|
|
373 |
|
130 |
|
373 |
|
|
130 |
|
||||||||||||||||||||||||||||||||||||||||||
Wholesale |
-- |
|
|
-- |
|
|
25 |
|
18 |
|
25 |
|
|
18 |
|
||||||||||||||||||||||||||||||||||||||||||
|
|
|||||||||||||||||||||||||||||||||||||||||||||||||||||||||
|
|
391 |
$ |
3,206 |
|
|
740 |
|
$ |
386 |
|
1,131 |
|
|
3,592 |
|
||||||||||||||||||||||||||||||||||||||||||
Balancing accounts and other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(287 |
) |
|||||||||||||||||||||||||||||||||||||||||
Total |
|
|
|
|
|
|
|
|
|
|
|
|
$ |
3,305 |
|
||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||||||||||||||||||||||
|
1999: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||||||||||
Residential |
313 |
$ |
2,091 |
|
|
3 |
|
$ |
10 |
|
316 |
|
$ |
2,101 |
|
||||||||||||||||||||||||||||||||||||||||||
Commercial and industrial |
105 |
|
560 |
|
|
324 |
|
|
243 |
|
429 |
|
|
803 |
|
||||||||||||||||||||||||||||||||||||||||||
Electric generation plants |
18 |
|
7 |
* |
|
218 |
|
|
83 |
|
236 |
|
|
90 |
|
||||||||||||||||||||||||||||||||||||||||||
Wholesale |
-- |
|
-- |
|
|
23 |
|
|
11 |
|
23 |
|
|
11 |
|
||||||||||||||||||||||||||||||||||||||||||
|
|
436 |
$ |
2,658 |
|
|
568 |
|
$ |
347 |
|
1,004 |
|
|
3,005 |
|
||||||||||||||||||||||||||||||||||||||||||
Balancing accounts and other |
|
|
|
|
|
|
|
|
|
|
|
|
(94 |
) |
|||||||||||||||||||||||||||||||||||||||||||
Total |
|
|
|
|
|
|
|
|
|
|
|
$ |
2,911 |
|
|||||||||||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||||||||||||||
|
* |
|
Consists of the interdepartmental margin on SDG&E's sales to its power plants prior to their sale in the first half of 1999. |
ELECTRIC SALES
(Dollars in millions, volumes in million kWhs)
for the years ended December 31
|
|
|
2001 |
|
2000 |
1999 |
|||||||||||||||
|
|
|
Volumes |
Revenue |
Volumes |
Revenue |
Volumes |
Revenue |
|||||||||||||
|
Residential |
|
6,011 |
|
$ |
775 |
|
|
6,304 |
|
$ |
730 |
|
6,327 |
|
$ |
663 |
||||
|
Commercial |
|
6,107 |
|
|
753 |
|
|
6,123 |
|
|
747 |
|
6,284 |
|
|
592 |
||||
|
Industrial |
|
2,792 |
|
|
325 |
|
|
2,614 |
|
|
310 |
|
2,034 |
|
|
154 |
||||
|
Direct access |
|
2,464 |
|
|
84 |
|
|
3,308 |
|
|
99 |
|
3,212 |
|
|
118 |
||||
|
Street and highway lighting |
|
89 |
|
|
10 |
|
|
74 |
|
|
7 |
|
73 |
|
|
7 |
||||
|
Off-system sales |
|
249 |
|
|
39 |
|
|
899 |
|
|
59 |
|
383 |
|
|
10 |
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
|
|
17,712 |
|
|
1,986 |
|
|
19,322 |
|
|
1,952 |
|
18,313 |
|
|
1,544 |
||||
|
Balancing and other |
|
|
|
|
(359 |
) |
|
|
|
|
232 |
|
|
|
|
274 |
||||
|
|
||||||||||||||||||||
|
Total |
|
17,712 |
|
$ |
1,627 |
|
|
19,322 |
|
$ |
2,184 |
|
18,313 |
|
$ |
1,818 |
||||
2001 Compared to 2000
Electric revenues decreased from $2.2 billion in 2000 to $1.6 billion in 2001, and the cost of electric fuel and purchased power decreased from $1.3 billion in 2000 to $0.7 billion in 2001. These decreases were primarily due to the DWR's purchases of SDG&E's net short position. These purchases and the corresponding sale to SDG&E's customers are not included in the Statements of Consolidated Income since SDG&E was merely transporting the electricity from the DWR to the customers. Similarly, PX/ISO power revenues have been netted against purchased-power expense to avoid double-counting as SDG&E sells power into the PX/ISO and then purchases power therefrom. In addition, volumes were down compared to 2000 due to reductions in customer demand, arising from conservation efforts encouraged by the State of California program to give bill credits (funded by the DWR) to customers who significantly reduced usage. It is uncertain when SDG&E's electric volumes will return to levels of prior years .
Other operating expenses increased from $1.1 billion in 2000 to $1.3 billion in 2001. The increase was primarily due to increased wages and employee benefits costs, as well as an increase in operation costs associated with balancing accounts.
2000 Compared to 1999
Natural gas revenues increased from $2.9 billion in 1999 to $3.3 billion in 2000, primarily due to higher prices for natural gas in 2000 and higher electric generation plant revenues. The increase in electric generation plant revenues was due to higher demand for electricity in 2000 and the sale of SDG&E's fossil fuel generating plants in the second quarter of 1999. Prior to the plant sale, SDG&E's natural gas revenues from these plants consisted of the margin from the sales. Subsequent to the plant sale, SDG&E's gas revenues consisted of the price of the natural gas transportation service since the sales now are to unrelated parties. In addition, the generating plants receiving gas transportation from the California utilities were operating at higher capacities than previously, as discussed below.
Electric revenues increased from $1.8 billion in 1999 to $2.2 billion in 2000. The increase was primarily due to higher sales to industrial customers and the effect of higher electric commodity costs, partially offset by the $50 million pretax charge at SDG&E for a potential regulatory disallowance related to the acquisition of wholesale power in the deregulated California market, and the decrease in base electric rates (the noncommodity portion) from the completion of stranded cost recovery. For 2000, SDG&E's electric revenues included an undercollection of $447 million as a result of the 6.5-cent rate cap.
The cost of natural gas distributed increased from $1.2 billion in 1999 to $1.6 billion in 2000. The increase was largely due to higher prices for natural gas. Prices for natural gas increased due to the increased use of natural gas to fuel electric generation, colder winter weather and population growth in California.
The cost of electric fuel and purchased power increased from $0.5 billion in 1999 to $1.3 billion in 2000. The increase was primarily due to the higher cost of electricity from the PX that has resulted from higher demand for electricity and the shortage of power plants in California, higher prices for natural gas used to generate electricity (as described above), the sale of SDG&E's fossil fuel generating plants, and warmer weather in California. Under the current regulatory framework, changes in on-system prices normally do not affect net income. See the discussions of balancing accounts and electric revenues in Note 2 of the notes to Consolidated Financial Statements.
In September 2000, as a result of high electricity costs the CPUC authorized SDG&E to purchase up to 1,900 megawatts of power directly from third-party suppliers under both short-term contracts and long-term contracts. Subsequent to December 31, 2000, the state of California authorized the DWR to purchase all of SDG&E's power requirements not covered by its own generation or by existing contracts. These and related events are discussed more fully in Note 14 of the notes to Consolidated Financial Statements.
Depreciation and amortization expense decreased from $0.8 billion in 1999 to $0.5 billion in 2000 and other operating expenses decreased from $1.2 billion in 1999 to $1.1 billion in 2000. Both decreases were primarily due to the 1999 sale of SDG&E's fossil fuel generating plants.
SEMPRA ENERGY TRADING
SET, a leading marketer of natural gas, electricity, petroleum, petroleum products and other commodities headquartered in Stamford, Connecticut, was acquired on December 31, 1997. SET is a full-service energy trading company and also has offices in Europe, Canada and Asia. For the year ended December 31, 2001, SET recorded net revenues of $1.0 billion compared to $795 million for the prior year. SET's gross revenues were $33.5 billion and $25.6 billion in 2001 and 2000, respectively.
For the year ended December 31, 2001, SET recorded net income of $196 million, compared to net income of $155 million and $19 million in 2000 and 1999, respectively. The increase in net income in 2001 compared to 2000 was primarily due to high volatility in energy markets during the first half of 2001 and an increase in trading volumes, partially offset by reduced profitability in Europe. The increase in net income for 2000 compared to 1999 was due to increased volatility in the U.S. energy markets and higher earnings from European crude oil trading.
A summary of SET's unrealized revenues for trading activities for the year ended December 31, 2001 (in millions of dollars) follows:
|
Balance at beginning of year |
|
$ |
(72 |
) |
|
Additions |
|
|
1,333 |
|
|
Realized |
|
|
856 |
|
|
Balance at end of year |
|
$ |
405 |
|
|
Source of fair value |
2002 |
2003 and |
|
|
2005 and |
|
|
Thereafter |
|
Total fair value |
|
|||||||||||||||||
|
Exchange prices |
|
$ |
(37 |
) |
|
$ |
(15 |
) |
|
$ |
-- |
|
|
$ |
-- |
|
$ |
(52 |
) |
|||||||||
|
Prices actively quoted |
|
|
181 |
|
|
|
239 |
|
|
|
(9 |
) |
|
|
-- |
|
|
411 |
|
|||||||||
|
Prices provided by other external sources |
|
|
(2 |
) |
|
|
(1 |
) |
|
|
(11 |
) |
|
|
18 |
|
|
4 |
|
|||||||||
|
Prices based on models and other valuation methods |
|
|
(1 |
) |
|
|
16 |
|
|
|
23 |
|
|
|
4 |
|
|
42 |
|
|||||||||
|
Total |
|
$ |
141 |
|
|
$ |
239 |
|
|
$ |
3 |
|
|
$ |
22 |
|
$ |
405 |
|
|||||||||
SEMPRA ENERGY INTERNATIONAL
SEI develops, operates and invests in energy-infrastructure systems. SEI has interests in natural gas and/or electric transmission and distribution projects in Argentina, Chile, Mexico, Peru and the eastern United States, and is pursuing other projects, primarily in Mexico.
As noted above in "Investments," SEI increased its investment in Sodigas Pampeana S.A. and Sodigas Sur S.A. in 2000. These natural gas distribution companies serve 1.3 million customers in central and southern Argentina, respectively, and have a combined sendout of 650 million cubic feet per day. See further discussion at Note 3 of the notes to Consolidated Financial Statements.
In December 1999, Sempra Atlantic Gas (SAG), a subsidiary of SEI, was awarded a 25-year franchise by the government of Nova Scotia to build and operate a natural gas distribution system. In September 2001, due to new conditions required by the government of Nova Scotia, SAG notified the government that it intended to surrender its natural gas distribution franchise. SAG recorded an after-tax expense of $25 million related to the surrender of the franchise.
Net income from international operations in 2001 was $25 million compared to net income of $33 million and $2 million for 2000 and 1999, respectively. The decrease in net income for 2001 was primarily due to SAG's surrender of the natural gas franchise in Nova Scotia discussed above, partially offset by increased earnings at the Latin American subsidiaries. The increase in net income for 2000 was primarily due to the first full year of results from Luz and Energia, and improved operating results at Sodigas Pampeana S.A. and Sodigas Sur S.A.
Additional information concerning the company's international operations is provided in Note 3 of the notes to Consolidated Financial Statements.
SEMPRA ENERGY RESOURCES
SER develops, owns and operates power plants for the competitive market, and owns natural gas storage, production and transportation assets. SER is planning to develop 5,000 to 10,000 megawatts of generation within the next decade, primarily in the southwestern United States. SER is a 50-percent partner in El Dorado Energy, a 500-megawatt power plant located near Las Vegas, Nevada, which began commercial operation in 2000. In addition, SER has three power plants under construction. SER's share of El Dorado and the new plants will provide 2,400 megawatts of electricity when completed. See additional discussion regarding construction of these power plants in the "Investments" section above.
In May 2001, SER entered into a ten-year agreement with the DWR to supply up to 1,900 megawatts of power to the state. SER intends to deliver most of this electricity from its projected portfolio of plants in the western United States and Baja California, Mexico. Sales under the contract comprise more than two-thirds of the capacity referred to above. The company's ability to increase its earnings is significantly dependent on results to be provided by the DWR agreement. In accordance with the DWR contract, on June 1, 2001, SER began providing to the DWR 250 megawatts of capacity at prices discounted from normal contract prices. This electricity was supplied through market purchases and SER's share of the El Dorado generating facility. In accordance with the contract, sales to the DWR ceased from October 1, 2001 through March 31, 2002, the period during which expected demands for energy are lower due to cooler weather. Deliveries under the contract are scheduled to recommence on April 1, 2002 (witho ut discounting) and end on September 30, 2011.
Subsequent to the state's signing of this contract and electricity-supply contracts with other vendors, various state officials have contended that the rates called for by the contracts are too high. These rates substantially exceed current spot-market prices for electricity, but are substantially lower than those prevailing at the time the contracts were signed. In February 2002, the CPUC and the California Electricity Oversight Board petitioned the Federal Energy Regulatory Commission to determine that the contracts do not provide just and reasonable rates, and to abrogate or reform the contracts. The company believes that its contract prices were fair, but has offered to renegotiate certain aspects of its contract (which would not affect the long-term profitability) in a manner mutually beneficial to SER and the state.
SER recorded a net loss of $27 million in 2001, compared to net income of $29 million and $5 million in 2000 and 1999, respectively. The decline in results for 2001 was primarily due to SER's sale of electricity to the State of California at a discounted price in the first phase of the long-term contract described above and the successful operations of the El Dorado power plant in 2000 when market prices for electricity were higher than in 2001 or 1999.
OTHER OPERATIONS
Sempra Energy's retail energy services, concentrated primarily in SES, provides integrated energy-related products and services to commercial, industrial, government, institutional and consumer markets. This includes owning and/or operating customer heating and cooling systems, providing energy efficient retrofitting and supplying energy commodities. The retail energy services' operations recorded net income of $2 million in 2001, compared to net losses of $23 million and $11 million in 2000 and 1999, respectively. The losses for 2000 and 1999 are primarily attributable to start-up costs, which continued in 2001 but were more than offset by the 2001 gain from the sale of Energy America as noted above.
In delivering electric and gas supplies to its commercial and industrial customers, SES hedges its price exposure through the use of exchange-traded and over-the-counter financial instruments. A summary of SES' unrealized revenues for trading activities for the year ended December 31, 2001 (in millions of dollars) follows:
|
Balance at beginning of year |
|
$ |
2 |
|
|
Additions |
|
|
75 |
|
|
Realized |
|
|
(8 |
) |
|
Balance at end of year |
|
$ |
69 |
|
|
Source of fair value |
2002 |
2003 and |
2005 and |
Thereafter |
Total fair value |
||||||||||
|
Exchange prices |
|
$ |
3 |
|
$ |
-- |
|
$ |
-- |
|
$ |
-- |
|
$ |
3 |
|
Prices actively quoted |
|
|
31 |
|
|
31 |
|
|
3 |
|
|
1 |
|
|
66 |
|
Total |
|
$ |
34 |
|
$ |
31 |
|
$ |
3 |
|
$ |
1 |
|
$ |
69 |
OTHER INCOME, INTEREST EXPENSE AND INCOME TAXES
Other Income
Other income, which primarily consists of interest income from short-term investments, equity earnings from unconsolidated subsidiaries and interest on regulatory balancing accounts, decreased to $90 million in 2001 from $127 million in 2000. The decrease was primarily due to the lower earnings from SER's investment in the El Dorado power plant, partially offset by higher interest income and $19 million from SDG&E's sale of its property in Blythe, California. Other income increased in 2000 to $127 million from $50 million in 1999, primarily due to improved equity earnings from El Dorado and from unconsolidated subsidiaries of SEI, and higher balancing-account interest.
Interest Expense
Interest expense for 2001 increased to $323 million from $286 million in 2000. The increase was primarily due to interest expense incurred on long-term debt issued in December of 2000 and June of 2001 as described in Note 5 of the notes to the Consolidated Financial Statements, and on higher short-term commercial paper borrowings in 2001. Interest expense increased to $286 million in 2000 from $229 million in 1999. The increase was primarily due to interest expense incurred on long-term debt issued in connection with the company's common stock repurchase, as described in Notes 5 and 12 of the notes to the Consolidated Financial Statements, and on short-term commercial paper borrowings made in 2000, offset by its 2000 expense associated with the surplus bond proceeds discussed in Note 5 of the notes to Consolidated Financial Statements. Interest rates on certain of the company's debt can vary with credit ratings, as described in Notes 4 and 5 of the notes to Consolidated Financial Statements.
Income Taxes
Income tax expense was $213 million, $270 million and $179 million for 2001, 2000 and 1999, respectively. The effective income tax rates were 29.1 percent, 38.6 percent and 31.2 percent for the same years. The decrease in income tax expense for 2001 compared to 2000 was primarily due to the favorable settlement of various tax issues and higher income tax credits, partially offset by the fact that any income tax benefits from certain losses outside the United States, primarily related to the SAG franchise surrender discussed above, are not yet recordable.
The increase in income tax expense for 2000 compared to 1999 was due to the increase in income before taxes and the fact that SDG&E made a charitable contribution to the San Diego Unified Port District in 1999 in connection with the sale thereto of its South Bay generating plant.
FACTORS INFLUENCING FUTURE PERFORMANCE
Base results of the company in the near future will depend primarily on the results of the California utilities, while earnings growth and volatility will result primarily from activities at SET, SEI, SER and other businesses. The factors influencing future performance are summarized below.
Electric Industry Restructuring and Electric Rates
In 1996, California enacted legislation restructuring California's investor-owned electric utility industry. The legislation and related decisions of the CPUC were intended to stimulate competition and reduce electric rates. During the transition period, utilities were allowed to charge frozen rates that were designed to be above current costs by amounts assumed to provide a reasonable opportunity to recover the above-market "stranded" costs of investments in electric-generating assets. The rate freeze was to end for each utility when it completed recovery of its stranded costs, but no later than March 31, 2002. SDG&E completed recovery of its stranded costs in June 1999 and, with its rates no longer frozen, SDG&E's overall rates became subject to fluctuation with the actual cost of electricity purchases.
Supply/demand imbalances and a number of other factors resulted in abnormally high electric-commodity costs beginning in mid-2000 and continuing into 2001. This caused SDG&E's monthly customer bills to be substantially higher than normal. In response, legislation enacted in September 2000 imposed a ceiling of 6.5 cents/kWh on the cost of electricity that SDG&E could pass on to its residential, small-commercial and lighting customers. The legislation provides for the future recovery of undercollections in a manner (not specified in the decision) intended to make SDG&E whole for the reasonable and prudent costs of procuring electricity. The undercollection, included as a noncurrent regulatory asset on the Consolidated Balance Sheets, amounted to $392 million at December 31, 2001.
As a result of the passage of Assembly Bill 1 in February 2001, the DWR began to purchase power from generators and marketers to supply a portion of the power requirements of the state's population that is served by IOUs. The DWR is now purchasing SDG&E's full net short position (the power needed by SDG&E's customers, other than that provided by SDG&E's nuclear generating facilities or its previously existing purchase power contracts). Therefore, increases in SDG&E's undercollections would result only from these contracts and interest, offset by nuclear generation, the cost of which is below the 6.5-cent customer rate cap. Any increases are not expected to be material.
On June 18, 2001, representatives of California Governor Davis, the DWR, Sempra Energy and SDG&E entered into the MOU, contemplating the implementation of a series of transactions and regulatory settlements and actions to resolve many of the issues affecting SDG&E and its customers arising out of the California energy crisis. The MOU contemplated, subject to requisite approvals of the CPUC, the elimination from SDG&E's rate-ceiling balancing account of the undercollected costs that otherwise would be recovered in future rates charged to SDG&E customers; settlement of reasonableness reviews, electricity purchase contract issues and various other regulatory matters affecting SDG&E. During 2001, the CPUC dealt with several of these regulatory settlements, including approval of a reduction of the rate-ceiling balancing account by the application thereto of overcollections in certain other balancing accounts totaling $70 million and approval of a delay in the effective date of revised base rates for the California utilities to 2004. In addition, the CPUC approved a $100 million reduction of the rate-ceiling balancing account in settlement of the reasonableness of SDG&E's electric procurement practices between July 1, 1999 through February 7, 2001.
In January 2002, the CPUC rejected the part of the MOU dealing with a settlement on electricity purchase contracts held by SDG&E. The MOU would have granted SDG&E ownership of its power sale profits in exchange for crediting $219 million to customers to offset the rate-ceiling balancing account. Instead, the CPUC asserted that all the profits associated with the energy purchase contracts should accrue to the benefit of customers. The CPUC estimated these profits as $363 million. The company believes the CPUC's calculation is incorrect and the CPUC has not explained to the company how it arrived at that amount. In addition, the company believes the CPUC's position is incorrect and has challenged the CPUC's original disallowance in the Court of Appeals. The court challenge was put on hold when the MOU was reached. SDG&E has now reactivated the case and has also filed a similar suit in federal court. Further discussion is included in Note 14 of the notes to Consolidated Financial Statements.
As discussed in Note 15 of the notes to Consolidated Financial Statements, the California utilities will make new cost of service filings at the end of 2002. Upon approval by the CPUC, new rates will be effective January 1, 2004. See additional discussion of these and related topics in Note 15 of the notes to Consolidated Financial Statements.
In September 2001, the CPUC suspended the ability of retail electricity customers to choose their power provider ("direct access") until at least the end of 2003 in order to improve the probability that enough revenue would be available to the DWR to cover the state's power purchases. The decision forbids new direct access contracts after September 20, 2001. In January 2002, a draft decision was issued modifying the direct access suspension decision, suspending direct access retroactively to July 1, 2001. This issue is on the CPUC's agenda for March 21, 2002. An unfavorable decision could adversely affect SES's contracts signed between July 1, 2001 and September 20, 2001. Any effect is not expected to be material to the company's financial position.
The CPUC is studying whether the incentive plan for the San Onofre Nuclear Generating Station (SONGS) should be terminated earlier than currently scheduled. This is discussed in Note 2 of the notes to Consolidated Financial Statements. The effects of an earlier termination are not yet determinable.
Natural Gas Restructuring and Gas Rates
On December 11, 2001, the CPUC issued a decision adopting the following provisions affecting the structure of the natural gas industry in California, some of which could introduce additional volatility into the earnings of the California utilities and other market participants: a system for shippers to hold firm, tradable rights to capacity on SoCalGas' major gas transmission lines with SoCalGas' shareholders at risk for whether market demand for these rights will cover the cost of these facilities; a further unbundling of SoCalGas' storage services, giving SoCalGas greater upward pricing flexibility (except for storage service for core customers) but with increased shareholder risk for whether market demand will cover storage costs; new balancing services including separate core and noncore balancing provisions; a reallocation among customer classes of the cost of interstate pipeline capacity held by SoCalGas and an unbundling of interstate capacity for gas marketers serving core customers; and the elim ination of noncore customers' option to obtain gas supply service from the California utilities. The CPUC is still considering the schedule for implementation of these regulatory changes, but it is expected that most of the changes will be implemented during 2002.
Electric-Generation Assets
As discussed in "CASH FLOWS USED IN INVESTING ACTIVITIES" above, the company is involved in the development of several electric-generation projects. SER is a 50-percent joint partner in El Dorado Energy, a 500-megawatt power plant that was completed and began operations in May 2000. In addition, SER is constructing three power plants aggregating about 2,400 megawatts, which are expected to come on line in 2003. SER's share of these plants will be 2,100 megawatts. The company is in the permitting phase of four additional projects, also aggregating about 2,400 megawatts.
See additional discussion of these projects in "Investments," above and in Notes 3 and 13 of the notes to Consolidated Financial Statements.
Investments
As discussed in "CASH FLOWS USED IN INVESTING ACTIVITIES" above, the company has various investments and projects that will impact the company's future performance. These include, among other things, SEI's investments in the two Argentine natural gas utility holding companies, Energia, Luz, the natural gas pipelines in Baja California, and several natural gas distribution systems in Mexico; the recent purchase of Enron Metals Limited; and the investment in Atlantic Electric and Gas in the United Kingdom. See additional discussion of these investments and projects in Notes 3 and 13 of the notes to Consolidated Financial Statements. The devaluation of the Argentine peso, which is noted above and further described in Note 3 of the notes to Consolidated Financial Statements, is expected to have an adverse affect on future earnings of the Argentine operations, but the extent of the effect is not yet determinable.
Allowed Rate of Return
SoCalGas is authorized to earn a rate of return on rate base (ROR) of 9.49 percent and a rate of return on common equity (ROE) of 11.6 percent, the same as in 2001 and 2000. These rates will continue to be effective until the next periodic review by the CPUC unless interest-rate changes are large enough to trigger an automatic adjustment prior thereto. SDG&E is authorized to earn an 8.75 percent ROR and a 10.6 percent ROE, effective July 1, 1999, and remaining in effect through 2002. SDG&E is required to file an application by May 8, 2002, addressing ROE, ROR and capital structure for 2003. Either utility can earn more than the authorized rate by controlling costs below approved levels or by achieving favorable results in certain areas, such as various incentive mechanisms. In addition, earnings are affected by changes in sales volumes, except for the majority of SoCalGas' core sales.
Utility Integration
On September 20, 2001, the CPUC approved Sempra Energy's request to integrate the management teams of the California utilities. The decision retains the separate identities of each utility and is not a merger. Instead, utility integration is a reorganization that consolidates senior management functions of the two utilities and returns to the utilities a significant portion of shared support services currently provided by Sempra Energy's centralized corporate center. Once implementation is completed, the integration is expected to result in more efficient and effective operations.
In a related development, a CPUC draft decision would allow the California utilities to combine their natural gas procurement activities. The CPUC is scheduled to act on the draft decision at its April 4, 2002 meeting.
ENVIRONMENTAL MATTERS
The company's operations are subject to federal, state and local environmental laws and regulations governing such things as hazardous wastes, air and water quality, land use, solid-waste disposal, and the protection of wildlife.
Most of the environmental issues faced by the company occur at the California utilities. Utility costs to comply with environmental requirements are generally recovered in customer rates. Therefore, the likelihood of the company's financial position or results of operations being adversely affected in a significant manner is believed to be remote.
The environmental issues currently facing the company or resolved during the latest three-year period include investigation and remediation of the California utilities' manufactured-gas sites, cleanup at SDG&E's former fossil fuel power plants, cleanup of third-party waste-disposal sites used by the company, and mitigation of damage to the marine environment caused by the cooling-water discharge from SONGS.
See further discussion of environmental matters in Note 13 of the notes to Consolidated Financial Statements.
MARKET RISK
Market risk is the risk of erosion of the company's cash flows, net income, asset values and equity due to adverse changes in prices for various commodities, and in interest and foreign-currency rates.
The company's policy is to use derivative financial instruments to reduce its exposure to fluctuations in interest rates, foreign-currency exchange rates and commodity prices. The company also uses and trades derivative financial instruments in its energy trading and marketing activities. Transactions involving these financial instruments are with firms believed to be credit worthy and major exchanges. The use of these instruments exposes the company to market and credit risks which, at times, may be concentrated with certain counterparties. Except for the ISO receivable referred to below, there were no unusual concentrations at December 31, 2001, that would indicate an unacceptable level of risk.
SET derives a substantial portion of its revenue from trading activities in natural gas, electricity, petroleum, petroleum products and other commodities. Profits are earned as SET acts as a dealer in structuring and executing transactions that assist its customers in managing their energy-price risk. In addition, SET may, on a limited basis, take positions in commodity markets based on the expectation of future market conditions. These positions include options, forwards, futures and swaps.
SES derives a portion of its revenue from delivering electric and gas supplies to its commercial and industrial customers. Such contracts are hedged to preserve margin and carry minimal market risk. Exchange-traded and over-the-counter instruments are used to hedge contracts.
The California utilities use energy derivatives to manage natural gas price risk associated with servicing their load requirements. In addition, they make limited use of natural gas derivatives for trading purposes. These instruments can include forward contracts, futures, swaps, options and other contracts. In the case of both price-risk management and trading activities, the use of derivative financial instruments by the California utilities is subject to certain limitations imposed by company policy and regulatory requirements. See the continuing discussion below and Note 10 of the notes to Consolidated Financial Statements for further information regarding the use of energy derivatives by the California utilities.
The company has adopted corporate-wide policies governing its market-risk management and trading activities. An Energy Risk Management Oversight Committee, consisting of senior officers, oversees company-wide energy risk management activities and monitors the results of trading activities to ensure compliance with the company's stated energy-risk management and trading policies. In addition, all affiliates have groups that monitor energy-price risk management and trading activities independently from the groups responsible for creating or actively managing these risks.
Along with other tools, the company uses Value at Risk (VaR) to measure its exposure to market risk. VaR is an estimate of the potential loss on a position or portfolio of positions over a specified holding period, based on normal market conditions and within a given statistical confidence interval. The company has adopted the variance/covariance methodology in its calculation of VaR, and uses both the 95-percent and 99-percent confidence interval. A one-day holding period is used for SET. Historical volatilities and correlations between instruments and positions are used in the calculation. Following is a summary of the company's trading VaR profile in millions of dollars:
|
95% |
99% |
|
|
SET at December 31, 2001 |
$6.9 |
$ 9.7 |
|
SET 2001 average |
6.1 |
8.6 |
|
SET at December 31, 2000 |
7.2 |
10.2 |
|
SET 2000 average |
6.2 |
8.8 |
The following discussion of the company's primary market-risk exposures as of December 31, 2001, includes a discussion of how these exposures are managed.
Commodity-Price Risk
Market risk related to physical commodities is based upon potential fluctuations in the prices and basis of certain commodities. The company's market risk is impacted by changes in volatility and liquidity in the markets in which these commodities or related financial instruments are traded. The company's regulated and unregulated affiliates are exposed, in varying degrees, to price risk primarily in the natural gas, petroleum and electricity markets. The company's policy is to manage this risk within a framework that considers the unique markets, and operating and regulatory environments of each affiliate.
Sempra Energy Trading
Because SET derives a substantial portion of its revenue from trading activities in natural gas, petroleum and electricity, it is exposed to price volatility in the domestic and international natural gas, petroleum and electricity markets. SET conducts these activities within a structured and disciplined risk management and control framework that is based on clearly communicated policies and procedures, position limits, active and ongoing management monitoring and oversight, clearly defined roles and responsibilities, and daily risk measurement and reporting.
California Utilities
With respect to the California utilities, market risk exposure is limited due to CPUC authorized rate recovery of commodity purchase, sale and storage activity. However, the California utilities may, at times, be exposed to market risk as a result of activities under SDG&E's gas PBR or SoCalGas' Gas Cost Incentive Mechanism, which are discussed in Note 15 of the notes to Consolidated Financial Statements. They manage their risk within the parameters of the company's market-risk management and trading framework. As of December 31, 2001, the total VaR of the California utilities' natural gas positions was not material.
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 debt issues with fixed interest rates and these interest rates are recovered in utility rates. With the restructuring of the regulatory process, the CPUC has permitted greater flexibility 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 have used a combination of fixed-rate and floating-rate debt. Subject to regulatory constraints, interest-rate swaps may be used to adjust interest-rate exposures when appropriate, based upon market conditions.
At December 31, 2001, the California utilities had $1.7 billion of fixed-rate debt and $0.3 billion of variable-rate debt. Interest on fixed-rate utility debt is fully recovered in rates on a historical cost basis and interest on variable-rate debt is provided for in rates on a forecasted basis. At December 31, 2001, utility fixed-rate debt had a one-year VaR of $394 million and utility variable-rate debt had a one-year VaR of $37 million. Non-utility debt (fixed-rate and variable-rate) was $1.6 billion at December 31, 2001, with a one-year VaR of $150 million.
At December 31, 2001, the notional amount of interest-rate swap transactions totaled $720 million. See Notes 5 and 10 of the notes to Consolidated Financial Statements for further information regarding these swap transactions.
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 prospective counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances, and the use of standardized agreements that allow for the netting of positive and negative exposures associated with a single counterparty. At December 31, 2001, SET was due approximately $100 million from the ISO for which the company believes adequate reserves have been recorded.
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.
The company periodically enters into interest-rate swap agreements to moderate exposure to interest-rate changes and to lower the overall cost of borrowing. The company would be exposed to interest-rate fluctuations on the underlying debt should other parties to the agreement not perform. See the "Interest-Rate Risk" section above for additional information regarding the company's use of interest-rate swap agreements.
Foreign-Currency-Rate Risk
Foreign-currency-rate risk exists by the nature of the company's global operations. The company has investments in entities whose functional currency is not the U.S. dollar, which exposes the company to foreign exchange movements, primarily in Latin American currencies. As a result of the devaluation of the Argentine peso, in December 2001 SEI adjusted its investment in two unconsolidated Argentine subsidiaries downward by $155 million, which is included in "other comprehensive income (loss)." As the Argentine peso has been significantly devalued and will float freely in the foreign exchange market, the company recognizes that both income and cash flows associated with the investments are likely to be reduced; however, the company believes that they will remain sufficiently positive to support the carrying values of the investments. The company does not anticipate adverse developments that would change this view.
In appropriate instances, the company may attempt to limit its exposure to changing foreign-exchange rates through both operational and financial market actions. Financial actions may include entering into forward, option and swap contracts to hedge existing exposures, firm commitments and anticipated transactions. As of December 31, 2001, the company had not entered into any such arrangements.
CRITICAL ACCOUNTING POLICIES
The company's most significant accounting policies are described in Note 2 of the notes to Consolidated Financial Statements. The most critical policies are Statement of Financial Accounting Standards (SFAS) 71 "Accounting for the Effects of Certain Types of Regulation," SFAS 133 and SFAS 138 "Accounting for Derivative Instruments and Hedging Activities" and "Accounting for Certain Derivative Instruments and Certain Hedging Activities," (see below) and Issue No. 98-10 of the Emerging Issues Task Force of the Financial Accounting Standards Board "Accounting for Contracts Involved in Energy Trading and Risk Management Activities." All of these policies are mandatory under generally accepted accounting principles and the regulations of the Securities and Exchange Commission. Each of these policies has a material effect on the timing of revenue and expense recognition for significant company operations.
In connection with the application of these and other accounting policies, the company makes estimates and judgments about various matters. The most significant of these involve the calculation of fair values, and the collectibility of regulatory and other assets. As discussed elsewhere herein, the company uses exchange quotations or other third-party pricing to estimate fair values whenever possible. When no such data is available, it uses internally developed models or other techniques. The assumed collectibility of regulatory assets considers legal and regulatory decisions involving the specific items or similar items. The assumed collectibility of other assets considers the nature of the item, the enforceability of contracts where applicable, the creditworthiness of other parties and other factors.
NEW ACCOUNTING STANDARDS
Effective January 1, 2001, the company adopted SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities." As amended, SFAS 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value and recognize changes in the fair value of derivatives in earnings in the period of change unless the derivative qualifies as an effective hedge that offsets certain exposure.
The company utilizes derivative financial instruments to reduce its exposure to unfavorable changes in energy prices, which are subject to significant and often volatile fluctuation. Derivative financial instruments are comprised of futures, forwards, swaps, options and long-term delivery contracts. These contracts allow the company to predict with greater certainty the effective prices to be received and, in the case of the California utilities, the prices to be charged to their customers.
Upon adoption of SFAS 133 on January 1, 2001, the company is classifying its forward contracts as follows:
Normal Purchase and Sales: These forward contracts are excluded from the requirements of SFAS No. 133. The realized gains and losses on these contracts are reflected in the income statement at the contract settlement date. The contracts that generally qualify as normal purchases and sales are long-term contracts that are settled by physical delivery.
Cash Flow Hedges: The unrealized gains and losses related to these forward contracts are included in accumulated other comprehensive income, a component of shareholders' equity, and reflected in the Statements of Consolidated Income when the corresponding hedged transaction is settled.
Electric and Gas Purchases and Sales: The unrealized gains and losses related to these forward contracts, as they relate to the California utilities, are reflected on the balance sheet as regulatory assets and liabilities, to the extent derivative gains and losses will be recoverable or payable in future rates.
If gains and losses at the California utilities are not recoverable or payable through future rates, the California utilities will apply hedge accounting if certain criteria are met.
In instances where hedge accounting is applied to energy derivatives, cash flow hedge accounting is elected and, accordingly, changes in fair values of the derivatives are included in other comprehensive income and reflected in the Statements of Consolidated Income when the corresponding hedged transaction is settled. The effect on other comprehensive income for the year ended December 31, 2001 was not material. In instances where energy derivatives do not qualify for hedge accounting, gains and losses are recorded in the Statements of Consolidated Income.
The adoption of this new standard on January 1, 2001 did not have a material impact on the company's earnings. However, $1.1 billion in current assets, $1.1 billion in noncurrent assets, $6 million in current liabilities, and $238 million in noncurrent liabilities were recorded in the Consolidated Balance Sheets as fixed-priced contracts and other derivatives as of January 1, 2001. Due to the regulatory environment in which the California utilities operate, regulatory assets and liabilities were established to the extent that derivative gains and losses are recoverable or payable through future rates. As such, $1.1 billion in current regulatory liabilities, $1.1 billion in noncurrent regulatory liabilities, $5 million in current regulatory assets, and $238 million in noncurrent regulatory assets were recorded in the Consolidated Balance Sheets as of January 1, 2001. See Note 10 of the notes to Consolidated Financial Statements for additional information on the effects of SFAS 133 on the financial stateme nts at December 31, 2001. The ongoing effects will depend on future market conditions and the company's hedging activities.
In July 2001, the Financial Accounting Standards Board (FASB) issued three statements, SFAS 141 "Business Combinations," SFAS 142 "Goodwill and Other Intangible Assets" and SFAS 143 "Accounting for Asset Retirement Obligations."
SFAS 141 requires the use of the purchase method of accounting for all business combinations initiated after June 30, 2001. The pooling-of-interest method is eliminated. It also specifies the types of acquired intangible assets that are required to be recognized and reported separately from goodwill.
SFAS 142 provides guidance on how to account for goodwill and other intangible assets after an acquisition is complete, and is effective for fiscal years that start after December 15, 2001. SFAS 142 calls for amortization of goodwill to cease and requires goodwill and certain other intangibles to be tested for impairment at least annually. Amortization of goodwill, including the company's share of amounts recorded by unconsolidated subsidiaries, was $24 million, $35 million and $32 million in 2001, 2000 and 1999, respectively. The company does not expect a material impact on its earnings resulting from any impairment of goodwill.
SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation of a long-lived asset, such as nuclear plants. It requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its present value and paid, and the capitalized cost is depreciated over the useful life of the related asset. SFAS 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002.
Upon adoption of SFAS 143, the company estimates it would record an addition of $468 million to utility plant representing the company's share of the SONGS estimated future decommissioning costs, and a corresponding retirement obligation liability of $468 million. The nuclear decommissioning trusts balance of $526 million at December 31, 2001 represents amounts collected for future decommissioning costs and has a corresponding offset in accumulated depreciation. Any difference between the amount of capitalized cost that would have been recorded and depreciated and the amounts collected in the nuclear decommissioning trusts will be recorded as a regulatory asset or liability. Additional information on SONGS decommissioning is included in Note 6 of the notes to Consolidated Financial Statements. Except for SONGS, the company has not yet determined the effect of SFAS 143 on its financial statements.
In August 2001, the FASB issued SFAS 144 "Accounting for the Impairment or Disposal of Long-Lived Assets" that replaces SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." SFAS 144 applies to all long-lived assets, including discontinued operations. SFAS 144 requires that those long-lived assets classified as held for sale be measured at the lower of carrying amount or fair value less cost to sell. Discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. SFAS 144 also broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The provisions of SFAS 144 are effective for fiscal years beginning after December 15, 2001. The company has not yet determined the effect of SFAS 144 on its financial statements.
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report contains statements that are not historical fact and constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The words "estimates," "believes," "expects," "anticipates," "plans," "intends," "may," "would" and "should" or similar expressions, or discussions of strategy or of plans are intended to identify forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future results may differ materially from those expressed in these forward-looking statements.
Forward-looking statements are necessarily based upon various assumptions involving judgments with respect to the future and other risks, including, among others, local, regional, national and international economic, competitive, political, legislative and regulatory conditions and developments; actions by the CPUC, the California Legislature, the DWR, and the FERC; the financial condition of other investor-owned utilities; capital market conditions, inflation rates, interest rates and exchange rates; energy and trading markets, including the timing and extent of changes in commodity prices; weather conditions and conservation efforts; business, regulatory and legal decisions; the pace of deregulation of retail natural gas and electricity delivery; the timing and success of business development efforts; and other uncertainties, all of which are difficult to predict and many of which are beyond the control of the company. Readers are cautioned not to rely unduly on any forward-looking statements and are u rged to review and consider carefully the risks, uncertainties and other factors which affect the company's business described in this annual report and other reports filed by the company from time to time with the Securities and Exchange Commission.
FIVE YEAR SUMMARY
At December 31 or for the
Years Ended December 31
|
(Dollars in millions except per-share amounts) |
|
2001 |
|
2000 |
|
1999 |
|
1998 |
|
1997 |
||||||
|
OPERATING REVENUES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
California utilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas |
|
$ |
4,371 |
|
$ |
3,305 |
|
$ |
2,911 |
|
$ |
2,752 |
|
$ |
2,964 |
|
|
Electric |
|
|
1,627 |
|
|
2,184 |
|
|
1,818 |
|
|
1,865 |
|
|
1,769 |
|
|
Other |
|
|
2,031 |
|
|
1,548 |
|
|
631 |
|
|
364 |
|
|
336 |
|
|
Total |
|
$ |
8,029 |
|
$ |
7,037 |
|
$ |
5,360 |
|
$ |
4,981 |
|
$ |
5,069 |
|
|
Operating income |
|
$ |
993 |
|
$ |
884 |
|
$ |
763 |
|
$ |
626 |
|
$ |
906 |
|
|
Net income |
|
$ |
518 |
|
$ |
429 |
|
$ |
394 |
|
$ |
294 |
|
$ |
432 |
|
|
Net income per common share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
2.54 |
|
$ |
2.06 |
|
$ |
1.66 |
|
$ |
1.24 |
|
$ |
1.83 |
|
|
Diluted |
|
$ |
2.52 |
|
$ |
2.06 |
|
$ |
1.66 |
|
$ |
1.24 |
|
$ |
1.82 |
|
|
Dividends declared per common share |
|
$ |
1.00 |
|
$ |
1.00 |
|
$ |
1.56 |
|
$ |
1.56 |
|
$ |
1.27 |
|
|
Pretax income/revenue |
|
|
9.1% |
|
|
9.9% |
|
|
10.7% |
|
|
8.7% |
|
|
14.5% |
|
|
Return on common equity |
|
|
19.5% |
|
|
15.7% |
|
|
13.4% |
|
|
10.0% |
|
|
14.7% |
|
|
Effective income tax rate |
|
|
29.1% |
|
|
38.6% |
|
|
31.2% |
|
|
31.9% |
|
|
41.1% |
|
|
Dividend payout ratio: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
39.4% |
|
|
48.5% |
|
|
94.0% |
|
|
125.8% |
|
|
69.4% |
|
|
Diluted |
|
|
39.7% |
|
|
48.5% |
|
|
94.0% |
|
|
125.8% |
|
|
69.8% |
|
|
Price range of common shares |
|
$ |
28.61-17.31 |
|
$ |
24.88-16.19 |
|
$ |
26.00-17.13 |
|
$ |
29.31-23.75 |
|
|
* |
|
|
AT DECEMBER 31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
$ |
4,808 |
|
$ |
6,525 |
|
$ |
3,015 |
|
$ |
2,458 |
|
$ |
2,761 |
|
|
Total assets |
|
$ |
15,156 |
|
$ |
15,540 |
|
$ |
11,124 |
|
$ |
10,456 |
|
$ |
10,756 |
|
|
Current liabilities |
|
$ |
5,524 |
|
$ |
7,490 |
|
$ |
3,236 |
|
$ |
2,466 |
|
$ |
2,211 |
|
|
Long-term debt (excludes current portion) |
|
$ |
3,436 |
|
$ |
3,268 |
|
$ |
2,902 |
|
$ |
2,795 |
|
$ |
3,175 |
|
|
Shareholders' equity |
|
$ |
2,692 |
|
$ |
2,494 |
|
$ |
2,986 |
|
$ |
2,913 |
|
$ |
2,959 |
|
|
Common shares outstanding (in millions) |
|
|
204.5 |
|
|
201.9 |
|
|
237.4 |
|
|
237.0 |
|
|
235.6 |
|
|
Book value per common share |
|
$ |
13.16 |
|
$ |
12.35 |
|
$ |
12.58 |
|
$ |
12.29 |
|
$ |
12.56 |
|
|
Price/earnings ratio |
|
|
9.7 |
|
|
11.3 |
|
|
10.5 |
|
|
20.5 |
|
|
* |
|
|
Number of meters (in thousands): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas |
|
|
5,878 |
|
|
5,807 |
|
|
5,726 |
|
|
5,639 |
|
|
5,551 |
|
|
Electricity |
|
|
1,258 |
|
|
1,238 |
|
|
1,218 |
|
|
1,192 |
|
|
1,178 |
|
|
* |
|
Not presented as the formation of Sempra Energy was not completed until June 26, 1998 |
Statement of Management's Responsibility
for Consolidated Financial Statements
The consolidated financial statements have been prepared by management in accordance with generally accepted accounting principles. The integrity and objectivity of these financial statements and the other financial information in the Financial Report, including the estimates and judgments on which they are based, are the responsibility of management. The financial statements have been audited by Deloitte & Touche LLP, independent auditors appointed by the board of directors. Their report is shown on the next page. Management has made available to Deloitte & Touche LLP all of the company's financial records and related data, as well as the minutes of shareholders' and directors' meetings.
Management maintains a system of internal control which it believes is adequate to provide reasonable, but not absolute, assurance that assets are properly safeguarded, that transactions are executed in accordance with management's authorization and are properly recorded and that the accounting records may be relied on for the preparation of the consolidated financial statements, and for the prevention and detection of fraudulent financial reporting. The concept of reasonable assurance recognizes that the cost of a system of internal control should not exceed the benefits derived and that management makes estimates and judgments of these cost/benefit factors.
Management monitors the system of internal control for compliance through its own review and an internal auditing program, which independently assesses the effectiveness of the internal controls. The company's independent auditors also consider certain elements of internal controls in order to determine their audit procedures for the purpose of expressing an opinion on the company's financial statements. Management considers the recommendations of the internal auditors and independent auditors concerning the company's system of internal controls and takes appropriate actions. Management believes that the company's system of internal control is adequate to provide reasonable assurance that the accompanying financial statements present fairly the company's financial position and results of operations.
Management also recognizes its responsibility for fostering a strong ethical climate so that the company's affairs are conducted according to the highest standards of personal and corporate conduct. This responsibility is characterized and reflected in the company's code of corporate conduct, which is publicized throughout the company. The company maintains a systematic program to assess compliance with this policy.
The board of directors has an audit committee, composed of independent directors, to assist in fulfilling its oversight responsibilities for management's conduct of the company's financial reporting processes. The audit committee meets regularly to discuss financial reporting, internal controls and auditing matters with management, the company's internal auditors and independent auditors, and recommends to the board of directors any appropriate response to those discussions. The audit committee recommends for approval by the full board the appointment of the independent auditors. The independent auditors and the internal auditors periodically meet alone with the audit committee and have free access to the audit committee at any time.
|
/S/ NEAL E. SCHMALE |
/S/ FRANK H. AULT |
|
Neal E. Schmale |
Frank H. Ault |
|
Executive Vice President and |
Senior Vice President and Controller |
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders of Sempra Energy:
We have audited the accompanying consolidated balance sheets of Sempra Energy and subsidiaries (the "company") as of December 31, 2001 and 2000, and the related statements of consolidated income, cash flows and changes in shareholders' equity for each of the three years in the period ended December 31, 2001. 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 auditing standards generally accepted in the United States of America. 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.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Sempra Energy and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001, in conformity with accounting principles generally accepted in the United States of America.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
February 4, 2002 (February 21, 2002 as to Note 14 and March 5, 2002 as to Note 15)
SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED INCOME
|
|
|
Years Ended December 31, |
|
|||||||||||
|
(Dollars in millions, except per share amounts) |
|
2001 |
|
|
2000 |
|
|
1999 |
|
|||||
|
OPERATING REVENUES |
|
|
|
|
|
|
|
|
|
|
|
|
||
|
California utilities: |
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Natural gas |
|
$ |
4,371 |
|
|
$ |
3,305 |
|
|
$ |
2,911 |
|
||
|
Electric |
|
|
1,627 |
|
|
|
2,184 |
|
|
|
1,818 |
|
||
|
Other |
|
|
2,031 |
|
|
|
1,548 |
|
|
|
631 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Total |
|
|
8,029 |
|
|
|
7,037 |
|
|
|
5,360 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
OPERATING EXPENSES |
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Cost of natural gas distributed |
|
|
2,549 |
|
|
|
1,599 |
|
|
|
1,164 |
|
||
|
Electric fuel and net purchased power |
|
|
733 |
|
|
|
1,326 |
|
|
|
536 |
|
||
|
Other operating expenses |
|
|
2,985 |
|
|
|
2,485 |
|
|
|
1,837 |
|
||
|
Depreciation and amortization |
|
|
579 |
|
|
|
563 |
|
|
|
879 |
|
||
|
Franchise payments and other taxes |
|
|
190 |
|
|
|
180 |
|
|
|
181 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Total |
|
|
7,036 |
|
|
|
6,153 |
|
|
|
4,597 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Operating income |
|
|
993 |
|
|
|
884 |
|
|
|
763 |
|
||
|
Other income -- net |
|
|
90 |
|
|
|
127 |
|
|
|
50 |
|
||
|
Preferred dividends of subsidiaries |
|
|
(11 |
) |
|
|
(11 |
) |
|
|
(11 |
) |
||
|
Trust preferred distributions by subsidiary |
|
|
(18 |
) |
|
|
(15 |
) |
|
|
-- |
|
||
|
Interest expense |
|
|
(323 |
) |
|
|
(286 |
) |
|
|
(229 |
) |
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Income before income taxes |
|
|
731 |
|
|
|
699 |
|
|
|
573 |
|
||
|
Income taxes |
|
|
213 |
|
|
|
270 |
|
|
|
179 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Net income |
|
$ |
518 |
|
|
$ |
429 |
|
|
$ |
394 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Weighted-average number of shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Basic* |
|
|
203,593 |
|
|
|
208,155 |
|
|
|
237,245 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Diluted* |
|
|
205,338 |
|
|
|
208,345 |
|
|
|
237,553 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Net income per share of common stock (basic) |
|
$ |
2.54 |
|
|
$ |
2.06 |
|
|
$ |
1.66 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Net income per share of common stock (diluted) |
|
$ |
2.52 |
|
|
$ |
2.06 |
|
|
$ |
1.66 |
|
||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
|
Common dividends declared per share |
|
$ |
1.00 |
|
|
$ |
1.00 |
|
|
$ |
1.56 |
|
||
|
* |
|
In thousands of shares |
See notes to Consolidated Financial Statements.
SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
|
|
|
December 31, |
|
||||||
|
(Dollars in millions) |
|
2001 |
|
|
2000 |
|
|||
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
605 |
|
|
$ |
637 |
|
|
|
Accounts receivable -- trade |
|
|
660 |
|
|
|
994 |
|
|
|
Accounts and notes receivable -- other |
|
|
130 |
|
|
|
213 |
|
|
|
Due from unconsolidated affiliates |
|
|
57 |
|
|
|
-- |
|
|
|
Income taxes receivable |
|
|
98 |
|
|
|
24 |
|
|
|
Energy trading assets |
|
|
2,575 |
|
|
|
4,083 |
|
|
|
Fixed-price contracts and other derivatives |
|
|
57 |
|
|
|
-- |
|
|
|
Regulatory assets arising from fixed-price contracts and other derivatives |
|
|
193 |
|
|
|
-- |
|
|
|
Other regulatory assets |
|
|
73 |
|
|
|
100 |
|
|
|
Inventories |
|
|
289 |
|
|
|
342 |
|
|
|
Other |
|
|
71 |
|
|
|
132 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
4,808 |
|
|
|
6,525 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments and other assets: |
|
|
|
|
|
|
|
|
|
|
Fixed-price contracts and other derivatives |
|
|
27 |
|
|
|
-- |
|
|
|
Regulatory assets arising from fixed-price contracts and other derivatives |
|
|
830 |
|
|
|
-- |
|
|
|
Other regulatory assets |
|
|
1,005 |
|
|
|
1,001 |
|
|
|
Nuclear-decommissioning trusts |
|
|
526 |
|
|
|
543 |
|
|
|
Investments |
|
|
1,169 |
|
|
|
1,288 |
|
|
|
Sundry |
|
|
574 |
|
|
|
457 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total investments and other assets |
|
|
4,131 |
|
|
|
3,289 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment: |
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
|
12,806 |
|
|
|
11,889 |
|
|
|
Less accumulated depreciation and amortization |
|
|
(6,589 |
) |
|
|
(6,163 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total property, plant and equipment -- net |
|
|
6,217 |
|
|
|
5,726 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
15,156 |
|
|
$ |
15,540 |
|
|
SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
|
|
|
December 31, |
|
|||||||
|
(Dollars in millions) |
|
2001 |
|
|
2000 |
|
||||
|
LIABILITIES AND SHAREHOLDERS' EQUITY |
|
|
|
|
|
|
|
|
||
|
Current liabilities: |
|
|
|
|
|
|
|
|
||
|
Short-term debt |
|
$ |
875 |
|
|
$ |
568 |
|
||
|
Accounts payable -- trade |
|
|
702 |
|
|
|
1,162 |
|
||
|
Accounts payable -- other |
|
|
114 |
|
|
|
117 |
|
||
|
Deferred income taxes |
|
|
70 |
|
|
|
110 |
|
||
|
Energy trading liabilities |
|
|
1,793 |
|
|
|
3,619 |
|
||
|
Dividends and interest payable |
|
|
139 |
|
|
|
124 |
|
||
|
Regulatory balancing accounts - net |
|
|
660 |
|
|
|
832 |
|
||
|
Regulatory liabilities |
|
|
19 |
|
|
|
-- |
|
||
|
Fixed-price contracts and other derivatives |
|
|
195 |
|
|
|
-- |
|
||
|
Current portion of long-term debt |
|
|
242 |
|
|
|
368 |
|
||
|
Other |
|
|
715 |
|
|
|
590 |
|
||
|
|
|
|
|
|
|
|
|
|
||
|
Total current liabilities |
|
|
5,524 |
|
|
|
7,490 |
|
||
|
|
|
|
|
|
|
|
|
|
||
|
Long-term debt |
|
|
3,436 |
|
|
|
3,268 |
|
||
|
|
|
|
|
|
|
|
|
|
||
|
Deferred credits and other liabilities: |
|
|
|
|
|
|
|
|
||
|
Due to unconsolidated affiliate |
|
|
160 |
|
|
|
-- |
|
||
|
Customer advances for construction |
|
|
67 |
|
|
|
56 |
|
||
|
Post-retirement benefits other than pensions |
|
|
145 |
|
|
|
152 |
|
||
|
Deferred income taxes |
|
|
847 |
|
|
|
752 |
|
||
|
Deferred investment tax credits |
|
|
95 |
|
|
|
101 |
|
||
|
Fixed-price contracts and other derivatives |
|
|
835 |
|
|
|
-- |
|
||
|
Regulatory liabilities |
|
|
86 |
|
|
|
-- |
|
||
|
Deferred credits and other liabilities |
|
|
865 |
|
|
|
823 |
|
||
|
|
|
|
|
|
|
|
|
|
||
|
Total deferred credits and other liabilities |
|
|
3,100 |
|
|
|
1,884 |
|
||
|
|
|
|
|
|
|
|
|
|
||
|
Preferred stock of subsidiaries |
|
|
204 |
|
|
|
204 |
|
||
|
|
|
|
|
|
|
|
|
|
||
|
Mandatorily redeemable trust preferred securities |
|
|
200 |
|
|
|
200 |
|
||
|
|
|
|
|
|
|
|
|
|
||
|
Commitments and contingent liabilities (Note 13) |
|
|
|
|
|
|
|
|
||
|
SHAREHOLDERS' EQUITY |
|
|
|
|
|
|
|
|
||
|
Common stock (204,475,362 and 201,927,524 shares outstanding at December 31, 2001 and 2000, respectively) |
|
|
1,495 |
|
|
|
1,420 |
|
||
|
Retained earnings |
|
|
1,475 |
|
|
|
1,162 |
|
||
|
Deferred compensation relating to ESOP |
|
|
(36 |
) |
|
|
(39 |
) |
||
|
Accumulated other comprehensive income (loss) |
|
|
(242 |
) |
|
|
(49 |
) |
||
|
|
|
|
|
|
|
|
|
|
||
|
Total shareholders' equity |
|
|
2,692 |
|
|
|
2,494 |
|
||
|
|
|
|
|
|
|
|
|
|
||
|
Total liabilities and shareholders' equity |
|
$ |
15,156 |
|
|
$ |
15,540 |
|
||
See notes to Consolidated Financial Statements.
SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED CASH FLOWS
|
|
|
Years Ended December 31 |
|
|||||||||||||||||||||||||||||||||||||||||||
|
(Dollars in millions) |
|
2001 |
|
|
2000 |
|
|
1999 |
|
|||||||||||||||||||||||||||||||||||||
|
CASH FLOWS FROM OPERATING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||
|
Net Income |
|
$ |
518 |
|
|
$ |
429 |
|
|
$ |
394 |
|
||||||||||||||||||||||||||||||||||
|
Adjustments to reconcile net income to net cash provided provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||
|
Depreciation and amortization |
|
|
579 |
|
|
|
563 |
|
|
|
879 |
|
||||||||||||||||||||||||||||||||||
|
Customer refunds paid |
|
|
(127 |
) |
|
|
(628 |
) |
|
|
-- |
|
||||||||||||||||||||||||||||||||||
|
Portion of depreciation arising from sales of generating plants |
|
|
-- |
|
|
|
-- |
|
|
|
(303 |
) |
||||||||||||||||||||||||||||||||||
|
Application of balancing accounts to stranded costs |
|
|
-- |
|
|
|
-- |
|
|
|
(66 |
) |
||||||||||||||||||||||||||||||||||
|
Deferred income taxes and investment tax credits |
|
|
106 |
|
|
|
258 |
|
|
|
86 |
|
||||||||||||||||||||||||||||||||||
|
Equity in (income) losses of unconsolidated affiliates |
|
|
(12 |
) |
|
|
(62 |
) |
|
|
5 |
|
||||||||||||||||||||||||||||||||||
|
Gain on sale of Energy America |
|
|
(29 |
) |
|
|
-- |
|
|
|
-- |
|
||||||||||||||||||||||||||||||||||
|
Loss from surrender of Nova Scotia franchise |
|
|
30 |
|
|
|
-- |
|
|
|
-- |
|
||||||||||||||||||||||||||||||||||
|
Gain on sale of assets |
|
|
(14 |
) |
|
|
-- |
|
|
|
-- |
|
||||||||||||||||||||||||||||||||||
|
Changes in other assets |
|
|
(214 |
) |
|
|
22 |
|
|
|
(56 |
) |
||||||||||||||||||||||||||||||||||
|
Changes in other liabilities |
|
|
98 |
|
|
|
(108 |
) |
|
|
(3 |
) |
||||||||||||||||||||||||||||||||||
|
Net changes in other working capital components |
|
|
(203 |
) |
|
|
408 |
|
|
|
252 |
|
||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||
|
Net cash provided by operating activities |
|
|
732 |
|
|
|
882 |
|
|
|
1,188 |
|
||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||
|
CASH FLOWS FROM INVESTING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||
|
Expenditures for property, plant and equipment |
|
|
(1,068 |
) |
|
|
(759 |
) |
|
|
(589 |
) |
||||||||||||||||||||||||||||||||||
|
Investments and acquisitions of unconsolidated affiliates |
|
|
(111 |
) |
|
|
(243 |
) |
|
|
(639 |
) |
||||||||||||||||||||||||||||||||||
|
Dividends received from unconsolidated affiliates |
|
|
80 |
|
|
|
30 |
|
|
|
-- |
|
||||||||||||||||||||||||||||||||||
|
Net proceeds from sales of assets |
|
|
128 |
|
|
|
24 |
|
|
|
466 |
|
||||||||||||||||||||||||||||||||||
|
Loan to affiliate |
|
|
(57 |
) |
|
|
-- |
|
|
|
-- |
|
||||||||||||||||||||||||||||||||||
|
Other |
|
|
(11 |
) |
|
|
24 |
|
|
|
(27 |
) |
||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||
|
Net cash used in investing activities |
|
|
(1,039 |
) |
|
|
(924 |
) |
|
|
(789 |
) |
||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||
|
CASH FLOWS FROM FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||
|
Common stock dividends |
|
|
(203 |
) |
|
|
(244 |
) |
|
|
(368 |
) |
||||||||||||||||||||||||||||||||||
|
Repurchase of common stock |
|
|
(1 |
) |
|
|
(725 |
) |
|
|
-- |
|
||||||||||||||||||||||||||||||||||
|
Issuances of common stock |
|
|
41 |
|
|
|
12 |
|
|
|
3 |
|
||||||||||||||||||||||||||||||||||
|
Issuance of trust preferred securities |
|
|
-- |
|
|
|
200 |
|
|
|
-- |
|
||||||||||||||||||||||||||||||||||
|
Issuances of long-term debt |
|
|
675 |
|
|
|
813 |
|
|
|
160 |
|
||||||||||||||||||||||||||||||||||
|
Payments on long-term debt |
|
|
(681 |
) |
|
|
(238 |
) |
|
|
(270 |
) |
||||||||||||||||||||||||||||||||||
|
Loan from affiliate |
|
|
160 |
|
|
|
-- |
|
|
|
-- |
|
||||||||||||||||||||||||||||||||||
|
Increase in short-term debt -- net |
|
|
310 |
|
|
|
386 |
|
|
|
139 |
|
||||||||||||||||||||||||||||||||||
|
Other |
|
|
(26 |
) |
|
|
(12 |
) |
|
|
-- |
|
||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||
|
Net cash provided by (used in) financing activities |
|
|
275 |
|
|
|
192 |
|
|
|
(336 |
) |
||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||
|
Increase (decrease) in cash and cash equivalents |
|
|
(32 |
) |
|
|
150 |
|
|
|
63 |
|
||||||||||||||||||||||||||||||||||
|
Cash and cash equivalents, January 1 |
|
|
637 |
|
|
|
487 |
|
|
|
424 |
|
||||||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||||||
|
Cash and cash equivalents, December 31 |
|
$ |
605 |
|
|
$ |
637 |
|
|
$ |
487 |
|
||||||||||||||||||||||||||||||||||
See notes to Consolidated Financial Statements.
|
|
|
Years Ended December 31, |
|
||||||||||||||||||||||||||||||||||||
|
|
|
2001 |
2000 |
|
1999 |
|
|||||||||||||||||||||||||||||||||
|
CHANGES IN OTHER WORKING CAPITAL COMPONENTS |
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||||
|
(Excluding cash and cash equivalents, and debt due within one year) |
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||||
|
Accounts and notes receivable |
|
$ |
353 |
|
|
$ |
(655 |
) |
|
$ |
188 |
|
|||||||||||||||||||||||||||
|
Net trading assets |
|
|
(362 |
) |
|
|
(290 |
) |
|
|
(73 |
) |
|||||||||||||||||||||||||||
|
Income taxes -- net |
|
|
(121 |
) |
|
|
120 |
|
|
|
(171 |
) |
|||||||||||||||||||||||||||
|
Inventories |
|
|
33 |
|
|
|
(97 |
) |
|
|
(2 |
) |
|||||||||||||||||||||||||||
|
Regulatory balancing accounts |
|
|
46 |
|
|
|
522 |
|
|
|
303 |
|
|||||||||||||||||||||||||||
|
Regulatory assets and liabilities |
|
|
39 |
|
|
|
(2 |
) |
|
|
(2 |
) |
|||||||||||||||||||||||||||
|
Other current assets |
|
|
69 |
|
|
|
(84 |
) |
|
|
(21 |
) |
|||||||||||||||||||||||||||
|
Accounts payable |
|
|
(302 |
) |
|
|
733 |
|
|
|
25 |
|
|||||||||||||||||||||||||||
|
Other current liabilities |
|
|
42 |
|
|
|
161 |
|
|
|
5 |
|
|||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||||
|
Net change in other working capital components |
$ |
(203 |
) |
$ |
408 |
$ |
252 |
|
|||||||||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||||||||||||
|
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION |
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||
|
Interest payments, net of amounts capitalized |
|
$ |
302 |
$ |
291 |
$ |
274 |
|
|||||||||||||||||||||||||||||||
|
Income tax payments, net of refunds |
|
$ |
138 |
$ |
104 |
$ |
168 |
|
|||||||||||||||||||||||||||||||
|
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES |
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||||||||
|
Liabilities assumed for real estate investments |
|
$ |
-- |
|
$ |
-- |
$ |
34 |
|
||||||||||||||||||||||||||||||
SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
Years Ended December 31, 2001, 2000 and 1999
|
|
|
|
|
Deferred Compensation Relating to ESOP |
Accumulated Other Comprehensive Income (Loss) |
|
|
|
Balance at December 31, 1998 |
$ 1,883 |
$1,075 |
$ (45) |
$ -- |
$2,913 |
||
|
Net income |
$ 394 |
394 |
394 |
||||
|
Comprehensive income adjustments: |
|||||||
|
Foreign-currency translation losses |
(42) |
(42) |
(42) |
||||
|
Available-for-sale securities |
10 |
10 |
10 |
||||
|
Pension |
(7) |
(7) |
(7) |
||||
|
Comprehensive income |
$ 355 |
||||||
|
Common stock dividends declared |
(368) |
(368) |
|||||
|
Quasi-reorganization adjustment (Note 2) |
80 |
80 |
|||||
|
Issuances of common stock |
2 |
2 |
|||||
|
Long-term incentive plan |
1 |
1 |
|||||
|
Common stock released from ESOP |
3 |
3 |
|||||
|
Balance at December 31, 1999 |
1,966 |
1,101 |
(42) |
(39) |
2,986 |
||
|
Net income |
$429 |
429 |
429 |
||||
|
Comprehensive income adjustments: |
|||||||
|
Foreign-currency translation losses |
(2) |
(2) |
(2) |
||||
|
Available-for-sale securities |
(10) |
(10) |
(10) |
||||
|
Pension |
2 |
2 |
2 |
||||
|
Comprehensive income |
$419 |
||||||
|
Common stock dividends declared |
(201) |
(201) |
|||||
|
Issuances of common stock |
11 |
11 |
|||||
|
Repurchase of common stock |
(558) |
(167) |
(725) |
||||
|
Long-term incentive plan |
1 |
1 |
|||||
|
Common stock released from ESOP |
3 |
3 |
|||||
|
Balance at December 31, 2000 |
1,420 |
1,162 |
(39) |
(49) |
2,494 |
||
|
Net income |
$518 |
518 |
518 |
||||
|
Comprehensive income adjustments: |
|||||||
|
Foreign-currency translation losses (Note 2) |
|
|
|
||||
|
Pension |
(8) |
(8) |
(8) |
||||
|
Other |
1 |
1 |
1 |
||||
|
Comprehensive income |
$325 |
||||||
|
Common stock dividends declared |
(205) |
(205) |
|||||
|
Quasi-reorganization adjustment (Note 2) |
35 |
35 |
|||||
|
Issuances of common stock |
41 |
41 |
|||||
|
Repurchase of common stock |
(1) |
(1) |
|||||
|
Common stock released from ESOP |
3 |
3 |
|||||
|
Balance at December 31, 2001 |
$1,495 |
$1,475 |
$ (36) |
$ (242) |
$ 2,692 |
||
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. BUSINESS COMBINATION
The Consolidated Financial Statements are those of the company and its subsidiaries and give effect to the business combination using the pooling-of-interests method and, therefore, are presented as if the companies were combined during all periods included therein.
NOTE 2. SIGNIFICANT ACCOUNTING POLICIES
Effects of Regulation
The accounting policies of the company's principal utility subsidiaries, San Diego Gas & Electric (SDG&E) and Southern California Gas Company (SoCalGas) (collectively, the California utilities), conform with generally accepted accounting principles for regulated enterprises and reflect the policies of the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC).
SDG&E and SoCalGas prepare 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 records 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 rates for amounts due to customers. To the extent that portions of the utility operations cease to be subject to SFAS No. 71, or recovery is no longer probable as a result of changes in regulation or the utility's 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 and for 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. The application of SFAS No. 121 continues to be evaluated in connection with industry restructuring. Information concerning regulatory assets and liabilities is described below in "Revenues", "Regulatory Balancing Accounts," and "Regulatory Assets and Liabilities," and industry restructuring is described in Notes 14 and 15.
Revenues
Revenues from the California utilities are derived from deliveries of electricity and natural gas to customers and changes in related regulatory balancing accounts. Revenues for electricity and natural gas sales and services are generally recorded under the accrual method and these revenues are recognized upon delivery. The portion of SDG&E's electric commodity that is procured for its customers by the California Department of Water Resources (DWR) is not included in SDG&E's revenues or costs. PX/ISO power revenues have been netted against purchased-power expense to avoid double-counting as SDG&E sells power into the PX/ISO and then purchases power therefrom. Natural gas storage contract revenues are accrued on a monthly basis and reflect reservation, storage and injection charges in accordance with negotiated agreements, which have one-year to three-year terms. Operating revenue includes amounts for services rendered but unbilled (approximately one-half month's deliveries) at the end of each year.
Operating costs of San Onofre Nuclear Generating Station (SONGS) Units 2 and 3, including nuclear fuel and nuclear fuel financing costs, and incremental capital expenditures, are recovered through a performance incentive pricing plan which allows SDG&E to receive approximately 4 cents per kilowatt-hour (kWh) through 2003. Any differences between these costs and the incentive price affect net income. This is intended to make the units more competitive with other sources. As part of the CPUC's study of retained generation by all of California's investor-owned electric utilities (IOUs) a draft decision proposes that the incentive plan be terminated effective December 31, 2001 even though California law provides for its continuance through 2003. An alternative draft decision proposes that the incentive plan continues as scheduled. The matter is on the CPUC's agenda for its March 21, 2002 meeting.
Additional information concerning utility revenue recognition is discussed below under "Regulatory Balancing Accounts" and "Regulatory Assets and Liabilities."
Sempra Energy Trading (SET) derives a substantial portion of its revenues from market making and trading activities, as a principal, in natural gas, electricity, petroleum and other commodities, for which it quotes bid and asked prices to end users and other market makers. 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 measured at current market value. SET 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 include options, forwards, futures, physical commodities and swaps. Options, which are either exchange-traded or directly negotiated between counterparties, provide the holder with the right to buy from or sell to the other party an agreed amount of commodity at a specified price withi n a specified period or at a specified time.
As a writer of options, SET generally receives an option premium and then manages the risk of an unfavorable change in the value of the underlying commodity by entering into related transactions or by other means. Forward and future transactions are contracts for delayed delivery of commodities in which the counterparty agrees to make or take delivery at a specified price. Commodity swap transactions may involve the exchange of fixed and floating payment obligations without the exchange of the underlying commodity. 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 SET. For the year ended December 31, 2001, substantially all of SET's derivative transactions were held for trading and marketing purposes and were recorded at current market value.
Revenues at Sempra Energy Solutions (SES) are derived from integrated energy-related products and services to commercial, industrial, government, institutional and consumer markets. Energy supply revenues from natural gas and electricity commodity sales are recognized on a current market value basis and include realized gains and losses and the net change in unrealized gains and losses measured at fair value. Revenues on construction projects are recognized during the construction period using the percentage-of-completion method, and revenues from other operating and maintenance service contracts are recorded under the accrual method and recognized as service is rendered.
The consolidated subsidiaries of Sempra Energy International (SEI) which operate in Mexico recognize revenue similarly to the California utilities, except that SFAS 71 is not applicable due to the different regulatory environment. The balance of SEI's revenues and most of the revenues of Sempra Energy Resources (SER) consist of their share of the income of their unconsolidated subsidiaries.
Regulatory Balancing Accounts
The amounts included in regulatory balancing accounts at December 31, 2001, represent net payables (payables net of assets) of $85 million and $575 million for SoCalGas and SDG&E, respectively. The corresponding amounts at December 31, 2000, were net payables of $465 million and $367 million for SoCalGas and SDG&E, respectively.
Balancing accounts provide a mechanism for charging utility customers the exact amount incurred for certain costs, primarily commodity costs. As a result of California's electric-restructuring law, fluctuations in certain costs and consumption levels that had been balanced now affect earnings from electric operations. In addition, fluctuations in certain costs and consumption levels affect earnings from the California utilities' natural gas operations. Additional information on regulatory matters is included in Notes 14 and 15.
Regulatory Assets and Liabilities
In accordance with the accounting principles of SFAS 71 for rate-regulated enterprises, the company records regulatory assets (which represent probable future revenues associated with certain costs that will be recovered from customers through the rate-making process) and regulatory liabilities (which represent probable future reductions in revenue associated with amounts that are to be credited to customers through the rate-making process). They are amortized over the periods in which the costs are recovered from or refunded to customers in regulatory revenues.
Regulatory assets (liabilities) as of December 31 consist of (dollars in millions):
|
|
|
2001 |
|
|
2000 |
|
|||||||||||||
|
SDG&E |
|
|
|
|
|
|
|
|
|||||||||||
|
Fixed-price contracts and other derivatives |
|
$ |
760 |
|
|
$ |
-- |
|
|||||||||||
|
Recapture of temporary discount* |
|
|
409 |
|
|
|
474 |
|
|||||||||||
|
Undercollected electric commodity cost |
|
|
392 |
|
|
|
352 |
|
|||||||||||
|
Deferred taxes recoverable in rates |
|
|
162 |
|
|
|
140 |
|
|||||||||||
|
Unamortized loss on retirement of debt-net |
|
|
52 |
|
|
|
57 |
|
|||||||||||
|
Employee benefit costs |
|
|
39 |
|
|
|
35 |
|
|||||||||||
|
Other |
|
|
26 |
|
|
|
7 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
Total |
|
|
1,840 |
|
|
|
1,065 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
SoCalGas |
|
|
|
|
|
|
|
|
|||||||||||
|
Environmental remediation |
|
|
55 |
|
|
|
58 |
|
|||||||||||
|
Fixed-price contracts and other derivatives |
|
|
257 |
|
|
|
-- |
|
|||||||||||
|
Unamortized loss on retirement of debt-net |
|
|
41 |
|
|
|
36 |
|
|||||||||||
|
Deferred taxes refundable in rates |
|
|
(158 |
) |
|
|
(100 |
) |
|||||||||||
|
Employee benefit costs |
|
|
(132 |
) |
|
|
(60 |
) |
|||||||||||
|
Other |
|
|
5 |
|
|
|
6 |
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
Total |
|
|
68 |
|
|
(60 |
) |
||||||||||||
|
PE--Employee benefit costs |
|
|
88 |
|
|
96 |
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
Total PE consolidated |
|
|
156 |
|
|
36 |
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
Total |
|
$ |
1,996 |
|
$ |
1,101 |
|
||||||||||||
|
|
* |
|
In connection with electric industry restructuring, which is described in Note 14, SDG&E temporarily reduced rates to its small-usage customers. That reduction is being recovered in rates through 2004. |
|
|
|
2001 |
|
|
2000 |
||
|
Current regulatory assets |
|
$ |
266 |
|
|
$ |
100 |
|
Noncurrent regulatory assets |
|
|
1,835 |
|
|
|
1,001 |
|
Current regulatory liabilities |
|
|
(19 |
) |
|
|
-- |
|
Noncurrent regulatory liabilities |
|
|
(86 |
) |
|
|
-- |
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,996 |
|
|
$ |
1,101 |
Trading Instruments
Trading assets and trading liabilities are recorded on a trade-date basis and adjusted daily to current market value. They include option premiums paid and received; and unrealized gains and losses from exchange-traded futures and options, over-the-counter (OTC) swaps, forwards, physical commodities 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 an enforceable master netting arrangement.
Futures and exchange-traded option transactions are recorded as contractual commitments on a trade-date basis and are carried at current market value based on current 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 current dealer quotations and underlying commodity-exchange quotations. OTC options are carried at fair value based on the use of valuation models that utilize, among other things, current interest, commodity and volatility rates. For long-dated forward transactions, where there are no dealer or exchange quotations, current market values are derived using internally developed valuation methodologies based on available market information. Where market rates are not quoted, 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 significantly from realized values. Changes in market values are recorded in the calculation of net income.
Allowance for Doubtful Accounts
The allowance for doubtful accounts was $45 million, $34 million and $19 million at December 31, 2001, 2000, and 1999, respectively. The company recorded a provision for doubtful accounts of $36 million, $32 million and $11 million in 2001, 2000 and 1999, respectively.
Loans Due From Unconsolidated Affiliates
In December 2001, SEI issued two U.S. dollar denominated loans totaling $35 million and $22 million to its affiliates Camuzzi Gas Pampeana S. A. and Camuzzi Gas del Sur S. A., respectively. These loans have variable interest rates (8.863% at December 31, 2001) and are due on December 11, 2002.
Inventories
At December 31, 2001, inventory included natural gas and fuel oil of $233 million, and materials and supplies of $56 million. The corresponding balances at December 31, 2000 were $265 million and $77 million, respectively. SET's portion ($165 million and $197 million at December 31, 2001 and 2000, respectively) of the natural gas and fuel oil are carried at fair market value. Natural gas and fuel oil at the California utilities ($68 million at both December 31, 2001 and 2000) are valued by the last-in first-out (LIFO) method. When the California utilities' inventory is consumed, differences between this LIFO valuation and replacement cost will be reflected in customer rates. Materials and supplies at the California utilities are generally valued at the lower of average cost or market.
Property, Plant and Equipment
Property, plant and equipment primarily represents the buildings, equipment and other facilities used by the California utilities to provide natural gas and electric utility service.
The cost of utility plant includes labor, materials, contract services and related items, and an allowance for funds used during construction (AFUDC). The cost of most 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 14. Property, plant and equipment balances by major functional categories were as follows:
|
|
|
Property, Plant and Equipment at December 31 |
|
Depreciation rates for years ended December 31 |
||||||||||||
|
(Dollars in billions) |
|
2001 |
|
2000 |
|
2001 |
|
2000 |
1999 |
|||||||
|
California utilities: |
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Natural gas operations |
|
$ |
7.4 |
|
$ |
7.2 |
|
4.25% |
|
4.29% |
|
4.32% |
||||
|
Electric distribution |
|
|
2.9 |
|
|
2.7 |
|
4.67% |
|
4.67% |
|
4.69% |
||||
|
Electric transmission |
|
|
0.8 |
|
|
0.8 |
|
3.19% |
|
3.21% |
|
3.50% |
||||
|
Other electric |
|
|
0.4 |
|
|
0.4 |
|
8.46% |
|
8.33% |
|
8.21% |
||||
|
|
|
|
|
|
|
|
||||||||||
|
Total |
|
|
11.5 |
|
|
11.1 |
|
|
|
|
|
|
||||
|
Other operations |
|
|
1.3 |
|
|
0.8 |
|
various |
|
various |
|
various |
||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
|
Total |
|
$ |
12.8 |
|
$ |
11.9 |
|
|
|
|
|
|
||||
AFUDC, which represents the cost of funds used to finance the construction of utility plant, is added to the cost of utility plant. AFUDC also increases income, partly as an offset to interest charges and partly as a component of other income, shown in the Statements of Consolidated Income, although it is not a current source of cash. AFUDC amounted to $6 million, $4 million and $4 million for 2001, 2000 and 1999, respectively. Total interest amounts capitalized, including AFUDC and the impact of SER's construction projects, were $17 million, $7 million and $5 million for 2001, 2000 and 1999, respectively.
Long-Lived Assets
In accordance with SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," the company periodically evaluates whether events or circumstances have occurred that may affect the recoverability or the estimated useful lives of long-lived assets. Impairment occurs when the estimated future undiscounted cash flows exceed the carrying amount of the assets. If that comparison indicates that the assets' carrying value may be permanently impaired, such potential impairment is measured based on the difference between the carrying amount and the fair value of the assets based on quoted market prices or, if market prices are not available, on the estimated discounted cash flows. This calculation is performed at the lowest level for which separately identifiable cash flows exist.
Nuclear-Decommissioning Liability
At December 31, 2001 and 2000, deferred credits and other liabilities include $151 million and $162 million, respectively, of accumulated decommissioning costs associated with SDG&E's interest in SONGS Unit 1, which was permanently shut down in 1992. The corresponding liability for SONGS Units 2 and 3 decommissioning (included in accumulated depreciation and amortization) is $375 million and $381 million at December 31, 2001 and 2000, respectively. Additional information on SONGS decommissioning costs is included in Note 6.
Foreign Currency Translation
The assets and liabilities of the company's foreign operations are generally translated into U.S. dollars at current exchange rates, and revenues and expenses are translated at average exchange rates for the year. Resulting translation adjustments do not enter into the calculation of net income or retained earnings, but are reflected in accumulated other comprehensive income, a component of shareholders' equity which is described below. Foreign currency transaction gains and losses are included in consolidated net income. In December 2001, to reflect the devaluation in the Argentine peso, the functional currency of the company's Argentine operations, SEI adjusted its investment in two Argentine natural gas utility holding companies downward by $155 million. The adjustment is included in the calculation of comprehensive income. Additional information concerning these investments is described in Note 3.
Comprehensive Income
Comprehensive income includes all changes, except those resulting from investments by owners and distributions to owners, in the equity of a business enterprise from transactions and other events, including foreign-currency translation adjustments, minimum pension liability adjustments, unrealized gains and losses on marketable securities that are classified as available-for-sale, and certain hedging activities. The components of other comprehensive income are shown in the Statements of Consolidated Changes in Shareholders' Equity.
Quasi-Reorganization
In 1993, PE divested its merchandising operations and most of its oil and gas exploration and production business. In connection with the divestitures, PE effected a quasi-reorganization for financial reporting purposes as of December 31, 1992. Certain of the liabilities established in connection with the quasi-reorganization, including various income-tax issues, have been favorably resolved. Excess liabilities of $35 million and $80 million resulting from the favorable resolution of these issues were restored to shareholders' equity in December 2001 and November 1999, respectively, but did not affect the calculation of net income. The remaining liabilities will be resolved in future years. Management believes the provisions established for these matters are adequate.
Use of Estimates in the Preparation of the Financial Statements
The preparation of 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 the 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 can differ significantly from those estimates.
Cash and Cash Equivalents
Cash equivalents are highly liquid investments with maturities of three months or less at the date of purchase.
Basis of Presentation
Certain prior-year amounts have been reclassified to conform to the current year's presentation.
New Accounting Standards
Effective January 1, 2001, the company adopted SFAS No. 133 "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities." As amended, SFAS 133 requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value and recognize changes in the fair value of derivatives in earnings in the period of change unless the derivative qualifies as an effective hedge that offsets certain exposure.
The company utilizes derivative financial instruments to reduce its exposure to unfavorable changes in energy prices, which are subject to significant and often volatile fluctuation. Derivative financial instruments include futures, forwards, swaps, options and long-term delivery contracts. These contracts allow the company to predict with greater certainty the effective prices to be received and, in the case of the California utilities, the prices to be charged to their customers.
Upon adoption of SFAS 133 on January 1, 2001, the company classifies its forward contracts as follows:
Normal Purchase and Sales: These forward contracts are excluded from the requirements of SFAS No. 133. The realized gains and losses on these contracts are reflected in the income statement at the contract settlement date. The contracts that generally qualify as normal purchases and sales are long-term contracts that are settled by physical delivery.
Cash Flow Hedges: The unrealized gains and losses related to these forward contracts will be included in accumulated other comprehensive income, a component of shareholders' equity, but not reflected in the Statements of Consolidated Income until the corresponding hedged transaction is settled.
Electric and Gas Purchases and Sales: The unrealized gains and losses related to these forward contracts, as they relate to the California utilities, are reflected on the balance sheet as regulatory assets and liabilities, to the extent derivative gains and losses will be recoverable or payable in future rates.
If gains and losses at the California utilities are not recoverable or payable through future rates, the California utilities will apply hedge accounting if certain criteria are met.
In instances where hedge accounting is applied to energy derivatives, cash flow hedge accounting is elected and, accordingly, changes in fair values of the derivatives are included in other comprehensive income, but not reflected in the Statements of Consolidated Income until the corresponding hedged transaction is settled. The effect on other comprehensive income for the year ended December 31, 2001 was not material. In instances where energy derivatives do not qualify for hedge accounting, gains and losses are recorded in the Statements of Consolidated Income.
The adoption of this new standard on January 1, 2001, did not have a material effect on the company's earnings. However, $1.1 billion in current assets, $1.1 billion in noncurrent assets, $6 million in current liabilities and $238 million in noncurrent liabilities were recorded in the Consolidated Balance Sheets as fixed-priced contracts and other derivatives as of January 1, 2001. Due to the regulatory environment in which the California utilities operate, regulatory assets and liabilities were established to the extent that derivative gains and losses are recoverable or payable through future rates. As such, $1.1 billion in current regulatory liabilities, $1.1 billion in noncurrent regulatory liabilities, $5 million in current regulatory assets and $238 million in noncurrent regulatory assets were recorded in the Consolidated Balance Sheets as of January 1, 2001. See Note 10 for additional information on the effects of SFAS 133 on the financial statements at December 31, 2001. The ongoing eff ects will depend on future market conditions and the company's hedging activities.
In July 2001, the Financial Accounting Standards Board (FASB) issued three statements, SFAS 141 "Business Combinations," SFAS 142 "Goodwill and Other Intangible Assets" and SFAS 143 "Accounting for Asset Retirement Obligations."
SFAS 141 requires the use of the purchase method of accounting for all business combinations initiated after June 30, 2001. The pooling-of-interest method is eliminated. It also specifies the types of acquired intangible assets that are required to be recognized and reported separately from goodwill.
SFAS 142 provides guidance on how to account for goodwill and other intangible assets after an acquisition is complete, and is effective for fiscal years that start after December 15, 2001. SFAS 142 calls for amortization of goodwill to cease and requires goodwill and certain other intangibles to be tested for impairment at least annually. Included in the Consolidated Balance Sheets at December 31, 2001 were $172 million of goodwill related to consolidated subsidiaries (included in sundry assets) and $248 million of goodwill related to unconsolidated subsidiaries (included in investments). Amortization of goodwill, including the company's share of amounts recorded by unconsolidated subsidiaries, was $24 million, $35 million and $32 million in 2001, 2000, and 1999, respectively. The company does not expect a material impact on its earnings resulting from any impairment of goodwill.
SFAS 143 addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation of a long-lived asset, such as nuclear plants. It requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset to reflect the future retirement cost. Over time, the liability is accreted to its present value and paid, and the capitalized cost is depreciated over the useful life of the related asset. SFAS 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002.
Upon adoption of SFAS 143, the company estimates it would record an addition of $468 million to utility plant representing the company's share of SONGS estimated future decommissioning costs, and a corresponding retirement obligation liability of $468 million. The nuclear decommissioning trusts balance of $526 million at December 31, 2001 represents amounts collected for future decommissioning costs and has a corresponding offset in accumulated depreciation. Any difference between the amount of capitalized cost that would have been recorded and depreciated and the amounts collected in the nuclear decommissioning trusts will be recorded as a regulatory asset or liability. Additional information on SONGS decommissioning is included in Note 6. Except for SONGS, the company has not yet determined the effect of SFAS 143 on its Consolidated Balance Sheets, but has determined that it will not have a material effect on its Statements of Consolidated Income.
In August 2001, the FASB issued SFAS 144 "Accounting for the Impairment or Disposal of Long-Lived Assets" that replaces SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." SFAS 144 applies to all long-lived assets, including discontinued operations. SFAS 144 requires that those long-lived assets classified as held for sale be measured at the lower of carrying amount (cost less accumulated depreciation) or fair value less cost to sell. Discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. SFAS 144 also broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The provisions of SFAS 144 are effective for fiscal years beginning after December 15, 2001 . The adoption of SFAS 144 will not have a material effect on the company's financial statements.
NOTE 3. INVESTMENTS IN UNCONSOLIDATED SUBSIDIARIES
Investments in which the company has an interest of twenty to fifty percent are accounted for under the equity method. The company's pro rata shares of the subsidiaries' net assets are included under the caption "Investments" on the Consolidated Balance Sheets, and are adjusted for the company's share of each investee's earnings, dividends and foreign currency translation effects. Earnings are recorded as equity earnings on the Statements of Consolidated Income within the caption "Other income -- net." In addition, the company had approximately $30 million of investments accounted for by the cost method (at December 31, 2001 and 2000). The company's investments in unconsolidated subsidiaries accounted for by the equity method are summarized as follows:
|
|
|
Investment at December 31 |
|
||||||
|
(in millions) |
|
2001 |
|
|
2000 |
|
|||
|
Chilquinta Energia (including Luz del Sur) |
|
$ |
476 |
|
|
$ |
511 |
|
|
|
Sodigas Pampeana and Sodigas Sur |
|
|
140 |
|
|
|
290 |
|
|
|
Elk Hills power project |
|
|
133 |
|
|
|
-- |
|
|
|
El Dorado power project |
|
|
57 |
|
|
|
85 |
|
|
|
Sempra Energy Financial housing partnerships |
|
|
290 |
|
|
|
346 |
|
|
|
Sempra Energy Financial alternative fuel partnerships |
|
|
27 |
|
|
|
19 |
|
|
|
Other |
|
|
13 |
|
|
|
3 |
|
|
|
Total Investment |
|
|
1,136 |
|
|
|
1,254 |
|
|
|
Equity in net assets |
|
|
(888 |
) |
|
|
(974 |
) |
|
|
Cost in excess of equity in net assets |
|
$ |
248 |
|
|
$ |
280 |
|
|
Sempra Energy International
In June 1999, SEI and PSEG Global (PSEG) each purchased a 50-percent interest in Chilquinta Energia S.A. (Energia), a Chilean electric utility. SEI invested $260 million for the purchase of stock and refinanced $160 million of Energia's long-term debt outstanding. In September 1999, SEI and PSEG completed their acquisition of 47.5 percent of the outstanding shares of Luz del Sur S.A.A. (Luz), a Peruvian electric utility. SEI's share of the transaction was $108 million in cash. Combined with the 37 percent already owned through Energia, the companies' total joint ownership of Luz increased to 84.5 percent.
In October 2000, SEI increased its existing investment in two Argentine natural gas utility holding companies (Sodigas Pampeana S.A. and Sodigas Sur S.A.) from 21.5 percent to 43 percent. Shortly after December 31, 2001, the Argentine peso, the functional currency of the company's Argentine operations, was devalued and will now float freely in the foreign exchange market. As a result, SEI adjusted its investment in the Sodigas companies downward by $155 million. This did not affect net income, but is included in Other Comprehensive Income.
Sempra Energy Resources
In December 2000, SER obtained approvals from the appropriate state agencies to construct the Elk Hills Power Project (Elk Hills), a $410 million, 570-megawatt power plant near Bakersfield, California. Elk Hills is being developed in a joint venture with Occidental Energy Ventures Corporation (Occidental). Information concerning litigation with Occidental is provided in Note 13.
In 2000, El Dorado Energy, a 50/50 partnership between SER and Reliant Energy Power Generation, completed construction of a $280 million, 500-megawatt merchant power plant near Las Vegas, Nevada.
Sempra Energy Financial (SEF)
SEF invests as a limited partner in 1,300 affordable-housing projects throughout the United States, Puerto Rico and the Virgin Islands. These investments are accounted for in accordance with Issue No. 94-1 of the Emerging Issues Task Force of the Financial Accounting Standards Board, "Accounting for Tax Benefits Resulting from Investments in Affordable Housing Projects." These investments are expected to provide income tax benefits (primarily from income tax credits) over 10-year periods. SEF also invests in alternative-fuel projects. SEF's future investment policy is dependent on the company's future income tax position.
Sempra Energy Solutions
In August 2000, SES purchased Connectiv Thermal Systems' 50-percent interests in Atlantic-Pacific Las Vegas and Atlantic-Pacific Glendale for $40 million, thereby acquiring full ownership of these on-site energy management companies, resulting in their becoming consolidated subsidiaries.
NOTE 4. SHORT-TERM BORROWINGS
At December 31, 2001, Sempra Energy Global Enterprises (Global), the parent company for most of Sempra Energy's subsidiaries other than the California utilities, had a $1.2 billion syndicated revolving line of credit guaranteed by Sempra Energy. The revolving credit commitment expires in September 2002, at which time then outstanding borrowings may be converted to a one-year term loan. The agreement requires Sempra Energy to maintain a debt-to-total capitalization ratio (as defined in the agreement) of not to exceed 65 percent. Under this ratio Sempra Energy and its subsidiaries could have issued in excess of $2 billion of additional debt at December 31, 2001.
Borrowings under the agreement would bear interest at rates varying with market rates and Sempra Energy's credit rating. Global's line of credit was unused at December 31, 2001, and is available to support commercial paper and variable-rate long-term debt. Global had $705 million and $401 million of commercial paper, guaranteed by Sempra Energy, outstanding at December 31, 2001 and 2000, respectively.
At December 31, 2001, SDG&E had $250 million of revolving lines of credit, which is available to support commercial paper and variable-rate long-term debt. The revolving credit commitments on $50 million and $200 million of these lines expire in July 2002 and August 2002, respectively, at which time then outstanding borrowings may be converted into term loans of one and two years, respectively. Borrowings under the lines would bear interest at rates varying with market rates and SDG&E's credit rating. These revolving lines of credit were unused at December 31, 2001 and 2000.
At December 31, 2001, SoCalGas had a $170 million syndicated revolving line of credit, which is available to support commercial paper. Borrowings under the agreement, which expires on May 26, 2002, would bear interest at rates varying with market rates and SoCalGas' credit rating. The agreement requires SoCalGas to maintain a debt-to-total capitalization ratio (as defined in the agreement) of not to exceed 65 percent. At December 31, 2001, SoCalGas had $50 million of commercial paper outstanding. The revolving line of credit was unused at December 31, 2001 and 2000.
At December 31, 2001, SER had a syndicated $400 million, three-year revolving line of credit, guaranteed by Sempra Energy, primarily to finance power plant and gas pipeline construction projects. The agreement requires that Sempra Energy maintains a debt-to-total capitalization ratio (as defined in the agreement) of not to exceed 65 percent. SER's line of credit was unused at December 31, 2001. This agreement expires in August 2004 and borrowings bear interest at rates varying with market rates and Sempra Energy's credit rating. In January 2002, SER borrowed $200 million of the credit line to fund its construction activities.
At December 31, 2001, PE had a $500 million two-year revolving line of credit, guaranteed by Sempra Energy, for the purpose of providing loans to Global. The revolving credit commitment expires in April 2003, at which time then outstanding borrowings may be converted into a two-year term loan. Borrowings would be subject to mandatory prepayment should PE's issuer credit rating cease to be at least BBB- by Standard & Poors, should SoCalGas' unsecured long-term credit ratings cease to be at least BBB by S&P and Baa2 by Moody's, should Sempra Energy's or SoCalGas' debt-to-total capitalization ratios (as defined in the agreement) exceed 65 percent, or should there be a change in law materially and adversely affecting the ability of SoCalGas to pay dividends or make distributions to PE. Borrowings would bear interest at rates varying with market rates and the amount of outstanding borrowings. PE's line of credit was unused at December 31, 2001.
At December 31, 2001, SET had $548 million in various uncommitted lines of credit that are guaranteed by Sempra Energy and bear interest at rates varying with market rates and Sempra Energy's credit rating. SET had $120 million and $165 million in short-term borrowings outstanding at December 31, 2001 and 2000, respectively. SET also had $167 million of letters of credit outstanding against these lines at December 31, 2001.
The company's weighted average interest rate for short-term borrowings outstanding at December 31, 2001 and 2000 was 2.18% and 6.69%, respectively.
NOTE 5. LONG-TERM DEBT
|
December 31 (Dollars in millions) |
2001 |
|
2000 |
|||
|
First-mortgage bonds |
|
|
|
|
|
|
|
7.625% June 15, 2002 |
$ |
28 |
|
$ |
28 |
|
|
6.875% August 15, 2002 |
|
100 |
|
|
100 |
|
|
5.75% November 15, 2003 |
|
100 |
|
|
100 |
|
|
6.8% June 1, 2015 |
|
14 |
|
|
14 |
|
|
5.9% June 1, 2018 |
|
68 |
|
|
68 |
|
|
5.9% to 6.400% September 1, 2018 |
|
176 |
|
|
176 |
|
|
6.1% September 1, 2019 |
|
35 |
|
|
35 |
|
|
|
|
|
|
|
||
|
Variable rates (2% to 2.4% at December 31, 2001) payable September 1, 2020 |
|
58 |
|
|
58 |
|
|
5.85% June 1, 2021 |
|
60 |
|
|
60 |
|
|
8.5% April 1, 2022 |
|
10 |
|
|
10 |
|
|
7.375% March 1, 2023 |
|
100 |
|
|
100 |
|
|
7.5% June 15, 2023 |
|
125 |
|
|
125 |
|
|
Variable rates (1.95% at December 31, 2001) payable November 1, 2025 |
|
175 |
|
|
175 |
|
|
6.4% and 7% December 1, 2027 |
|
225 |
|
|
165 |
|
|
8.75% October 1, 2021 |
|
-- |
|
|
150 |
|
|
Total |
|
1,274 |
|
|
1,364 |
|
|
|
|
|
|
|
|
|
|
Unsecured long-term debt |
|
|
|
|
|
|
|
5.9% June 1, 2014 |
|
130 |
|
|
130 |
|
|
Variable rates (1.75% at December 31, 2001) payable July 1, 2021 |
|
39 |
|
|
39 |
|
|
Variable rates (1.5% at December 31, 2001) payable December 1, 2021 |
|
60 |
|
|
60 |
|
|
6.75% March 1, 2023 |
|
25 |
|
|
25 |
|
|
5.67% January 18, 2028 |
|
75 |
|
|
75 |
|
|
6.375% May 14, 2006 |
|
8 |
|
|
8 |
|
|
6.375% October 29, 2001 |
|
-- |
|
|
120 |
|
|
Other variable-rate debt |
|
27 |
|
|
10 |
|
|
Total |
|
364 |
|
|
467 |
|
|
|
|
|
|
|
|
|
|
Rate-reduction bonds, various rates, payable annually through 2007 (6.15% to 6.37% at December 31, 2001) |
|
395 |
|
|
461 |
|
|
Debt incurred to acquire limited partnerships, secured by real estate, at 6.97% to 9.35% payable annually through 2009 |
|
187 |
|
|
233 |
|
|
Notes payable at 6.95% payable in 2005 |
|
300 |
|
|
300 |
|
|
Notes payable at 7.95% payable in 2010 |
|
500 |
|
|
500 |
|
|
Notes payable at variable rates after a fixed-to-floating rate swap |
|
|
|
|
|
|
|
(3.19% to 3.23% at December 31, 2001) payable in 2004 |
|
500 |
|
|
-- |
|
|
Employee Stock Ownership Plan |
|
|
|
|
|
|
|
Bonds at 7.375% payable in November 2014 |
|
82 |
|
|
82 |
|
|
Bonds at variable rates (2.39% at December 31, 2001) payable in November 2014 |
|
46 |
|
|
48 |
|
|
Variable rate debt (10.2% at December 31,2000) |
|
-- |
|
|
160 |
|
|
Capitalized leases |
|
14 |
|
|
37 |
|
|
Market value adjustments for interest rate swaps -- net |
|
22 |
|
|
-- |
|
|
Total |
|
3,684 |
|
|
3,652 |
|
|
Less: |
|
|
|
|
|
|
|
Current portion of long-term debt |
|
242 |
|
|
368 |
|
|
Unamortized discount on long-term debt |
|
6 |
|
|
16 |
|
|
|
|
248 |
|
|
384 |
|
|
Total |
$ |
3,436 |
|
$ |
3,268 |
|
First-mortgage Bonds
The first-mortgage bonds were issued by the California utilities and are secured by a lien on their respective utility plant. The California utilities may issue additional first-mortgage bonds upon compliance with the provisions of their bond indentures, which require, among other things, the satisfaction of pro forma earnings-coverage tests on first-mortgage bond interest and the availability of sufficient mortgaged property to support the additional bonds. The most restrictive of these tests (the property test) would have permitted the issuance, subject to CPUC authorization, of an additional $2.5 billion of first-mortgage bonds at December 31, 2001.
During the first quarter of 2001, SDG&E remarketed $150 million of variable-rate first-mortgage bonds for a five-year term at a fixed rate of 7 percent. At SDG&E's option, the bonds may be remarketed at a fixed or floating rate at December 1, 2005, the expiration of the fixed term.
In November 2001, SoCalGas called its $150 million 8.75% million first-mortgage bonds at a premium of 3.59 percent.
On December 11, 2001, SoCalGas entered into an interest-rate swap which effectively exchanged the fixed rate on its $175 million 6.875% first-mortgage bonds for a floating rate. Additional information is provided under "Interest-Rate Swaps" below.
Callable Bonds
At the company's option, certain bonds may be called at a premium, including $157 million of variable-rate bonds that are callable at various dates in 2002. Of the company's remaining callable bonds, $203 million are callable in 2002, $666 million in 2003, $25 million in 2004, $105 million in 2005 and $8 million in 2006.
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, which is described in Note 14. 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.
The sizes of the rate-reduction bond issuances were set so as to make the IOUs neutral as to the 10-percent rate reduction, and were based on a four-year period to recover stranded costs. Because SDG&E recovered its stranded costs in only 18 months (due to the greater-than-anticipated plant-sale proceeds), the bond sale proceeds were greater than needed. Accordingly, during the third quarter of 2000, SDG&E returned to its customers $388 million of surplus bond proceeds in accordance with a June 8, 2000 CPUC decision. The bonds and their repayment schedule are not affected by this refund.
Unsecured Long-term Debt
In February 2001, SDG&E remarketed $25 million of variable-rate unsecured bonds as 6.75 percent fixed-rate debt for a three-year term. At SDG&E's option, the bonds may be remarketed at a fixed or floating rate at February 29, 2004, the expiration of the fixed term. In October 2001, SoCalGas repaid $120 million of 6.38-percent medium-term notes upon maturity. In June 2001, the company issued $500 million of three-year notes due July 1, 2004 at an interest rate of 6.8 percent. Sempra Energy has a fixed-to-floating rate swap on these notes. (See discussion under "Interest-Rate Swaps" below.)
In February 2000, the company issued $500 million of long-term 7.95 percent notes due in 2010 to partially finance the self-tender offer described in Note 12. In December 2000, the company issued an additional $300 million in long-term notes due in 2005 in order to reduce short-term debt. The notes bear interest at 6.95 percent, which is subject to change based on the company's credit ratings. In July 2000, SoCalGas repaid $30 million of 8.75 percent medium-term notes upon maturity.
Debt of Employee Stock Ownership Plan (ESOP) and Trust (Trust)
The Trust covers substantially all of SoCalGas' employees and is used to fund part of the retirement savings plan. The Trust was assumed by Sempra Energy on October 1, 1999, and participation in the ESOP was expanded to include employees of Sempra Energy and some of its unregulated affiliates effective January 1, 2000. In November 1999, the $130 million ESOP debt was refinanced using 15-year notes with a variable interest rate. The notes are repriced weekly and subject to repurchase by the company at the holder's option, depending on market demand. Subsequently, in June 2001, utilizing the term option provisions of the notes, $82 million of the notes were remarketed at a fixed rate of 7.375% for three years. The variable interest rate and weekly repricing resume in May 2004. In September 2001, ESOP debt was reduced by $2.5 million when 40,000 shares of company common stock were released from the Trust in order to fund the employer contribution to the company savings plan. Additional information on the co mpany savings plan is included in Note 8. Interest on ESOP debt amounted to $6 million in 2001, $9 million in 2000 and $6 million in 1999. Dividends used for debt service amounted to $3 million in 2001, $3 million in 2000 and $5 million in 1999.
Interest-Rate Swaps
The company periodically enters into interest-rate swap agreements to moderate its exposure to interest-rate changes and to lower its overall cost of borrowing. At December 31, 2001, the company had three such agreements. SDG&E has an interest-rate swap agreement that matures in 2002 and effectively fixes the interest rate on $45 million of variable-rate underlying debt at 5.4 percent. This floating-to-fixed-rate swap does not qualify for hedge accounting and, therefore, the gains and losses associated with the change in fair value are recorded in the Statements of Consolidated Income. For the year ended December 31, 2001, the effect on income was a $1 million loss. Although this financial instrument does not meet the hedge accounting criteria of SFAS 133, it continues to be effective in achieving the risk management objectives for which it was intended.
The remaining two agreements are fixed-to-floating-rate swaps. Sempra Energy has entered into a fixed-to-floating-rate swap on $500 million of underlying debt which matures in 2004 and effectively causes the interest rate on the debt to vary at a weighted-average rate of LIBOR plus 1.329 percent. On December 11, 2001, SoCalGas executed a cancelable-call interest-rate swap, exchanging its fixed-rate obligation of 6.875 percent on its $175 million first-mortgage bonds for a floating rate of LIBOR plus 4 basis points. The transaction may be cancelled every 5 years by either party by payment of the mark-to-market value, or may be cancelled by the counterparty at any time the bonds are callable, by payment to SoCalGas of the applicable call premium on the bonds. The company believes both swaps are fully effective in their purpose of converting the fixed rate stated in the debt to a floating rate and the swaps meet the criteria for accounting under the short-cut method defined in SFAS No. 133 for fair value he dges of debt instruments. Accordingly, a market value adjustment to long-term debt of $22 million was recorded at December 31, 2001 to reflect, without affecting net income or other comprehensive income, the favorable economic consequences (as measured at December 31, 2001) of having entered into the swap transactions. See additional discussion of interest rate swaps in Note 10.
Foreign-Currency Hedges
The company's primary objective with respect to currency risk is to reduce net income volatility that would otherwise occur due to exchange-rate fluctuations.
Sempra Energy's net investment in its Latin American operating companies and the resulting cash flows are partially protected against normal exchange-rate fluctuations by rate-setting mechanisms which are intended to compensate for local inflation and currency exchange-rate fluctuations. In addition to establishing such tariff-based protections, the company hedges material cross-currency transactions and net-income exposure through various means, including financial instruments and short-term investments.
Because the company does not hedge its net investment in foreign countries, it is susceptible to volatility in other comprehensive income, as occurred in the year ended December 31, 2001 when Argentina decoupled its peso from the U.S. dollar, as discussed in Notes 2 and 3.
See additional discussion of foreign-currency hedges in Note 10.
Loans Due to Affiliates
In March 2001, SEI refinanced $160 million of long-term notes through its unconsolidated affiliate Chilquinta Energia Finance, LLC. At December 31, 2001 long-term notes payable to affiliates include $60 million at 6.47 percent due April 1, 2008 and $100 million at 6.62 percent due April 1 2011. The loans are secured by SEI's investments in Energia and Luz.
Financial Covenants
The California utilities' first-mortgage bond indentures require the satisfaction of certain bond interest coverage ratios and the availability of sufficient mortgaged property to issue additional first-mortgage bonds, but do not restrict other indebtedness. Note 4 discusses the financial covenants applicable to short-term debt.
NOTE 6. FACILITIES UNDER JOINT OWNERSHIP
|
Project (Dollars in millions) |
|
SONGS |
|
|
Southwest Powerlink |
|
||
|
Percentage ownership |
|
|
20 |
% |
|
|
88 |
% |
|
Utility plant in service |
|
$ |
70 |
|
|
$ |
219 |
|
|
Accumulated depreciation and amortization |
|
$ |
41 |
|
|
$ |
127 |
|
|
Construction work in progress |
|
$ |
4 |
|
|
$ |
1 |
|
The company's share of operating expenses is included in the Statements of Consolidated Income. The amounts specified above for SONGS include nuclear production, transmission and other facilities. Certain substation equipment at SONGS is wholly owned by the company.
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 CPUC and other regulatory bodies.
The company's share of decommissioning costs for the SONGS units has been estimated to be $468 million in 2001 dollars, based on escalation of a cost study completed in 1998. Cost studies are updated every three years and approved by the CPUC. The next such update is scheduled to be filed with the CPUC in the first half of 2002. Rate recovery of decommissioning costs is allowed until the time that the costs are fully recovered, and is subject to adjustment every three years based on costs allowed by regulators. The amount accrued each year is currently being collected in rates. Collections are authorized to continue until 2013, but may be extended until 2022 upon approval by the CPUC. This amount is considered sufficient to cover the company's share of future decommissioning costs. Payments to the nuclear decommissioning trusts (described below under "Nuclear Decommissioning Trusts") are expected to continue until sufficient funds have been collected to fully decommission SONGS, which is n ot expected to occur before 2022.
Unit 1 was permanently shut down in 1992 and physical decommissioning began in January 2000. Several structures, foundations and equipment have been dismantled and removed. Preparations have been made for the remaining major work to be performed in 2002 and beyond. That work will include dismantling, removal and disposal of all remaining Unit 1 equipment and facilities (both nuclear and non-nuclear components), decontamination of the site and construction of an on-site storage facility for Unit 1 spent fuel. These activities are expected to be completed by 2008.
The amounts collected in rates are invested in externally managed trust funds (described below under "Nuclear Decommissioning Trusts"). The securities held by the trusts are considered available for sale and the trust assets are shown on the Consolidated Balance Sheets at market value. These values reflect unrealized gains of $122 million and $158 million at December 31, 2001, and 2000, respectively, with the offsetting credit recorded to accumulated depreciation and decommissioning on the Consolidated Balance Sheets.
In July 2001, the FASB approved SFAS No. 143 "Accounting for Asset Retirement Obligations," which requires entities to record the fair value of a liability that results from the acquisition, construction, development and/or the normal operation of long-lived assets, such as nuclear power plants. Information concerning the estimated effect on the company's financial statements is provided in Note 2. See further discussion regarding SONGS in Notes 13 and 14.
Nuclear Decommissioning Trusts
SDG&E has a Nonqualified Nuclear Decommissioning Trust and a Qualified Nuclear Decommissioning Trust. CPUC guidelines prohibit investments in derivatives and securities of Sempra Energy or related companies. They also establish maximum amounts for investments in equity securities (50 percent of the qualified trust and 60 percent of the nonqualified trust), international equity securities (20 percent) and securities of electric utilities having ownership interests in nuclear power plants (10 percent). Not less than 50 percent of the equity portion of the trusts shall be invested passively.
At December 31, 2001 and 2000, trust assets were allocated as follows (dollars in millions):
|
|
|
Qualified Trust |
|
Nonqualified Trust |
|||||||||
|
|
|
2001 |
|
2000 |
|
2001 |
|
2000 |
|||||
|
Domestic equity |
|
$ |
144 |
|
$ |
143 |
|
$ |
48 |
|
$ |
57 |
|
|
Foreign equity |
|
|
76 |
|
|
78 |
|
|
-- |
|
|
-- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total equity |
|
|
220 |
|
|
221 |
|
|
48 |
|
|
57 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total fixed income |
|
|
225 |
|
|
228 |
|
|
33 |
|
|
37 |
|
|
Total |
|
$ |
445 |
|
$ |
449 |
|
$ |
81 |
|
$ |
94 |
|
NOTE 7. INCOME TAXES
The reconciliation of the statutory federal income tax rate to the effective income tax rate is as follows:
|
For the years ended December 31 |
|
2001 |
|
|
2000 |
|
|
1999 |
|
|
|
Statutory federal income tax rate |
|
35.0 |
% |
|
35.0 |
% |
|
35.0 |
% |
|
|
Depreciation |
|
5.9 |
|
|
6.7 |
|
|
7.0 |
|
|
|
State income taxes -- net of federal income tax benefit |
|
6.4 |
|
|
6.6 |
|
|
6.6 |
|
|
|
Tax credits |
|
(13.7 |
) |
|
(13.0 |
) |
|
(14.9 |
) |
|
|
Income from unconsolidated foreign subsidiaries |
|
(3.0 |
) |
|
(1.8 |
) |
|
(1.0 |
) |
|
|
Other -- net |
|
(1.5 |
) |
|
5.1 |
|
|
(1.5 |
) |
|
|
Effective income tax rate |
|
29.1 |
% |
|
38.6 |
% |
|
31.2 |
% |
|
|
(Dollars in millions) |
|
2001 |
|
|
2000 |
|
|
1999 |
|
||||
|
Current: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
$ |
36 |
|
|
$ |
(8 |
) |
|
$ |
72 |
|
|
|
State |
|
|
60 |
|
|
|
(5 |
) |
|
|
21 |
|
|
|
Foreign |
|
|
11 |
|
|
|
25 |
|
|
|
-- |
|
|
|
Total |
|
|
107 |
|
|
|
12 |
|
|
|
93 |
|
|
|
Deferred: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal |
|
|
104 |
|
|
|
207 |
|
|
|
79 |
|
|
|
State |
|
|
1 |
|
|
|
57 |
|
|
|
15 |
|
|
|
Foreign |
|
|
7 |
|
|
|
(1 |
) |
|
|
-- |
|
|
|
Total |
|
|
112 |
|
|
|
263 |
|
|
|
94 |
|
|
|
Deferred investment tax credits |
|
|
(6 |
) |
|
|
(5 |
) |
|
|
(8 |
) |
|
|
Total income tax expense |
|
$ |
213 |
|
|
$ |
270 |
|
|
$ |
179 |
|
|
|
(Dollars in millions) |
|
2001 |
|
2000 |
||||||||
|
DEFERRED TAX LIABILITIES: |
|
|
|
|
|
|
||||||
|
Differences in financial and tax bases of utility plant |
|
$ |
664 |
|
$ |
730 |
||||||
|
Balancing accounts and other regulatory assets |
|
|
489 |
|
|
521 |
||||||
|
Partnership income |
|
|
37 |
|
|
49 |
||||||
|
Other |
|
|
287 |
|
|
276 |
||||||
|
Total deferred tax liabilities |
|
|
1,477 |
|
|
1,576 |
||||||
|
DEFERRED TAX ASSETS: |
|
|
|
|
|
|
||||||
|
Investment tax credits |
|
|
65 |
|
|
71 |
||||||
|
General business tax credit carryforward |
|
|
24 |
|
|
113 |
||||||
|
Comprehensive Settlement |
|
|
9 |
|
|
26 |
||||||
|
Postretirement benefits |
|
|
36 |
|
|
39 |
||||||
|
Other deferred liabilities |
|
|
174 |
|
|
143 |
||||||
|
Restructuring costs |
|
|
40 |
|
|
51 |
||||||
|
Other |
|
|
212 |
|
|
271 |
||||||
|
Total deferred tax assets |
|
|
560 |
|
|
714 |
||||||
|
Net deferred income tax liability |
|
$ |
917 |
|
$ |
862 |
||||||
|
(Dollars in millions) |
|
2001 |
|
2000 |
||
|
Current liability |
|
$ |
70 |
|
$ |
110 |
|
Noncurrent liability |
|
|
847 |
|
|
752 |
|
Total |
|
$ |
917 |
|
$ |
862 |
The company has not provided for U.S. income taxes on foreign subsidiaries' undistributed earnings ($182 million at December 31, 2001), which are expected to be reinvested outside the U.S. indefinitely. It is not possible to predict the amount of U.S. income taxes that might be payable if these earnings were eventually repatriated.
NOTE 8. EMPLOYEE BENEFIT PLANS
The information presented below covers the plans of the company and its principal subsidiaries.
Pension and Other Postretirement Benefits
The company sponsors several qualified and nonqualified pension plans and other postretirement benefit plans for its employees. Effective March 1, 1999, the Pacific Enterprises Pension Plan merged with the Sempra Energy Cash Balance Plan.
During 2001, SDG&E participated in a voluntary separation program. As a result, the company recorded a $13 million special termination benefit, a $1 million curtailment cost and a $19 million settlement gain.
During 2000, Sempra Energy and most of its subsidiaries participated in another voluntary separation program. As a result, the company recorded a $56 million special termination benefit, a $2 million curtailment credit and a $26 million settlement gain.
The following tables provide a reconciliation of the changes in the plans' benefit obligations and the fair value of assets over the two years, and a statement of the funded status as of each year end:
|
|
Pension Benefits |
Other Postretirement Benefits |
|||||||||||||
|
(Dollars in millions) |
2001 |
|
|
2000 |
|
|
2001 |
|
|
2000 |
|
||||
|
WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
7.25 |
% |
|
|
7.25 |
%(1) |
|
|
7.25 |
% |
|
|
7.25 |
% |
|
Expected return on plan assets |
|
8.00 |
% |
|
|
8.00 |
% |
|
|
7.85 |
% |
|
|
7.85 |
% |
|
Rate of compensation increase |
|
5.00 |
% |
|
|
5.00 |
% |
|
|
5.00 |
% |
|
|
5.00 |
% |
|
Cost trend of covered health-care charges |
|
-- |
|
|
|
-- |
|
|
|
7.25 |
%(2) |
|
|
7.50 |
%(2) |
|
CHANGE IN BENEFIT OBLIGATION: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net benefit obligation at January 1 |
$ |
2,027 |
|
|
$ |
1,962 |
|
|
$ |
551 |
|
|
$ |
555 |
|
|
Service cost |
|
49 |
|
|
|
41 |
|
|
|
11 |
|
|
|
11 |
|
|
Interest cost |
|
141 |
|
|
|
153 |
|
|
|
41 |
|
|
|
37 |
|
|
Actuarial (gain) loss |
|
(27 |
) |
|
|
114 |
|
|
|
13 |
|
|
|
(37 |
) |
|
Curtailments |
|
(7 |
) |
|
|
(7 |
) |
|
|
-- |
|
|
|
5 |
|
|
Settlements |
|
1 |
|
|
|
2 |
|
|
|
-- |
|
|
|
-- |
|
|
Special termination benefits |
|
13 |
|
|
|
54 |
|
|
|
-- |
|
|
|
2 |
|
|
Benefits paid |
|
(187 |
) |
|
|
(292 |
) |
|
|
(26 |
) |
|
|
(22 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net benefit obligation at December 31 |
|
2,010 |
|
|
|
2,027 |
|
|
|
590 |
|
|
|
551 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
|
CHANGE IN PLAN ASSETS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at January 1 |
|
2,910 |
|
|
|
3,427 |
|
|
|
515 |
|
|
|
548 |
|
|
Actual return on plan assets |
|
(277 |
) |
|
|
(247 |
) |
|
|
(37 |
) |
|
|
(25 |
) |
|
Employer contributions |
|
3 |
|
|
|
22 |
|
|
|
17 |
|
|
|
14 |
|
|
Benefits paid |
|
(187 |
) |
|
|
(292 |
) |
|
|
(26 |
) |
|
|
(22 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at December 31 |
|
2,449 |
|
|
|
2,910 |
|
|
|
469 |
|
|
|
515 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
|
Plan assets net of benefit obligation at December 31 |
|
439 |
|
|
|
883 |
|
|
|
(121 |
) |
|
|
(36 |
) |
|
Unrecognized net actuarial gain |
|
(426 |
) |
|
|
(945 |
) |
|
|
(14 |
) |
|
|
(106 |
) |
|
Unrecognized prior service cost |
|
49 |
|
|
|
55 |
|
|
|
(10 |
) |
|
|
(10 |
) |
|
Unrecognized net transition obligation |
|
2 |
|
|
|
2 |
|
|
|
-- |
|
|
|
-- |
|
|
|
|||||||||||||||
|
Net recorded asset (liability) at December 31 |
$ |
64 |
|
|
$ |
(5 |
) |
|
$ |
(145 |
) |
|
$ |
(152 |
) |
|
(1) |
|
Discount rate decreased from 7.75% to 7.25%, effective March 1, 2000. |
|
(2) |
|
Decreasing to ultimate trend of 6.50% in 2004. |
The following table provides the amounts recognized on the Consolidated Balance Sheets (under "sundry," "deferred credits and other liabilities," and "postretirement benefits other than pensions") at December 31:
|
|
|
Pension Benefits |
|
Other Postretirement Benefits |
|
||||||||||||||||||||||||
|
(Dollars in millions) |
|
2001 |
|
|
2000 |
|
|
2001 |
|
|
2000 |
|
|||||||||||||||||
|
Prepaid benefit cost |
|
$ |
146 |
|
|
$ |
75 |
|
|
$ |
-- |
|
|
$ |
-- |
|
|||||||||||||
|
Accrued benefit cost |
|
|
(82 |
) |
|
|
(80 |
) |
|
|
(145 |
) |
|
|
(152 |
) |
|||||||||||||
|
Additional minimum liability |
|
|
(18 |
) |
|
|
(12 |
) |
|
|
-- |
|
|
|
-- |
|
|||||||||||||
|
Intangible asset |
|
|
3 |
|
|
|
4 |
|
|
|
-- |
|
|
|
-- |
|
|||||||||||||
|
Accumulated other comprehensive income, pretax |
|
|
15 |
|
|
|
8 |
|
|
|
-- |
|
|
|
-- |
|
|||||||||||||
|
Net recorded asset (liability) |
|
$ |
64 |
|
|
$ |
(5 |
) |
|
$ |
(145) |
|
|
$ |
(152) |
|
|||||||||||||
|
(Dollars in millions) |
Pension Benefits |
|
|
Other Postretirement Benefits |
|
||||||||||||||||||||||
|
For the years ended December 31, |
2001 |
|
|
2000 |
|
|
1999 |
|
|
2001 |
|
2000 |
|
|
1999 |
|
|||||||||||
|
Service cost |
$ |
49 |
|
|
$ |
41 |
|
|
$ |
48 |
|
|
$ |
11 |
|
$ |
11 |
|
|
$ |
15 |
|
|||||
|
Interest cost |
|
141 |
|
|
|
153 |
|
|
|
142 |
|
|
|
41 |
|
|
37 |
|
|
|
40 |
|
|||||
|
Expected return on assets |
|
(219 |
) |
|
|
(239 |
) |
|
|
(206 |
) |
|
|
(39 |
) |
|
(37 |
) |
|
|
(32 |
) |
|||||
|
Amortization of: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
|
Transition obligation |
|
1 |
|
|
|
1 |
|
|
|
1 |
|
|
|
10 |
|
|
11 |
|
|
|
11 |
|
|||||
|
Prior service cost |
|
6 |
|
|
|
6 |
|
|
|
6 |
|
|
|
(1 |
) |
|
(2 |
) |
|
|
(1 |
) |
|||||
|
Actuarial (gain) loss |
|
(39 |
) |
|
|
(55 |
) |
|
|
(31 |
) |
|
|
(3 |
) |
|
(8 |
) |
|
|
2 |
|
|||||
|
Special termination benefit |
|
13 |
|
|
|
54 |
|
|
|
-- |
|
|
|
-- |
|
|
2 |
|
|
|
-- |
|
|||||
|
Curtailment cost (credit) |
|
1 |
|
|
|
(2 |
) |
|
|
-- |
|
|
|
-- |
|
|
-- |
|
|
|
-- |
|
|||||
|
Settlement credit |
|
(19 |
) |
|
|
(26 |
) |
|
|
-- |
|
|
|
-- |
|
|
-- |
|
|
|
-- |
|
|||||
|
Regulatory adjustment |
|
51 |
|
|
|
18 |
|
|
|
17 |
|
|
|
30 |
|
|
26 |
|
|
|
15 |
|
|||||
|
Total net periodic benefit cost (income) |
$ |
(15 |
) |
|
$ |
(49 |
) |
|
$ |
(23 |
) |
|
$ |
49 |
|
|
$ |
40 |
|
|
$ |
50 |
|
||||
|
(Dollars in millions) |
|
1% Increase |
|
1% Decrease |
|
||
|
Effect on total of service and interest cost components of net periodic postretirement health-care benefit cost |
|
$ |
9 |
|
$ |
(7 |
) |
|
Effect on the health-care component of the accumulated postretirement benefit obligation |
|
$ |
90 |
|
$ |
(71 |
) |
Other postretirement benefits include retiree life insurance, medical benefits for retirees and their spouses, and Medicare Part B reimbursement for certain retirees.
Savings Plans
The company offers savings plans, administered by plan trustees, to all eligible employees. Eligibility to participate in the various employer plans ranges from one month to one year of completed service. Employees may contribute, subject to plan provisions, from one percent to 15 percent of their regular earnings. After one year of completed service, the company begins to make matching contributions. Employer contribution amounts and methodology vary by plan, but generally the contribution is equal to 50 percent of the first 6 percent of eligible base salary contributed by employees. Employer contributions are invested in company stock (new issuances or market purchases) and must remain so invested until termination of employment. At the direction of the employees, the employees' contributions are invested in company stock, mutual funds, institutional trusts or guaranteed investment contracts. Employer contributions for the Sempra Energy and SoCalGas plans are partially funded by the employee stock ownership plan referred to below. Company contributions to the savings plans were $17 million in 2001, $15 million in 2000 and $14 million in 1999. The market value of company stock held by the savings plan was $530 million and $501 million at December 31, 2001 and 2000, respectively.
Employee Stock Ownership Plan
All contributions to the Trust are made by the company; there are no contributions made by the participants.
As the company makes contributions to the ESOP, the ESOP debt service is paid and shares are released in proportion to the total expected debt service. Compensation expense is charged and equity is credited for the market value of the shares released. Income tax deductions are based on the cost of the shares. Dividends on unallocated shares are used to pay debt service and are applied against the liability. The Trust held 2.7 million and 2.8 million shares of Sempra Energy common stock, with fair values of $65.9 million and $65.5 million, at December 31, 2001, and 2000, respectively.
NOTE 9. STOCK-BASED COMPENSATION
Sempra Energy has stock-based compensation plans intended to align employee and shareholder objectives related to the long-term growth of the company. The plans permit a wide variety of stock-based awards, including nonqualified stock options, incentive stock options, restricted stock, stock appreciation rights, performance awards, stock payments and dividend equivalents.
In 2001, 777,500 shares of restricted company stock were awarded to key employees. In 1999, 85,400 shares of restricted company stock were awarded to officers. The corresponding weighted average fair values of the shares granted were $23.37 and $21.00, respectively. There was no restricted company stock awarded in 2000. Subject to earlier forfeitures upon termination of employment, each award vests at the end of seven years, subject to earlier vesting over a four-year period upon satisfaction of objective performance-based goals. Holders of restricted stock have full voting and dividend rights. Compensation expense for the issuance of restricted stock was approximately $5 million in 2001, $1 million in 2000 and $1 million in 1999.
In 2001, 2000 and 1999, Sempra Energy granted to officers and approximately 200 key employees 2,934,800, 4,339,000 and 3,442,400 stock options, respectively. The option price is equal to the market price of common stock at the date of grant. The grants, which vest over a one to four-year period, include options with and without performance-based dividend equivalents. The stock options expire 10 years from the date of grant, subject to earlier expiration upon termination of employment. Compensation expense (or reduction thereof) for the stock option grants (all associated with the options with the dividend equivalents) and similar awards was $7 million, $14 million, and ($13 million) in 2001, 2000 and 1999, respectively.
As of December 31, 2001, 12,805,700 shares were authorized and available for future grants of restricted stock and/or stock options. In addition, on January 1 of each year, additional shares amounting to 1.5 percent of the outstanding shares of Sempra Energy common stock become available for grant.
The plans permit the granting of dividend equivalents, which provide grantees the opportunity to receive some or all of the cash dividends that would have been paid on the shares since the grant date. All grants thus far have made the dividend equivalents dependant on the attainment of certain performance goals. For grants prior to July 1, 1998, payment of the dividend equivalents is also contingent upon an in-the-money exercise of the related options.
In 1995, 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, the company adopted only its disclosure requirements and continues to account for stock-based compensation in accordance with the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees."
Had compensation cost for the stock-based compensation plans been determined based on the fair value at the grant dates for awards under those plans, consistent with the method of SFAS No. 123, net income would have been reduced by $1 million in 2001 and $16 million in 1999. The company's net income (earnings per diluted share) would have been $517 million ($2.52), $429 million ($2.06) and $378 million ($1.59) for 2001, 2000 and 1999, respectively.
STOCK OPTION ACTIVITY
|
|
|
Shares Under Option |
|
|
Average Exercise Price |
|
Options Exercisable at December 31 |
||
|
OPTIONS WITH DIVIDEND EQUIVALENTS |
|
|
|
|
|
|
|
|
|
|
December 31, 1998 |
|
3,596,660 |
|
|
$ |
22.06 |
|
1,387,523 |
|
|
Granted |
|
1,451,100 |
|
|
|
21.00 |
|
|
|
|
Exercised |
|
(254,886 |
) |
|
|
17.32 |
|
|
|
|
Cancelled |
|
(99,677 |
) |
|
|
23.34 |
|
|
|
|
|
|
|
|
|
|
|
|||
|
December 31, 1999 |
|
4,693,197 |
|
|
|
21.96 |
|
1,844,079 |
|
|
Exercised |
|
(399,875 |
) |
|
|
18.91 |
|
|
|
|
Cancelled |
|
(264,749 |
) |
|
|
23.39 |
|
|
|
|
|
|
|
|
|
|
|
|||
|
December 31, 2000 |
|
4,028,573 |
|
|
|
22.17 |
|
2,462,574 |
|
|
Exercised |
|
(588,315 |
) |
|
|
20.92 |
|
|
|
|
Cancelled |
|
(119,911 |
) |
|
|
22.46 |
|
|
|
|
|
|
|
|
|
|
|
|||
|
December 31, 2001 |
|
3,320,347 |
|
|
$ |
22.38 |
|
2,508,328 |
|
|
OPTIONS WITHOUT DIVIDEND EQUIVALENTS |
|
|
|
|
|
|
|
|
|
|
December 31, 1998 |
|
2,030,232 |
|
|
$ |
24.28 |
|
523,661 |
|
|
Granted |
|
1,991,300 |
|
|
|
21.00 |
|
|
|
|
Exercised |
|
(12,781 |
) |
|
|
15.20 |
|
|
|
|
Cancelled |
|
(55,746 |
) |
|
|
23.25 |
|
|
|
|
|
|
|
|
|
|
|
|||
|
December 31, 1999 |
|
3,953,005 |
|
|
|
22.67 |
|
1,019,056 |
|
|
Granted |
|
4,339,000 |
|
|
|
19.03 |
|
|
|
|
Exercised |
|
(329,313 |
) |
|
|
19.10 |
|
|
|
|
Cancelled |
|
(397,271 |
) |
|
|
25.07 |
|
|
|
|
|
|
|
|
|
|
|
|||
|
December 31, 2000 |
|
7,565,421 |
|
|
|
20.61 |
|
1,659,244 |
|
|
Granted |
|
2,934,800 |
|
|
|
22.50 |
|
|
|
|
Exercised |
|
(421,633 |
) |
|
|
18.79 |
|
|
|
|
Cancelled |
|
(204,134 |
) |
|
|
23.59 |
|
|
|
|
|
|
|
|
|
|
|
|||
|
December 31, 2001 |
|
9,874,454 |
|
|
$ |
21.19 |
|
3,143,319 |
|
|
Range of Exercise Prices |
|
Number of Shares |
|
Average Remaining Life |
|
Average Exercise Price |
|
|
Outstanding Options |
|
|
|
|
|
|
|
|
$12.80-$16.12 |
|
233,200 |
|
2.96 |
|
$ |
15.55 |
|
$17.00-$22.65 |
|
10,305,913 |
|
7.98 |
|
$ |
20.46 |
|
$24.27-$27.31 |
|
2,655,688 |
|
6.66 |
|
$ |
25.97 |
|
|
|
13,194,801 |
|
7.62 |
|
$ |
21.48 |
|
Exercisable Options |
|
|
|
|
|
|
|
|
$12.80-$16.12 |
|
233,200 |
|
|
|
$ |
15.55 |
|
$17.00-$22.65 |
|
3,334,313 |
|
|
|
$ |
19.82 |
|
$24.27-$27.31 |
|
2,084,134 |
|
|
|
$ |
25.86 |
|
|
|
|
|
|
|
|
|
|
|
|
5,651,647 |
|
|
|
$ |
21.87 |
The assumptions that were used to determine these grant-date market values are as follows:
|
|
|
2001 |
|
2000 |
|
1999 |
|
Stock price volatility |
|
24% |
|
20% |
|
19% |
|
Risk-free rate of return |
|
4.6% |
|
6.8% |
|
5.5% |
|
Annual dividend yield* |
|
4.3% |
|
5.4% |
|
6.11% |
|
Expected life |
|
6 Years |
|
6 Years |
|
6 Years |
|
* |
|
The assumed yield for the options that include dividend equivalents is zero. |
NOTE 10. FINANCIAL INSTRUMENTS
Fair Value
|
|
|
2001 |
2000 |
||||||||||||
|
|
|
Carrying Amount |
|
Fair Value |
|
Carrying Amount |
|
Fair Value |
|||||||
|
Investments in limited partnerships |
|
$ |
317 |
|
$ |
272 |
|
$ |
365 |
|
$ |
345 |
|||
|
|
|||||||||||||||
|
First-mortgage bonds |
|
$ |
1,274 |
|
$ |
1,297 |
|
$ |
1,364 |
|
$ |
1,361 |
|||
|
Notes payable |
|
|
1,300 |
|
|
1,327 |
|
|
800 |
|
|
814 |
|||
|
SDG&E rate - reduction bonds |
|
|
395 |
|
|
411 |
|
|
461 |
|
|
462 |
|||
|
Debt incurred to acquire limited partnerships |
|
|
187 |
|
|
147 |
|
|
233 |
|
|
188 |
|||
|
Other long-term debt |
|
|
528 |
|
|
545 |
|
|
794 |
|
|
807 |
|||
|
Total long-term debt |
|
$ |
3,684 |
|
$ |
3,727 |
|
$ |
3,652 |
|
$ |
3,632 |
|||
|
|
|||||||||||||||
|
Preferred stock of subsidiaries |
|
$ |
204 |
|
$ |
162 |
|
$ |
204 |
|
$ |
146 |
|||
|
|
|||||||||||||||
|
Mandatorily redeemable trust preferred securities |
|
$ |
200 |
|
$ |
214 |
|
$ |
200 |
|
$ |
188 |
|||
Accounting for Derivative Instruments and Hedging Activities
Effective January 1, 2001, the company adopted SFAS 133, as amended by SFAS 138 "Accounting for Certain Derivative Instruments and Certain Hedging Activities." As amended, SFAS 133 requires that an entity recognize all derivative instruments as either assets or liabilities in the statement of financial position, measure the instruments at fair value and recognize changes in the fair value of derivatives in earnings in the period of change unless the derivative instrument qualifies as an effective hedge that offsets certain exposures.
At December 31, 2001, $57 million in current assets, $27 million in noncurrent assets, $195 million in current liabilities and $835 million in noncurrent liabilities were recorded in the Consolidated Balance Sheets for fixed-priced contracts and other derivatives. Regulatory assets and liabilities were established to the extent that derivative gains and losses are recoverable or payable through future rates. As such, $193 million in current regulatory assets, $830 million in noncurrent regulatory assets, $50 million in regulatory balancing account liabilities, $4 million in current regulatory liabilities and $1 million in noncurrent regulatory liabilities were recorded in the Consolidated Balance Sheets as of December 31, 2001. The remaining $22 million was a market value adjustment to long-term debt related to two fixed-to-floating interest rate swaps. There was not a material impact to the Statements of Consolidated Income.
Changes in the fair value of derivative instruments have been recognized in the classification shown below (dollars in millions):
|
|
|
2001 |
|
2000 |
|
1999 |
|||
|
Other operating revenues |
|
$ |
1,035 |
|
$ |
795 |
|
$ |
450 |
|
Cost of natural gas distributed |
|
$ |
53 |
|
$ |
72 |
|
$ |
-- |
Market Risk
Interest-Rate Risk Management
The company periodically enters into interest-rate swap agreements to moderate exposure to interest-rate changes and to lower the overall cost of borrowing. At December 31, 2001, the company had three such agreements. SDG&E has an interest-rate swap agreement that matures in 2002 and effectively fixes the interest rate on $45 million of variable-rate underlying debt at 5.4 percent. This floating- to-fixed-rate swap does not qualify for hedge accounting and, therefore, the gains and losses associated with the change in fair value are recorded in the Statements of Consolidated Income. For the year ended December 31, 2001, the effect on income was a $1 million loss. Although this financial instrument does not meet the hedge accounting criteria of SFAS 133, it continues to be effective in achieving the risk management objectives for which it was intended.
The remaining two agreements are fixed-to-floating-rate swaps. The company has one such agreement on $500 million of underlying debt which matures in 2004 and effectively causes the interest rate on the debt to vary at the weighted-average rate of LIBOR plus 1.329 percent. SoCalGas has the other agreement, which is a cancelable-call interest-rate swap, exchanging a fixed rate obligation of 6.875 percent on its $175 million first-mortgage bonds, maturing in 2025, for a floating rate of LIBOR plus 4 basis points. The transaction may be canceled every 5 years by either party by payment of the mark-to-market value, or may be canceled by the counterparty at any time the bonds are callable, by payment to SoCalGas of the applicable call premium on the bonds. The company believes both swaps are fully effective in their purpose of converting the fixed rate stated in the debt to a floating rate and the swaps meet the criteria for accounting under the short-cut method defined in SFAS No. 133 for fair value hedges o f debt instruments. Accordingly, a market value adjustment of $22 million (as discussed above) was recorded in long-term debt at December 31, 2001 and no net gains or losses were recorded in income related to these swaps.
Energy Derivatives
The company utilizes derivative financial instruments to reduce its exposure to unfavorable changes in energy prices, which are subject to significant and often volatile fluctuation. Derivative financial instruments are comprised of futures, forwards, swaps, options and long-term delivery contracts. These contracts allow the company to predict with greater certainty the effective prices to be received and, in the case of the California utilities, the prices to be charged to their customers. See Note 2 of the notes to Consolidated Financial Statements for discussion of how these derivatives are classified under SFAS 133.
Energy Contracts
The California utilities record gas and electric energy contracts in "Cost of gas distributed" and "Electric fuel and net purchased power," respectively, in the Statements of Consolidated Income. For open contracts not expected to result in physical delivery, changes in market value of the contracts are recorded in these accounts during the period the contracts are open, with an offsetting entry to a regulatory asset or liability. The company's trading operations include the net effects of its contracts in trading revenues. The majority of the California utilities' contracts result in physical delivery, which is less frequent at the trading operations.
Sempra Energy Trading and Sempra Energy Solutions
SET derives a substantial portion of its revenue from market making and trading activities, as a principal, in natural gas, electricity, petroleum, petroleum products and other commodities, for which it quotes bid and asked prices to other market makers and end users. 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 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 SET. For the year ended December 31, 2001, substantially all of SET's derivative transactions were held for trading and marketing purposes. Sempra Energy guarantees many of SET's transactions.
SES derives a portion of its revenue from delivering electric and gas supplies to its commercial and industrial customers. Such contracts are hedged to preserve margin and carry minimal market risk. Exchange-traded and over-the-counter instruments are used to hedge contracts. The derivatives and financial instruments used to hedge the transactions include swaps, forwards, futures, options or combinations thereof.
Both SET and SES mark these derivatives to market daily, with gains and losses recognized in earnings. These instruments are included in the Consolidated Balance Sheets as energy trading assets or liabilities. Certain instruments, such as swaps, are entered into and closed out within the same period. SET records net gains and losses on these derivative transactions in other operating revenues in the Statements of Consolidated Income. For SES, unrealized gains or losses are also included in other operating revenues. As transactions are settled, SES records the realized retail contracts as revenues while wholesale contracts and related financial instruments are recognized as other operating expenses.
At SET, market risk arises from the potential for changes in the value of financial instruments resulting from fluctuations in natural gas, electricity, petroleum, petroleum products and other commodities exchange prices and basis. Market risk is also affected by changes in volatility and liquidity in markets in which these instruments are traded. Market risk for SES from fluctuations in natural gas or electricity prices is minimized by SES' hedging strategy as described above.
SET also carries an inventory of financial instruments. Market making and proprietary positions are managed in concert in order to maximize trading profits due to the close relationship between commodities and the related financial instruments.
SET's credit risk from financial instruments as of December 31, 2001, is represented by the positive fair value of financial instruments after consideration of collateral. Credit risk, however, relates to the net losses that would be recognized if all counterparties failed completely to perform their obligations. Options written do not expose SET 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. For SES, credit risk is associated with its retail customers.
The following table summarizes the counterparty credit quality and exposure for SET and SES at December 31, 2001 expressed in terms of net replacement value (dollars in millions). These exposures are net of collateral in form of customer margin and/or letters of credit of $175 million:
|
Counterparty credit quality: |
|
Total |
||
|
SET: |
|
|
|
|
|
Commodity Exchanges |
|
$ |
133 |
|
|
AAA |
|
|
53 |
|
|
AA |
|
|
105 |
|
|
A |
|
|
577 |
|
|
BBB |
|
|
476 |
|
|
Below investment grade |
|
|
335 |
|
|
|
|
|
|
|
|
Total |
|
$ |
1,679 |
|
|
|
|
|
|
|
|
SES: |
|
|
|
|
|
AA |
|
$ |
4 |
|
|
A |
|
|
18 |
|
|
BBB |
|
|
7 |
|
|
Below investment grade and not rated |
|
|
190 |
|
|
|
|
|
|
|
|
|
|
$ |
218 |
|
Energy trading assets and liabilities are recorded on a trade-date basis and adjusted daily to current value, and include amounts due from commodity clearing organizations, amounts due to/from trading counterparties, unrealized gains and losses from exchange traded futures and options, and 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 liquidation of these contracts under current market conditions. Unrealized gains and losses on OTC transactions are reported separately as assets and liabilities unless a legal right of setoff exists.
Based on quarterly measurements, the average fair values during 2001 for energy trading assets and liabilities approximate $3.0 billion and $2.2 billion, respectively.
The carrying value of energy trading assets and energy trading liabilities approximate the following:
|
December 31 (Dollars in millions) |
|
2001 |
|
2000 |
|||
|
ENERGY TRADING ASSETS |
|
|
|
|
|
|
|
|
Unrealized gains on swaps and forwards |
|
$ |
1,674 |
|
$ |
2,647 |
|
|
OTC commodity options purchased |
|
|
425 |
|
|
684 |
|
|
Due from trading counterparties |
|
|
343 |
|
|
653 |
|
|
Due from commodity clearing organizations and clearing brokers |
|
|
133 |
|
|
99 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
2,575 |
|
$ |
4,083 |
|
|
|
|
|
|
|
|
|
|
|
ENERGY TRADING LIABILITIES |
|
|
|
|
|
|
|
|
Unrealized losses on swaps and forwards |
|
$ |
1,340 |
|
$ |
2,590 |
|
|
OTC commodity options written |
|
|
290 |
|
|
612 |
|
|
Due to trading counterparties |
|
|
163 |
|
|
417 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,793 |
|
$ |
3,619 |
|
Notional amounts do not necessarily represent the amounts exchanged by parties to the financial instruments and do not measure SET's or SES'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, both companies are exposed to much smaller amounts.
The notional amounts of SET's and SES's financial instruments at December 31 were:
|
(Dollars in millions) |
|
2001 |
|
2000 |
||
|
Forwards and commodity swaps |
|
$ |
33,597 |
|
$ |
45,656 |
|
Options purchased |
|
|
21,542 |
|
|
13,496 |
|
Options written |
|
|
18,253 |
|
|
13,799 |
|
Futures and exchange options |
|
|
4,721 |
|
|
3,117 |
|
|
|
|
|
|
|
|
|
Total |
|
$ |
78,113 |
|
$ |
76,068 |
NOTE 11. PREFERRED STOCK OF SUBSIDIARIES
|
December 31 (Dollars in millions except call price) |
|
Call Price |
|
2001 |
|
2000 |
||||
|
Pacific Enterprises (not subject to mandatory redemption): |
|
|
|
|
|
|
|
|
|
|
|
Without par value, authorized 15,000,000 shares: |
|
|
|
|
|
|
|
|
|
|
|
$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 |
|
|
-- |
|
|
-- |
|
|
|
|
|
||||||||
|
Total |
|
|
|
|
|
80 |
|
|
80 |
|
|
|
|
|
||||||||
|
SoCalGas (not subject to mandatory redemption): |
|
|
|
|
|
|
|
|
|
|
|
$25 par value, authorized 1,000,000 shares: |
|
|
|
|
|
|
|
|
|
|
|
6% Series, 28,049 shares outstanding |
|
|
|
|
|
1 |
|
|
1 |
|
|
6% Series A, 783,032 shares outstanding |
|
|
|
|
|
19 |
|
|
19 |
|
|
Without par value, authorized 10,000,000 shares |
|
|
|
|
|
-- |
|
|
-- |
|
|
|
|
|
||||||||
|
Total |
|
|
|
|
|
20 |
|
|
20 |
|
|
|
|
|
||||||||
|
SDG&E: |
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
||||||||
|
Total |
|
|
|
|
$ |
204 |
|
$ |
204 |
|
None of SoCalGas' preferred stock is callable. All series have one vote per share and cumulative preferences as to dividends, and have a liquidation value of $25 per share, plus any unpaid dividends. In addition, the 6% Series preferred stock would also share pro rata with common stock in the remaining assets.
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, plus any unpaid dividends. SDG&E is authorized to issue 10,000,000 shares of no-par-value preferred stock (both subject to and not subject to mandatory redemption). All series are currently callable except for the $1.70 and $1.7625 Series (callable in 2003). 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.
Mandatorily Redeemable Trust Preferred Securities
On February 23, 2000, a wholly owned subsidiary trust of the company issued 8,000,000 shares of preferred stock in the form of 8.90-percent Cumulative Quarterly Income Preferred Securities, Series A (QUIPS). The QUIPS have cumulative preferences as to distributions, are nonvoting and have a par and liquidation value of $25 per share. Cash dividends are paid quarterly and the QUIPS mature on February 23, 2030, subject to extension to a date not later than February 23, 2049, and shortening to a date not earlier than February 23, 2015. The QUIPS are subject to mandatory redemption and the company has guaranteed payments to the extent that the trust does not have funds available to make distributions. The trust has no assets except its corresponding receivable from Sempra Energy. The QUIPS are callable on or after February 23, 2005 and there are no sinking fund provisions. The QUIPS are reflected as "Mandatorily redeemable trust preferred securities" on the company's Consolidated Balance Sheets and cash dividend payments are shown as "Trust preferred distributions by subsidiary" on the company's Statements of Consolidated Income. Proceeds of this issuance, together with $500 million of long-term 7.95% notes due 2010 (see Note 5), were used to finance substantially all of the tender offer referred to in Note 12.
NOTE 12. SHAREHOLDERS' EQUITY AND EARNINGS PER SHARE
The only difference between basic and diluted earnings per share is the effect of common stock options. For 2001, 2000 and 1999, the effect of dilutive options was equivalent to an additional 1,745,000, 190,000 and 308,000 shares, respectively, using the treasury stock method, whereby the proceeds from the exercise price are assumed to be used to repurchase shares on the open market at the average market price for the year. This excludes options covering 2.1 million shares, 6.6 million shares and 3.3 million shares for 2001, 2000 and 1999, respectively, for which the exercise price was greater than the average market price for common stock during the respective periods.
The company is authorized to issue 750,000,000 shares of no-par-value common stock and 50,000,000 shares of Preferred Stock. Excluding shares held by the ESOP, common stock activity consisted of the following:
|
|
|
2001 |
|
|
2000 |
|
|
1999 |
|
|
|
Common shares outstanding, January 1 |
|
201,927,524 |
|
|
237,408,051 |
|
|
236,956,683 |
|
|
|
Stock options exercised |
|
1,009,948 |
|
|
729,188 |
|
|
267,667 |
|
|
|
Long-term incentive plan |
|
777,500 |
|
|
-- |
|
|
85,400 |
|
|
|
Common stock investment plan* |
|
761,154 |
|
|
-- |
|
|
-- |
|
|
|
Shares released from ESOP |
|
134,645 |
|
|
125,848 |
|
|
126,721 |
|
|
|
Shares repurchased |
|
(60,000 |
) |
|
(36,304,740 |
) |
|
-- |
|
|
|
Shares forfeited and other |
|
(75,409 |
) |
|
(30,823 |
) |
|
(28,420 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares outstanding, December 31 |
|
204,475,362 |
|
|
201,927,524 |
|
|
237,408,051 |
|
|
|
|
* |
|
In 2001 participants in the Direct Stock Purchase Plan reinvested dividends and purchased newly issued shares. In 1999 and 2000 open-market shares were used. |
Tender Offer
On February 25, 2000, the company completed a self-tender offer, purchasing 36.1 million shares of its outstanding common stock at $20 per share. In March 2000, the company's board of directors authorized the optional expenditure of up to $100 million to repurchase additional shares of common stock from time to time in the open market or in privately negotiated transactions. The company acquired 60,000 shares and 162,400 shares under this authorization in 2001 and 2000, respectively.
NOTE 13. COMMITMENTS AND CONTINGENCIES
Natural Gas Contracts
SoCalGas has commitments for firm pipeline capacity under contracts with pipeline companies that expire at various dates through 2006.
SDG&E has long-term natural gas transportation contracts with various interstate pipelines which expire on various dates between 2003 and 2023. SDG&E has a long-term purchase agreement with a Canadian supplier that expires in August 2003, and in which the delivered cost is tied to the California border spot-market price. SDG&E purchases natural gas on a spot basis to fill its additional long-term pipeline capacity. SDG&E intends to continue using the long-term pipeline capacity in other ways as well, including the transport of other natural gas for its own use and the release of a portion of this capacity to third parties.
At December 31, 2001, the future minimum payments under natural gas contracts were:
|
(Dollars in millions) |
|
Storage and Transportation |
|
Natural Gas |
||
|
2002 |
|
$ |
181 |
|
$ |
468 |
|
2003 |
|
|
183 |
|
|
174 |
|
2004 |
|
|
188 |
|
|
-- |
|
2005 |
|
|
184 |
|
|
-- |
|
2006 |
|
|
105 |
|
|
-- |
|
Thereafter |
|
|
155 |
|
|
-- |
|
|
|
|
||||
|
Total minimum payments |
|
$ |
996 |
|
$ |
642 |
Purchased-Power Contracts
SDG&E buys electric power under several long-term contracts. The contracts expire on various dates between 2003 and 2025. Prior to the electric rate ceiling described in Note 14, the above-market cost of contracts was recovered from SDG&E's customers. In general, the market value of these contracts was recovered by bidding them into the California Power Exchange (PX) and receiving revenue from the PX for bids accepted. As of January 1, 2001, in compliance with a FERC order prohibiting sales to the PX, SDG&E no longer bids those contracts into the PX. Those contracts are now used to serve customers in compliance with a CPUC order. In late 2000, SDG&E entered into additional contracts to serve customers instead of buying all of its power from the PX. These contracts expire in 2003.
At December 31, 2001, the estimated future minimum payments under the long-term contracts were:
|
(Dollars in millions) |
|
|
|
|
2002 |
|
$ |
224 |
|
2003 |
|
|
218 |
|
2004 |
|
|
172 |
|
2005 |
|
|
173 |
|
2006 |
|
|
170 |
|
Thereafter |
|
|
2,000 |
|
|
|||
|
Total minimum payments |
|
$ |
2,957 |
On January 17, 2001, the California Assembly passed a bill (AB1) to allow the DWR to purchase power under long-term contracts for the benefit of California consumers. In accordance with AB1, SDG&E entered into an agreement with DWR under which DWR purchases SDG&E's full net short position (the power needed by SDG&E's customers, other than that provided by SDG&E's nuclear generating facilities or its previously existing purchase power contracts) through December 31, 2002. The CPUC is conducting proceedings intended to establish guidelines and procedures for the eventual resumption of electricity procurement by SDG&E and the other California IOUs. For additional discussion of this matter see Note 14.
Leases
The company has leases (primarily operating) on real and personal property expiring at various dates from 2002 to 2045. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 2 percent to 7 percent. The rentals payable under these leases are determined on both fixed and percentage bases, and most leases contain extension options which are exercisable by the company. The company also has long-term capital leases on real property. Property, plant and equipment includes $35 million at December 31, 2001, and $92 million at December 31, 2000, related to these leases. The associated accumulated amortization is $18 million and $55 million, respectively. The decreases in 2001 resulted from SDG&E's terminating its capital lease agreement for nuclear fuel in mid-2001. SDG&E now owns its nuclear fuel.
At December 31, 2001, the minimum rental commitments payable in future years under all noncancellable leases were:
|
(Dollars in millions) |
|
Operating Leases |
|
Capitalized Leases |
|
|||
|
2002 |
|
$ |
66 |
|
$ |
7 |
|
|
|
2003 |
|
|
74 |
|
|
3 |
|
|
|
2004 |
|
|
98 |
|
|
3 |
|
|
|
2005 |
|
|
94 |
|
|
2 |
|
|
|
2006 |
|
|
92 |
|
|
1 |
|
|
|
Thereafter |
|
|
1,183 |
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total future rental commitment |
|
$ |
1,607 |
|
|
17 |
|
|
|
Imputed interest (9% to 15%) |
|
|
|
|
|
(3 |
) |
|
|
|
|
|
|
|
||||
|
Net commitment |
|
|
|
|
$ |
14 |
|
|
Rent expense totaled $92 million in 2001, $102 million in 2000 and $108 million in 1999.
Other Commitments and Contingencies
In October 2001, SEI and CMS Energy Corporation announced plans to jointly develop a liquefied natural gas (LNG) receiving facility on a 300-acre site along Baja California's Pacific coast near Ensenada, Mexico. The joint venture will develop the $400 million facility and related port infrastructure, which is expected to provide one billion cubic feet per day of natural gas. SEI has entered into a memorandum of understanding with a Bolivian consortium for the potential supply of LNG to the facility. Commercial operation of the facility is scheduled to begin in late 2005. As of December 31, 2001, no contractual commitments existed yet.
In February 2001, the company announced plans to construct Termoelectrica de Mexicali, a $350 million, 600-megawatt power plant near Mexicali, Mexico. Fuel for the plant will be supplied via the planned pipeline from Arizona to Tijuana referred to below. It is anticipated that the electricity produced by the plant will be exported for consumption in the United States via the 230,000-volt transmission line which is also under construction. Construction of the power plant began in the second half of 2001. $135 million has been invested in the project, which is scheduled for completion by mid-2003. As of December 31, 2001, SER has additional commitments of $135 million related to the purchase of steam and gas turbine generators and engineering and procurement services.
In December 2000, SER obtained approvals from the appropriate state agencies to construct the Elk Hills Power Project, a $410 million 570-megawatt power plant near Bakersfield, California. Elk Hills is being developed in a 50/50 joint venture with Occidental Energy Ventures Corporation and will supply electricity to California. As of December 31, 2001, SER has invested $133 million in the project and has commitments of approximately $70 million. The project is anticipated to be completed during the first half of 2003. Information concerning litigation with Occidental is provided below.
In December 2000, SER obtained approval from the appropriate state agencies to construct the Mesquite Power Plant (Mesquite Power). Located near Phoenix, Arizona, Mesquite Power is a $700 million, 1,200-megawatt project which will provide electricity to wholesale energy markets in the Southwest. Construction began in March 2001, and completion is anticipated by 2003. Expenditures as of December 31, 2001 are $259 million and SER has commitments of $337 million related to this project. Expenditures have been financed through a synthetic lease agreement. However, additional financing under the synthetic lease would require obtaining additional bank commitments or the posting of U.S. Treasury obligations in similar amounts.
SER, as construction agent for the lessor, is responsible for completing construction in a timely manner. Upon completion of the project, SER is required to make lease payments to the lessor in an amount sufficient to provide a specified return to the investors. In 2005, SER has the option to extend the lease at fair market value, purchase the project at a fixed amount, or act as remarketing agent for the lessor to sell the project. If SER elects the remarketing option, it may be required to pay the lessor up to 85 percent of the project cost if the proceeds from remarketing are insufficient to repay the lessor's investors. The lease is guaranteed by Sempra Energy and the availability of additional financing is conditioned upon Sempra Energy's continuing to have credit ratings of at least BBB- by S&P or Baa3 by Moody's. The lease also requires Sempra Energy to maintain a debt-to-total capitalization ratio, (as defined in the lease), of not to exceed 65%. As a synthetic lease, neither the asset nor th e liability is included on the Consolidated Balance Sheets. If they were, assets and long-term debt would have been increased by $225 million at December 31, 2001, reflecting costs incurred on the project, all in 2001.
As of December 31, 2001, SER has invested $100 million for gas turbines and other power plant projects. SER has additional commitments related to these projects of $125 million.
In May 2001, SER entered into a ten-year agreement with the DWR to supply up to 1,900 megawatts of power to the state. SER intends to deliver most of this electricity from its projected portfolio of plants in the western United States and Baja California, Mexico. Sales under the contract comprise more than two-thirds of the projected capacity of these facilities and the profits therefrom are significant to the company's ability to increase its earnings. Subsequent to the state's signing of this contract and electricity-supply contracts with other vendors, various state officials have contended that the rates called for by the contracts are too high. These rates substantially exceed current spot-market prices for electricity, but are substantially lower than those prevailing at the time the contracts were signed. In February 2002, the CPUC and the California Electricity Oversight Board petitioned the Federal Energy Regulatory Commission to determine that the contracts do not provide just and reasonable ra tes, and to abrogate or reform the contracts. The company believes that the contract prices were fair, but has offered to renegotiate certain aspects of the contract (which would not affect the long-term profitability) in a manner mutually beneficial to SER and the state.
In June 2000, SEI and PG&E Corporation announced a joint agreement to construct the North Baja Pipeline, a $230 million, 215-mile natural gas pipeline which will extend from Arizona to the Rosarito Pipeline south of Tijuana and supply natural gas to new and existing power plants and to industrial customers in northern Baja California, including SER's Termoelectrica de Mexicali plant discussed above. SEI will construct, own and operate the Mexican portion of the pipeline ($130 million and 135 miles) and has invested approximately $75 million through 2001. PG&E's National Energy Group is responsible for the U.S. segment of the operations and is entitled to the operating income or losses stemming therefrom. As of December 31, 2001, SEI has commitments of $25 million related to this project. Completion of SEI's portion of the project is contemplated for the summer of 2002.
In December 1999, Sempra Atlantic Gas (SAG), a subsidiary of SEI, was awarded a 25-year franchise by the provincial government of Nova Scotia to build and operate a natural gas distribution system in Nova Scotia. In September 2001, due to new conditions required by the government of Nova Scotia, SAG notified the government that it intended to surrender its natural gas distribution franchise. SAG had invested $30 million through September 2001 and has expensed the costs believed to be nonrecoverable.
Environmental Issues
The company's operations are subject to federal, state and local environmental laws and regulations governing hazardous wastes, air and water quality, land use, solid waste disposal and the protection of wildlife. Most of the environmental issues faced by the company occur at the California utilities. However, as SER constructs new power plants, additional environmental issues will arise requiring the company's attention. As applicable, appropriate and relevant, these laws and regulations require that the company investigate and remediate the effects of the release or disposal of materials at sites associated with past and present operations, including sites at which the company has been identified as a Potentially Responsible Party under the federal Superfund laws and comparable state laws. Costs incurred to operate the facilities in compliance with these laws and regulations generally have been recovered in customer rates.
Costs that mitigate or prevent future environmental contamination or extend the life, increase the capacity or improve the safety or efficiency of property utilized in current operations are capitalized. The company's capital expenditures to comply with environmental laws and regulations were $6 million in 2001, $4 million in 2000 and $2 million in 1999. The increase in 2001 is due to purchases of endangered species habitat land to mitigate the impact of the construction of a new transmission line and the installation of air quality control equipment at a compressor station and at various storage fields. The increase in 2000 was due to the installation of air quality control equipment on another compressor facility. The cost of compliance with these regulations over the next five years is not expected to be significant.
Costs that relate to current operations or an existing condition caused by past operations are generally recorded as a regulatory asset due to the assurance that these costs will be recovered in rates. In 1994, the CPUC approved the Hazardous Waste Collaborative Memorandum account, allowing California's energy utilities to recover their hazardous waste cleanup costs, including those related to Superfund sites or similar sites requiring cleanup. Cleanup costs at electric generation related sites were specifically excluded from the collaborative by the CPUC. Recovery of 90 percent of hazardous waste cleanup costs and related third-party litigation costs and 70 percent of the related insurance-litigation expenses is permitted. In addition, the company has the opportunity to retain a percentage of any insurance recoveries to offset the 10 percent of costs not recovered in rates.
The environmental issues currently facing the company or resolved during the latest three-year period include investigation and remediation of the California utilities' manufactured-gas sites (21 completed as of December 31, 2001, and 24 to be completed), cleanup at SDG&E's former fossil fuel power plants (all sold in 1999 and actual or estimated cleanup costs included in the transactions), cleanup of third-party waste-disposal sites used by the company, which has been identified as a Potentially Responsible Party (investigations and remediations are continuing), and mitigation of damage to the marine environment caused by the cooling-water discharge from the San Onofre Nuclear Generating Station (the requirements for enhanced fish protection, a 150-acre artificial reef and restoration of 150 acres of coastal wetlands are in process).
Environmental liabilities are recorded when the company's liability is probable and the costs are reasonably estimable. In many cases, however, investigations are not yet at a stage where the company has been able to determine whether it is liable or, if liability is probable, to reasonably estimate the amount or range of amounts of the cost or certain components thereof. Estimates of the company's liability are further subject to other uncertainties, such as the nature and extent of site contamination, evolving remediation standards and imprecise engineering evaluations. The accruals are reviewed periodically and, as investigations and remediation proceed, adjustments are made as necessary. At December 31, 2001, the company's accrued liability for environmental matters was $65 million, of which approximately $52 million related to manufactured-gas sites, $10 million related to cleanup at SDG&E's former fossil-fueled power plants and $3 million related to waste-disposal sites used by the company (which has been identified as a Potentially Responsible Party). The accruals for the manufactured-gas and waste-disposal sites are expected to be paid ratably over the next five years. The accruals for SDG&E's former fossil-fueled power plants are expected to be paid ratably over the next two years. There are no circumstances currently known to management that would require adjustment to the accruals.
Nuclear Insurance
SDG&E and the co-owners of SONGS have purchased primary insurance of $200 million, the maximum amount available, for public-liability claims. An additional $9.3 billion of coverage is provided by secondary financial protection required by the Nuclear Regulatory Commission and provides for loss sharing among utilities owning nuclear reactors if a costly accident occurs. SDG&E could be assessed retrospective premium adjustments of up to $36 million in the event of a nuclear incident involving any of the licensed, commercial reactors in the United States, if the amount of the loss exceeds $200 million. In the event the public-liability limit stated above is insufficient, the Price-Anderson Act provides for Congress to enact further revenue-raising measures to pay claims, 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 12 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 $7 million.
Both the public-liability and property insurance (including replacement power coverage) include coverage for losses resulting from acts of terrorism. This includes the risk-sharing arrangement with other nuclear facilities.
Department Of Energy Decommissioning
The Energy Policy Act of 1992 established a fund for the decontamination and decommissioning of the Department of Energy (DOE) nuclear fuel enrichment facilities. Utilities which have used DOE enrichment services are being assessed 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 through 1992. SDG&E's annual assessment is approximately $1 million. This assessment is recovered through SONGS revenue.
Department Of Energy Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 made the DOE responsible for the disposal of spent nuclear fuel. However, it is uncertain when the DOE will begin accepting spent nuclear fuel from SONGS. Continued delays by the DOE can lead to increased cost of disposal, which could be significant. If this occurs and the company is unable to recover the increased costs from the federal government or from its customers, the company's profitability from SONGS would be adversely affected.
Litigation
Lawsuits filed in 2000 and currently consolidated in San Diego Superior Court seek class-action certification and allege that Sempra Energy, SoCalGas, SDG&E and El Paso Energy Corp. acted to drive up the price of natural gas for Californians by agreeing to stop a pipeline project that would have brought new and less-expensive natural gas supplies into California. Management believes the allegations are without merit.
Various 2000 lawsuits, which seek class-action certification and which have been consolidated in San Diego Superior Court, allege that company subsidiaries unlawfully manipulated the electric-energy market. Management believes the allegations are without merit.
SET is a defendant in the action brought by the FERC concerning rates charged certain utilities by sellers of electricity (see FERC Actions in Note 14).
SER is a defendant in an action brought by its joint venture partner, Occidental Energy Ventures (Occidental), concerning the Elk Hills power project that the companies are developing. The lawsuit alleges breach of contract and Occidental claims that SER misrepresented that the entire output of the power plant would be committed to providing power under the contract between SER and the DWR. Management believes the allegations are without merit.
Except for the matters referred to above, neither the company nor its subsidiaries are party to, nor is their property the subject of, any material pending legal proceedings other than routine litigation incidental to their businesses. Management believes that these matters will not have a material adverse effect on the company's financial condition or results of operations.
SET had been involved in a contractual dispute with Pacific Gas and Electric (PG&E) relating to SET's obligations to deliver certain quantities of natural gas to PG&E. A settlement of this matter has been concluded and approved by the Bankruptcy Court. The settlement will not result in any additional charge to earnings.
Electric Distribution System Conversion
Under a CPUC-mandated program and through franchise agreements with various cities, SDG&E is committed, in varying amounts, to converting overhead distribution facilities to underground. As of December 31, 2001, the aggregate unexpended amount of this commitment was approximately $110 million. Capital expenditures for underground conversions were $12 million in 2001, $26 million in 2000 and $20 million in 1999.
Concentration Of Credit Risk
The company maintains credit policies and systems to manage overall credit risk. These policies include an evaluation of potential counterparties' financial condition and an assignment of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. The California utilities grant credit to utility customers, substantially all of whom are located in their service territories, which together cover most of Southern California and a portion of central California.
Supply/demand imbalances and a number of other factors resulted in abnormally high electric-commodity costs beginning in mid-2000 and continuing into 2001. This caused SDG&E's monthly customer bills to be substantially higher than normal. In response, legislation imposed a ceiling of 6.5 cents/kWh on the cost of electricity that SDG&E could pass on to its residential, small-commercial and lighting customers on a current basis. The ceiling extends through December 31, 2002 (December 31, 2003 if deemed by the CPUC to be in the public interest). Once SDG&E is able to pass on these costs, it may experience an increase in customer credit risk. Additional information on this issue is discussed in Note 14.
SET 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, SET 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 14. ELECTRIC INDUSTRY RESTRUCTURING
Background
In 1996, California enacted legislation (AB 1890) restructuring California's investor-owned electric utility industry. The legislation and related decisions of the CPUC were intended to stimulate competition and reduce electric rates.
As part of the framework for a competitive electric-generation market, the legislation established the PX, which served as a wholesale power pool to which the California IOUs were required to sell all of their power supply (including owned generation and purchased-power contracts) and, except to the extent otherwise authorized by the CPUC, from which they were required to buy all of the electricity needed to serve their retail consumers. The PX also purchased power from nonutility generators through an auction process intended to establish competitive market prices for the power that it sells to the IOUs. An Independent System Operator (ISO) scheduled power transactions and access to the transmission system. In connection with the deregulation of California's electric-utility industry, during 1999 and 2000, the company sold and purchased electricity to and from the PX. Net purchase power reflects sales and purchases to and from the PX/ISO commencing April 1, 1998, at market prices of energy from SDG& E's power plants and from long-term purchase-power contracts. Due to subsequent industry restructuring developments (described below), the PX suspended its trading operations on January 31, 2001.
The restructuring legislation also established a rate freeze on amounts that the IOUs could charge their customers. The rate freeze was designed to generate revenue levels assumed to be sufficient to provide the IOUs with a reasonable opportunity to recover, by December 31, 2001, their costs of generation and purchased power that are fixed and unavoidable and included in customer rates. The rate freeze was to end as to each IOU when it completed recovery of the costs, but in no event later than March 31, 2002.
In June 1999, SDG&E completed the recovery of its stranded costs, other than the future above-market portion of its purchased-power contracts that were in effect at December 31, 1995, and SONGS costs, both of which continue to be collected in rates. Recovery of the other costs was effected by, among other things, the sale of SDG&E's fossil power plants and combustion turbines during the quarter ended June 30, 1999. Therefore, SDG&E is no longer subject to the rate freeze imposed by AB 1890.
With the rate freeze no longer applicable, SDG&E lowered its base rates (the portion of its rates not attributable to electric-commodity costs) and began to pass through to its customers, without markup, the cost of electricity purchased from the PX. SDG&E's overall rates were lower than during the rate freeze, but they also became subject to fluctuation with the actual cost of electricity purchases.
Effect on Customer Rates
As noted above, supply/demand imbalances and a number of other factors resulted in abnormally high electric-commodity prices beginning in mid-2000 and continuing into 2001. This caused SDG&E's monthly customer bills to be substantially higher than normal.
These higher prices were initially passed through to SDG&E's customers and resulted in customer bills that in most cases were double or triple those from 1999 and early 2000. This resulted in several legislative and regulatory responses.
California Assembly Bill 265 (AB 265), enacted in September 2000, imposed a ceiling of 6.5 cents kWh on the cost of the electric commodity that SDG&E could pass on to its small-usage customers on a current basis. Customers covered under the commodity rate ceiling generally include residential, small-commercial and lighting customers. The ceiling, retroactive to June 1, 2000, extends through December 31, 2002, and may be extended through December 31, 2003, if the CPUC determines that it is in the public interest to do so. The 6.5-cent rate ceiling is a "floating cap" that can float downward as prices decrease, but cannot exceed actual commodity costs without the approval of the CPUC. The CPUC subsequently approved an increase to the system average rate paid by SDG&E customers (to 7.96 cents per kWh) in order to pass through, without markup, the rates to repay the DWR for its purchases of power, as described below. The agreement for the ending of the earlier rate freeze provided for futur e recovery of SDG&E's electricity costs that could not be passed on to customers on a current basis. Although it delayed such recovery, AB 265 reaffirmed SDG&E's right to later collect undercollections resulting from the reasonable and prudent costs of procuring the commodity. The reasonableness reviews related to the commodity costs have been settled, as discussed below.
SDG&E accumulates the amount that it pays for electricity in excess of the ceiling rate (the undercollected costs) in an interest-bearing balancing account. SDG&E expects to amortize these amounts, together with interest, in rates charged to customers following the end of the rate-ceiling period. Due to their long-term nature, these undercollected costs are classified as a noncurrent regulatory asset on the company's Consolidated Balance Sheets. The undercollection was $447 million (of which $352 million was included in regulatory assets and $95 million was included in regulatory balancing accounts on the Consolidated Balance Sheets) at December 31, 2000. It increased to approximately $750 million in the first quarter of 2001 and decreased to $392 million at December 31, 2001. The decrease was due primarily to the $100 million refund related to prudence of purchase-power costs and the application of overcollections in other balancing accounts.
Role of the Department of Water Resources
In February 2001, through the passage of AB 1, the DWR began to purchase power from generators and marketers, who had previously sold their power to the PX/ISO, and has entered into long-term contracts for the purchase of a portion of the power requirements of the state's population that is served by IOUs. SDG&E and the DWR have entered into an agreement under which the DWR will continue to purchase power for SDG&E's customers through December 31, 2002.
As the DWR is now purchasing SDG&E's full net short position (the power needed by SDG&E's customers, other than that provided by SDG&E's nuclear generating facilities or its previously existing purchase power contracts), significant growth in these undercollections has ceased.
In April 2001, California law AB 43X took effect, extending the temporary 6.5-cent rate cap to include SDG&E's large customers (the only customer class not previously covered by the rate cap) retroactive to February 7, 2001. The reduced future bills did not add to the undercollection nor did the fourth quarter refunds of past charges above 6.5 cents, since, in large part, the purchases for these customers are covered by the agreement between SDG&E and the DWR.
Memorandum of Understanding
On June 18, 2001 representatives of California Governor Davis, the DWR, Sempra Energy and SDG&E entered into a Memorandum of Understanding (MOU) contemplating the implementation of a series of transactions and regulatory settlements and actions to resolve many of the issues affecting SDG&E and its customers arising out of the California energy crisis. The MOU contemplated the elimination from SDG&E's rate-ceiling balancing account of the undercollected costs that otherwise would be recovered in future customer rates; settlement of reasonableness reviews, electricity purchase contract issues and other regulatory matters.
On August 2, 2001, the CPUC approved a reduction of the rate-ceiling balancing account, as contemplated by the MOU, by the application thereto of overcollections in certain other balancing accounts totaling $70 million.
On October 10, 2001, the CPUC issued a decision approving the delay until 2004 of the effects of revised revenue requirements for the California utilities. However, the decision also denied the California utilities' request to continue equal sharing between ratepayers and shareholders of estimated savings stemming from the 1998 merger between PE and Enova. Instead, the CPUC ordered that all of the estimated 2003 merger savings go to ratepayers. The portion to be refunded to electric ratepayers would be credited to the Transition Cost Balancing Account (TCBA), based on the net present value (NPV) in 2001 of the savings for 2003. Merger savings related to 2001 and 2002 also would be so credited. The combined NPV is estimated to be $39 million. Merger savings allocable to gas ratepayers would be refunded through once-a-year bill credit, as has been the case.
On November 8, 2001, the CPUC approved a $100 million reduction of the rate-ceiling balancing account, in settlement of the reasonableness of SDG&E's electric procurement practices between July 1, 1999 through February 7, 2001.
In January 2002, the CPUC rejected the part of the MOU dealing with a settlement on electricity purchase contracts held by SDG&E. The MOU would have granted SDG&E ownership of its power sale profits in exchange for crediting $219 million to customers to offset the rate-ceiling balancing account. Instead, the CPUC asserted that all the profits associated with the energy purchase contracts should accrue to the benefit of customers. The CPUC estimated these profits as $363 million. The company believes the CPUC's calculation is incorrect and the CPUC has not explained to the company how it arrived at that amount. In addition, the company believes the CPUC's position is incorrect and has challenged the CPUC's original disallowance in the Court of Appeals. The court challenge was put on hold when the MOU was reached. SDG&E has now reactivated the case and has also filed a similar suit in federal court.
Recent Rate Changes
In order to provide sufficient revenues to repay the DWR for the $10 billion of power purchases it made on behalf of the state's three IOUs during the energy crisis, the CPUC issued a decision in September 2001 that established interim rate increases for SDG&E's electric customers in an average amount of approximately 1.46 cents per kWh, resulting in a system average rate of 7.96 cents per kWh when added to the 6.5 cents per kWh rate ceiling discussed above.
On February 21, 2002, the CPUC issued a final decision about the DWR revenue requirement, approving allocation of the DWR's cost of providing power based on actual cost of service, which was lower for SDG&E customers than for those in Northern California and, therefore, avoids a rate hike for SDG&E customers. Based on this allocation, the price SDG&E pays to the DWR drops from the previously proposed rate of 9.02 cents per kWh to 7.29 cents per kWh. SDG&E's system average rate of 7.96 cents per kWh (described above) remains unchanged and will be addressed separately. The CPUC also voted to relinquish oversight over DWR power purchases, which allows the state to proceed with the bond sale of up to $11.1 billion to repay the state's general fund (used for DWR power purchases during the energy crisis) and to cover continuing power purchases. Interested parties have 30 days to appeal the decision.
Direct Access
In September 2001, the CPUC suspended the ability of retail electricity customers to choose their power provider ("direct access") until at least the end of 2003 in order to improve the probability that enough revenue would be available to the DWR to cover the state's power purchases. The decision forbids new direct access contracts after September 20, 2001. In January 2002, a draft decision was issued modifying the direct access suspension decision, suspending direct access retroactively to July 1, 2001. This issue is on the CPUC's agenda for March 21, 2002. An unfavorable decision could adversely affect SES's contracts signed between July 1, 2001 and September 20, 2001. Any such effect is not expected to be material to the company's financial position or liquidity.
FERC Actions
The FERC has been investigating prices charged to the California IOUs by various electric suppliers. The FERC appears to be proceeding in the direction of awarding to the California IOUs a partial refund of the amounts charged. Any such refunds would reduce SDG&E's rate-ceiling balancing account and could result in a payment by SET. Such payment, if any, is not expected to be material to the company's financial position or liquidity. A FERC decision is not expected before the second half of 2002.
More recently, FERC has launched an investigation as to whether there was manipulation of short-term energy prices in the West that resulted in unjust and unreasonable long-term power sales contracts. The results of this investigation will be used by FERC to determine how it should proceed on existing and future complaints about long-term contracts, but will not address or prejudge any arguments made in these proceedings.
Effect On Other Subsidiaries
At December 31, 2001, SET was due approximately $100 million from the ISO for which the company believes adequate reserves have been recorded. The collection of these receivables may depend on satisfactory resolution of the financial difficulties being experienced by the IOUs as a result of the California electric industry situation described above.
NOTE 15. OTHER REGULATORY MATTERS
Gas Industry Restructuring
The natural gas industry in California experienced an initial phase of restructuring during the 1980s, but the CPUC did not make major changes after the early 1990s. In January 1998, the CPUC released a staff report initiating a project to assess the current market and regulatory framework for California's natural gas industry. In July 1999, after hearings, the CPUC issued a decision stating which natural gas regulatory changes it found most promising, encouraging parties to submit settlements addressing those changes, and providing for further hearings if necessary.
On December 11, 2001, the CPUC issued a decision adopting much of a settlement that had been submitted in 2000 by the California utilities and approximately 30 other parties representing all segments of the gas industry in Southern California, but which was opposed by other parties. The CPUC decision adopts the following provisions: a system for shippers to hold firm, tradable rights to capacity on SoCalGas' major gas transmission lines with SoCalGas' shareholders at risk for whether market demand for these rights will cover the cost of these facilities; a further unbundling of SoCalGas' storage services giving SoCalGas greater upward pricing flexibility (except for storage service for core customers) but with increased shareholder risk for whether market demand will cover storage costs; new balancing services including separate core and noncore balancing provisions; a reallocation among customer classes of the cost of interstate pipeline capacity held by SoCalGas and an unbundling of interstate capacity for gas marketers serving core customers; and the elimination of noncore customers' option to obtain gas supply service from SoCalGas and SDG&E. The CPUC modified the settlement to provide increased protection against the exercise of market power by persons who would acquire rights on the SoCalGas gas transmission system. The CPUC also rejected certain aspects of the settlement that would have provided more options for gas marketers serving core customers.
The CPUC is still considering the schedule for implementation of these regulatory changes, but it is expected that most of the changes will be implemented during 2002.
The California utilities believe the decision will make gas service more reliable, efficient and better tailored to the desires of customers. The decision is not expected to negatively impact the California utilities' earnings.
Performance-Based Regulation (PBR)
To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, the CPUC has been directing utilities to use PBR. PBR has replaced the general rate case and certain other regulatory proceedings for the California utilities. Under PBR, regulators require future income potential to be tied to achieving or exceeding specific performance and productivity goals, as well as cost reductions, rather than relying solely on expanding utility plant in a market where a utility already has a highly developed infrastructure.
In April 2001, SDG&E filed its 2000 PBR report with the CPUC. For 2000, SDG&E exceeded all six performance indicator benchmarks, resulting in a request for a total net reward of $11.7 million. The CPUC has not yet approved this report and these awards have not been recorded. In addition, SDG&E achieved an actual 2000 rate of return (applicable only to electric distribution and gas transportation) of 8.74 percent, which is below the authorized 8.75 percent. This results in no sharing of earnings in 2000 under the PBR sharing mechanism (as described below).
The California utilities' PBR mechanisms were to have been in effect through December 31, 2002, at which time the mechanisms were to be updated. That update was to include, among other things, a re-examination of the California utilities' reasonable costs of operation to be allowed in rates. The PBR and Cost of Service (COS) cases for the California utilities were both due to be filed on December 21, 2001. However, both the California utilities' PBR/COS cases were delayed by an October 10, 2001 CPUC decision such that the resulting rates would be effective in 2004 instead of 2003. The decision also denies the California utilities' request to continue equal sharing between ratepayers and shareholders of the estimated savings for the merger discussed in Note 1 and, instead, orders that all of the estimated 2003 merger savings go to ratepayers. The portion to be refunded to electric ratepayers was credited to the TCBA during the fourth quarter of 2001, based on the NPV in 2001 of the savings for 2003. Merge r savings related to 2001 and 2002 also were credited. The combined NPV was $39 million. Merger savings allocable to gas ratepayers will be refunded through once-a-year bill credits, as has been the case.
Key elements of the current mechanisms include an annual indexing mechanism that adjusts rates by the inflation rate less a productivity factor and other adjustments to accommodate major unanticipated events, a sharing mechanism with customers that applies to earnings that exceed the authorized rate of return on rate base, rate refunds to customers if service quality deteriorates or awards if service quality exceeds set standards, and a change in authorized rate of return and customer rates if interest rates change by more than a specified amount. The SoCalGas rate change is triggered if the 12-month trailing average of actual market interest rates increases or decreases by more than 150 basis points and is forecasted to continue to vary by at least 150 basis points for the next year. The SDG&E rate change is triggered by a six-month trailing average and a 100-basis-point change in interest rates. If these events occur, there would be an automatic adjustment of rates for the change in the cost of cap ital according to a formula which applies a percentage of the change to various capital components.
Gas Cost Incentive Mechanism
The Gas Cost Incentive Mechanism (GCIM) evaluates SoCalGas' natural gas purchases by comparing their cost with the average price of 30-day firm spot supplies in the basins in which SoCalGas purchases natural gas. The mechanism permits full recovery of all costs within a tolerance band above the benchmark price and refunds all savings within a tolerance band below the benchmark price. The costs or savings outside the tolerance band are shared between customers and shareholders. The CPUC approved the use of natural gas futures for managing risk associated with the GCIM. SoCalGas enters into natural gas futures contracts in the open market to mitigate risk and better manage natural gas costs.
Shareholder awards associated with the GCIM normally are recorded to SoCalGas' Purchased Gas Balancing Account after the close of the GCIM period, which covers the utility's gas supply operations for the twelve months ended March 31. These awards are not included in earnings until receipt of CPUC approval. In May 2001, the CPUC approved a $10 million shareholder award for GCIM Year Six ended March 31, 2000, and the CPUC is addressing whether the GCIM should be extended and, if so, whether it should be with or without modifications. The CPUC's Energy Division had previously issued an evaluation report recommending the continuation of the GCIM with modifications. In July 2001, SoCalGas, the CPUC's Office of Ratepayer Advocates (ORA) and The Utility Reform Network (TURN), a consumer-advocacy group, filed a Joint Motion for Adoption of Settlement Agreement to resolve all Phase 2 issues and to continue the GCIM with modifications. On March 5, 2002, a proposed decision was issued that, if adopted by the CPUC, would approve the settlement agreement and continue the mechanism, applying the modified GCIM beginning with the GCIM Year Seven (see below). A CPUC decision is expected by the third quarter of 2002.
In June 2001, SoCalGas filed its annual GCIM application with the CPUC requesting a shareholder award of $106 million for the GCIM Year Seven ended March 31, 2001. Notwithstanding this request the July 2001 Settlement Agreement among SoCalGas, the ORA and TURN would retroactively reduce the award request to $31 million. This proceeding is separate from the Phase 2 proceeding discussed above and final CPUC approval is not expected until early 2003.
Demand Side Management Awards
In recent years, the IOUs have participated in a CPUC program whereby they could earn awards for operating and/or administering energy-conservation efforts involving their retail customers. The California utilities have participated in these programs and have consistently achieved significant earnings therefrom. As part of the CPUC's review of the program, a draft decision is proposing that the program be reduced in scope and that award potentials for the IOUs be eliminated. An alternate proposal would maintain the award concept, but the potential awards would probably be reduced. The CPUC is scheduled to review both proposals at its March 21, 2002 meeting.
Biennial Cost Allocation Proceeding (BCAP)
Rates to recover the changes in the cost of natural gas transportation services are determined in the BCAP. The BCAP adjusts rates to reflect variances in customer demand from estimates previously used in establishing customer natural gas transportation rates. The mechanism substantially eliminates the effect on income of variances in market demand and natural gas transportation costs. SoCalGas filed its 2003 BCAP on September 21, 2001 and SDG&E filed its 2003 BCAP on October 5, 2001.
On April 20, 2000, the CPUC issued a decision on the 1999 BCAP, adopting overall decreases in natural gas revenues of $210 million for SoCalGas and $37 million for SDG&E for transportation rates effective June 1, 2000. For SoCalGas, there is a return to 75/25 (customer/shareholder) balancing account treatment for noncore transportation revenues, excluding certain transactions. In addition, unbundled noncore storage revenues are balanced 50/50 between customers and shareholders. Since the decreases reflect anticipated changes in corresponding costs, they have no effect on net income.
Cost Of Capital
SoCalGas is authorized to earn a rate of return on common equity (ROE) of 11.6 percent and a 9.49 percent return on rate base (ROR), the same as in 2001 and 2000. These rates will continue to be effective until the next periodic review by the CPUC unless interest-rate changes are large enough to trigger an automatic adjustment prior thereto, as discussed above under "Performance-Based Regulation." For SDG&E, electric industry restructuring has changed the method of calculating the utility's annual cost of capital. In June 1999, the CPUC adopted a 10.6 percent ROE and an 8.75 percent ROR for SDG&E's electric distribution and natural gas businesses. These rates remain in effect through 2002. The electric-transmission cost of capital is determined under a separate FERC proceeding. SDG&E is required to file an application by May 8, 2002, addressing ROE, ROR and capital structure for 2003. The application will, among other things, consider the recent and ongoing financial impacts on SDG& amp;E of electric industry restructuring.
Utility Integration
On September 20, 2001 the CPUC approved Sempra Energy's request to integrate the management teams of the California utilities. The decision retains the separate identities of each utility and is not a merger. Instead, utility integration is a reorganization that consolidates senior management functions of the two utilities and returns to the utilities a significant portion of shared support services currently provided by Sempra Energy's centralized corporate center. Once implementation is completed, the integration is expected to result in more efficient and effective operations.
In a related development, a CPUC draft decision would allow the California utilities to combine their natural gas procurement activities. The CPUC is scheduled to act on the draft decision at its April 4, 2002 meeting.
CPUC Investigation of Energy-Utility Holding Companies
The CPUC has initiated an investigation into the relationship between California's IOUs and their parent holding companies. Among the matters to be considered in the investigation are utility dividend policies and practices and obligations of the holding companies to provide financial support for utility operations under the agreements with the CPUC permitting the formation of the holding companies. On January 11, 2002, the CPUC issued a decision to clarify under what circumstances, if any, a holding company would be required to provide financial support to its utility subsidiaries. The CPUC broadly determined that it would require the holding company to provide cash to a utility subsidiary to cover its operating expenses and working capital to the extent they are not adequately funded through retail rates. This would be in addition to the requirement of holding companies to cover their utility subsidiaries' capital requirement, as the IOUs have previously acknowledged in connection with the holding comp anies' formations. On January 14, 2002, the CPUC ruled on jurisdictional issues, deciding that the CPUC had jurisdiction to create the holding company system and, therefore, retains jurisdiction to enforce conditions to which the holding companies had agreed. The company has filed to request rehearing on the issues.
NOTE 16. SEGMENT INFORMATION
The company, primarily an energy services company, has three separately managed reportable segments comprised of SoCalGas, SDG&E and SET. The two California utilities operate in essentially separate service territories under separate regulatory frameworks and rate structures set by the CPUC. SDG&E provides electric and natural gas service to San Diego and southern Orange counties. SoCalGas is a natural gas distribution utility, serving customers throughout most of Southern California and part of central California. SET is based in Stamford, Connecticut, and is engaged in wholesale trading and marketing of natural gas, electricity, petroleum, petroleum products and other commodities in the United States, Canada, Europe and Asia. The accounting policies of the segments are described in Note 2, and segment performance is evaluated by management based on reported net income. Intersegment transactions are recorded the same as sales or transactions with third parties. Utility transactions are primarily based on rates set by the CPUC and FERC.
|
|
Years ended December 31, |
|
|||||||||
|
(Dollars in millions) |
2001 |
|
|
2000 |
|
|
1999 |
|
|||
|
OPERATING REVENUES |
|
|
|
|
|
|
|
|
|
|
|
|
Southern California Gas |
$ |
3,716 |
|
|
$ |
2,854 |
|
|
$ |
2,569 |
|
|
San Diego Gas & Electric |
|
2,313 |
|
|
|
2,671 |
|
|
|
2,207 |
|
|
Sempra Energy Trading |
|
1,003 |
|
|
|
795 |
|
|
|
450 |
|
|
Intersegment revenues |
|
(31 |
) |
|
|
(65 |
) |
|
|
(72 |
) |
|
All other |
|
1,028 |
|
|
|
782 |
|
|
|
206 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
$ |
8,029 |
|
|
$ |
7,037 |
|
|
$ |
5,360 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INTEREST INCOME |
|
|
|
|
|
|
|
|
|
|
|
|
Southern California Gas |
$ |
22 |
|
|
$ |
27 |
|
|
$ |
16 |
|
|
San Diego Gas & Electric |
|
21 |
|
|
|
51 |
|
|
|
40 |
|
|
Sempra Energy Trading |
|
11 |
|
|
|
8 |
|
|
|
3 |
|
|
Intersegment interest |
|
(50 |
) |
|
|
(106 |
) |
|
|
(86 |
) |
|
All other |
|
79 |
|
|
|
88 |
|
|
|
82 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total interest income |
|
83 |
|
|
|
68 |
|
|
|
55 |
|
|
Equity in earnings of unconsolidated subsidiaries |
|
12 |
|
|
|
62 |
|
|
|
(5 |
) |
|
Sundry income (loss) |
|
(5 |
) |
|
|
(3 |
) |
|
|
-- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other income |
$ |
90 |
|
|
$ |
127 |
|
|
$ |
50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEPRECIATION AND AMORTIZATION |
|
|
|
|
|
|
|
|
|
|
|
|
Southern California Gas |
$ |
268 |
|
|
$ |
263 |
|
|
$ |
260 |
|
|
San Diego Gas & Electric (See Note 14) |
|
207 |
|
|
|
210 |
|
|
|
561 |
|
|
Sempra Energy Trading |
|
27 |
|
|
|
32 |
|
|
|
29 |
|
|
All other |
|
77 |
|
|
|
58 |
|
|
|
29 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
$ |
579 |
|
|
$ |
563 |
|
|
$ |
879 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INTEREST EXPENSE |
|
|
|
|
|
|
|
|
|
|
|
|
Southern California Gas |
$ |
68 |
|
|
$ |
74 |
|
|
$ |
60 |
|
|
San Diego Gas & Electric |
|
92 |
|
|
|
118 |
|
|
|
120 |
|
|
Sempra Energy Trading |
|
14 |
|
|
|
18 |
|
|
|
15 |
|
|
Intersegment interest |
|
(50 |
) |
|
|
(106 |
) |
|
|
(86 |
) |
|
All other |
|
199 |
|
|
|
182 |
|
|
|
120 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
$ |
323 |
|
|
$ |
286 |
|
|
$ |
229 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME TAX EXPENSE (BENEFIT) |
|
|
|
|
|
|
|
|
|
|
|
|
Southern California Gas |
$ |
169 |
|
|
$ |
183 |
|
|
$ |
182 |
|
|
San Diego Gas & Electric |
|
141 |
|
|
|
144 |
|
|
|
126 |
|
|
Sempra Energy Trading |
|
87 |
|
|
|
63 |
|
|
|
(7 |
) |
|
All other |
|
(184 |
) |
|
|
(120 |
) |
|
|
(122 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
$ |
213 |
|
|
$ |
270 |
|
|
$ |
179 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS) |
|
|
|
|
|
|
|
|
|
|
|
|
Southern California Gas |
$ |
207 |
|
|
$ |
206 |
|
|
$ |
200 |
|
|
San Diego Gas & Electric |
|
177 |
|
|
|
145 |
|
|
|
193 |
|
|
Sempra Energy Trading |
|
196 |
|
|
|
155 |
|
|
|
19 |
|
|
All other |
|
(62 |
) |
|
|
(77 |
) |
|
|
(18 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
$ |
518 |
|
|
$ |
429 |
|
|
$ |
394 |
|
|
|
|
At December 31 or for the years ended December 31 |
||||||||
|
(Dollars in millions) |
|
2001 |
|
2000 |
|
1999 |
||||
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
Southern California Gas |
|
$ |
3,762 |
|
$ |
4,128 |
|
$ |
3,452 |
|
|
San Diego Gas & Electric |
|
|
5,444 |
|
|
4,734 |
|
|
4,366 |
|
|
Sempra Energy Trading |
|
|
3,114 |
|
|
4,689 |
|
|
1,981 |
|
|
All other |
|
|
2,836 |
|
|
1,989 |
|
|
1,325 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
15,156 |
|
$ |
15,540 |
|
$ |
11,124 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CAPITAL EXPENDITURES |
|
|
|
|
|
|
|
|
|
|
|
Southern California Gas |
|
$ |
294 |
|
$ |
198 |
|
$ |
146 |
|
|
San Diego Gas & Electric |
|
|
307 |
|
|
324 |
|
|
245 |
|
|
Sempra Energy Trading |
|
|
45 |
|
|
22 |
|
|
26 |
|
|
All other |
|
|
422 |
|
|
215 |
|
|
172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,068 |
|
$ |
759 |
|
$ |
589 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
GEOGRAPHIC INFORMATION |
|
|
|
|
|
|
|
|
|
|
|
Long-lived assets |
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
6,516 |
|
$ |
6,071 |
|
$ |
5,857 |
|
|
Latin America |
|
|
836 |
|
|
911 |
|
|
701 |
|
|
Canada |
|
|
24 |
|
|
23 |
|
|
-- |
|
|
Europe |
|
|
10 |
|
|
9 |
|
|
-- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
7,386 |
|
$ |
7,014 |
|
$ |
6,558 |
|
|
|
||||||||||
|
Operating revenues |
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
7,468 |
|
$ |
6,700 |
|
$ |
5,280 |
|
|
Latin America |
|
|
280 |
|
|
154 |
|
|
16 |
|
|
Europe |
|
|
250 |
|
|
158 |
|
|
62 |
|
|
Canada |
|
|
15 |
|
|
14 |
|
|
2 |
|
|
Asia |
|
|
16 |
|
|
11 |
|
|
-- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
8,029 |
|
$ |
7,037 |
|
$ |
5,360 |
|
QUARTERLY FINANCIAL DATA (UNAUDITED)
|
Quarter ended (Dollars in millions except per-share amounts) |
|
March 31 |
|
June 30 |
|
September 30 |
|
December 31 |
||||
|
2001 |
|
|
||||||||||
|
Operating revenues |
|
$ |
3,242 |
|
$ |
1,900 |
|
$ |
1,510 |
|
$ |
1,377 |
|
Operating expenses |
|
|
2,870 |
|
|
1,628 |
|
|
1,291 |
|
|
1,247 |
|
Operating income |
|
$ |
372 |
|
$ |
272 |
|
$ |
219 |
|
$ |
130 |
|
|
||||||||||||
|
Net income |
|
$ |
178 |
|
$ |
137 |
|
$ |
96 |
|
$ |
107 |
|
Average common shares outstanding (diluted) |
|
|
203.0 |
|
|
206.0 |
|
|
206.6 |
|
|
206.0 |
|
Net income per common share (diluted) |
|
$ |
0.88 |
|
$ |
0.66 |
|
$ |
0.46 |
|
$ |
0.52 |
|
|
||||||||||||
|
2000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues |
|
$ |
1,442 |
|
$ |
1,510 |
|
$ |
1,806 |
|
$ |
2,279 |
|
Operating expenses |
|
|
1,201 |
|
|
1,288 |
|
|
1,619 |
|
|
2,046 |
|
Operating income |
|
$ |
241 |
|
$ |
222 |
|
$ |
187 |
|
$ |
233 |
|
|
||||||||||||
|
Net income |
|
$ |
113 |
|
$ |
110 |
|
$ |
110 |
|
|
95 |
|
Average common shares outstanding (diluted) |
|
|
228.4 |
|
|
201.5 |
|
|
201.5 |
|
|
202.7 |
|
Net income per common share (diluted) |
|
$ |
0.49 |
|
$ |
0.55 |
|
$ |
0.55 |
|
$ |
0.47 |
QUARTERLY COMMON STOCK DATA (UNAUDITED)
|
|
|
First Quarter |
|
Second Quarter |
|
Third Quarter |
|
Fourth Quarter |
|||||
|
2001 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
$ |
23.94 |
|
$ |
28.61 |
|
$ |
28.00 |
|
$ |
26.68 |
|
|
Low |
|
$ |
17.31 |
|
$ |
21.98 |
|
$ |
23.25 |
|
$ |
22.00 |
|
|
|
|||||||||||||
|
2000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Market price |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
$ |
19.25 |
|
$ |
19.25 |
|
$ |
21.00 |
|
$ |
24.88 |
|
|
Low |
|
$ |
16.25 |
|
$ |
16.19 |
|
$ |
17.00 |
|
$ |
19.38 |
|
Sempra Energy's annual report to the Securities and Exchange Commission (Form 10-K) is available to shareholders at no charge by writing to Shareholder Services at 101 Ash Street, San Diego, CA 92101.
EXHIBIT 21.01
SEMPRA ENERGY
Schedule of Significant Subsidiaries at December 31, 2001
State of Incorporation
Subsidiary or Other Jurisdiction
- ---------- ----------------------
Chilquinta Energia, S.A. Chile
Luz del Sur, S.A.A. Peru
San Diego Gas & Electric Company California
Sempra Energy Financial California
Sempra Energy Global Enterprises California
Sempra Energy International California
Sempra Energy Resources California
Sempra Energy Services Texas
Sempra Energy Trading Corp. Delaware
Sodigas Pampeana S.A. Argentina
Sodigas Sur S.A. Argentina
Southern California Gas Company California