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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported) November 22, 2002
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
(Exact name of registrant as specified in its charter)
State of New Jersey 001-09120 22-2625848
(State or other (Commission File Number) (I.R.S. Employer
jurisdiction of Identification No.)
incorporation)
80 Park Plaza, P.O. Box 1171
Newark, New Jersey 07101-1171
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 973-430-7000
http://www.pseg.com
(Registrant's internet address)
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Item 5. Other Events
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED (PSEG) CONFORMS PRESENTATION OF
INFORMATION CONTAINED IN ITS 2001 ANNUAL REPORT ON FORM 10-K TO REFLECT MATTERS
PREVIOUSLY DISCLOSED IN 2002 QUARTERLY REPORTS ON FORM 10-Q
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THIS CURRENT REPORT ON FORM 8-K (REPORT) CONFORMS THE INFORMATION CONTAINED
IN OUR 2001 ANNUAL REPORT ON FORM 10-K TO THE PRESENTATION REPORTED IN OUR THIRD
QUARTER 2002 FORM 10-Q. ACCORDINGLY, THIS REPORT REVISES INFORMATION PREVIOUSLY
REPORTED IN OUR 2001 ANNUAL REPORT ON FORM 10-K TO REFLECT THE FOLLOWING MATTERS
WHICH HAVE PREVIOUSLY BEEN DISCLOSED IN REPORTS FILED UNDER THE SECURITIES
EXCHANGE ACT OF 1934.
NO ATTEMPT HAS BEEN MADE IN THIS FORM 8-K TO MODIFY OR UPDATE OTHER
DISCLOSURES AS PRESENTED IN THE ORIGINAL FORM 10-K EXCEPT AS REQUIRED TO REFLECT
THE EFFECTS OF THOSE ITEMS AS DESCRIBED BELOW.
This Report is limited to the reclassifications to reflect:
o certain businesses as discontinued operations,
o a change in the reporting of trading revenues and costs,
o a change in business segment reporting,
o a reclassification of certain costs related to the early extinguishment of
debt.
This Report reflects these changes and their impact upon Item 6. Selected
Financial Data, Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations, Item 7A. Qualitative and Quantitative
Disclosures About Market Risks, Item 8. Financial Statements and Supplementary
Data, and Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K as originally reported in our 2001 Annual Report on Form 10-K. These changes
have been made to maintain conformity to the reporting format presented in our
Form 10-Q for the period ended September 30, 2002. Certain reclassifications of
amounts reported in prior periods have been made to conform with the current
presentation.
As disclosed in our Form 10-Q for the quarter ended September 30, 2002, we
have implemented a plan to exit the heating, ventilating, air conditioning
(HVAC), and mechanical operating business of PSEG Energy Technologies Inc.
(Energy Technologies) and PSEG Global Inc.'s (Global) interest in Tanir Bavi, an
electric generation facility in India. As a result, Global's interest in Tanir
Bavi and Energy Technologies' HVAC/mechanical operating business were
reclassified to discontinued operations and presented in accordance with
Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for
Impairment or Disposal of Long-Lived Assets" (SFAS 144). Under SFAS 144
long-lived assets to be disposed of are measured at the lower of carrying amount
or fair value less cost to sell, whether reported in continued operations or in
discontinued operations. Discontinued operations are no longer 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. SFAS
144 is effective for fiscal years beginning after December 15, 2001. The
consolidated statements for all periods presented have been restated to reflect
this reclassification. For additional information, see Note 3. Discontinued
Operations.
Pursuant to Emerging Issues Task Force (EITF) Issue No. 99-19, "Reporting
Revenue Gross as a Principal versus Net as an Agent" (EITF 99-19), prior to July
1, 2002, we recorded our energy trading revenues and energy trading costs on a
gross basis for physical energy and capacity sales and purchases. As disclosed
in our Form 10-Q for the quarter ended September 30, 2002, in accordance with
the consensus reached in June 2002 relating to EITF Issue No. 02-3, "Issues
Involved in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities" (EITF
02-3), beginning in the third quarter of 2002, we started reporting energy
trading revenues and energy trading costs on a net basis and have reclassified
prior periods to conform with this net presentation. As a result, both Operating
Revenues and Operating Costs were
reduced by approximately $2.3 billion, $2.7 billion and $1.8 billion for the
fiscal years ended December 31, 2001, 2000 and 1999, respectively. This change
in presentation did not have an effect on trading margins, net income or cash
flows.
Power's business has evolved during 2002. With the transfer of the basic
gas supply service (BGSS) contract to Power and the commencement of the new
basic generation service contracts (BGS) with wholesale electric suppliers,
Power's business has become a fully integrated wholesale energy supply business.
As a result of that evolution of Power's business, trading activities changed
from a stand-alone operation to a function that has become fully integrated with
the wholesale energy supply business, and primarily serves to optimize the value
of that business. Therefore, upon review and in accordance with SFAS No. 131,
"Disclosures About Segments of an Enterprise and Related Information" (SFAS
131), as disclosed in our Form 10-Q for the quarter ended September 30, 2002, we
have determined that Power's generation and trading components no longer meet
the definition of separate operating segments for financial reporting purposes
and we have reported Power's financial position and results of operations as one
segment. All prior periods have been reclassified to conform to the current
presentation.
During the third quarter of 2002, we adopted SFAS 145. This Statement
rescinds SFAS No. 4, "Reporting Gains and Losses from Extinguishments of Debt,"
(SFAS 4) and an amendment of that Statement, SFAS No. 64, "Extinguishments of
Debt Made to Satisfy Sinking Fund Requirements" (SFAS 64). SFAS 4 required that
gains and losses from extinguishments of debt that were included in the
determination of net income be aggregated, and if material, classified as an
extraordinary item. Since the issuance of SFAS 4, the use of debt
extinguishments has become part of the risk management strategy of many
companies, representing a type of debt extinguishment that does not meet the
criteria for classification as an extraordinary item. Based on this trend, the
Financial Accounting Standards Board issued this rescission of SFAS 4 and SFAS
64. Accordingly, as disclosed in our Form 10-Q for the quarter ended September
30, 2002, under SFAS 145, we now record these gains and losses in Other Income
and Other Deductions, respectively. We reclassified a pre-tax loss of $3 million
($2 million after-tax) from the early retirement of debt to a component of Other
Income and Deductions for the year ended December 31, 2001 in accordance with
SFAS 145.
Controls and Procedures
The Company has established and maintains disclosure controls and
procedures which are designed to provide reasonable assurance that material
information relating to the Company, including our consolidated subsidiaries, is
made known to us by others within those entities, particularly during the period
in which this current report is being prepared. The Company has established a
Disclosure Committee which is made up of several key management employees and
reports directly to the Chief Financial Officer and Chief Executive Officer, to
monitor and evaluate these disclosure controls and procedures. The Chief
Financial Officer and Chief Executive Officer have evaluated the effectiveness
of our disclosure controls and procedures as of a date within 90 days prior to
the filing date of this current report (the "Evaluation Date") and based on this
evaluation, it was concluded that our disclosure controls and procedures were
effective in providing reasonable assurance during the period covered in this
report. There were no significant changes in internal controls or in other
factors that could significantly affect internal controls subsequent to the date
of our most recent evaluation.
TABLE OF CONTENTS
UPDATES TO 2001 FORM 10-K
PART II Page
Item 6. Selected Financial Data.................................... 1
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations...................................... 2
Corporate Structure................................. ...... 2
Overview of 2001 and Future Outlook........................ 3
Results of Operations...................................... 5
Liquidity and Capital Resources............................ 12
Capital Requirements....................................... 18
Qualitative and Quantitative Disclosures About Market Risk. 20
Foreign Operations......................................... 25
Accounting Issues.......................................... 25
Forward Looking Statements................................. 27
Item 7A. Qualitative and Quantitative Disclosures About Market Risk. 28
Item 8. Financial Statements and Supplementary Data................ 28
Consolidated Financial Statements.......................... 29
Notes to Consolidated Financial Statements................. 34
Financial Statement Responsibility......................... 83
Independent Auditors' Report............................... 84
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K 85
Schedule II-Valuation and Qualifying Accounts.............. 85
ITEM 6. SELECTED FINANCIAL DATA
PSEG
The information presented below should be read in conjunction with our
Consolidated Financial Statements and Notes thereto.
Years Ended December 31,
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2001 2000 1999 1998 1997
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(Millions of Dollars, where applicable)
Total Operating Revenues.................... $7,055 $6,521 $6,339 $5,947 $6,173
============= ============= ============= ============= =============
Income Before Discontinued Operations,
Extraordinary Item and Cumulative
Effect Adjustment........................... $776 $776 $736 $656 $577
Loss from Discontinued Operations (A)....... (15) (12) (13) (12) (17)
Extraordinary Item (B)...................... -- -- (804) -- --
Cumulative Effect Adjustment (C)............ 9 -- -- -- --
------------- ------------- ------------- ------------- -------------
Net Income (Loss)........................... $770 $764 $(81) $644 $560
============= ============= ============= ============= =============
Earnings per Average Share (Basic and Diluted):
Before Discontinued Operations, Extraordinary
Item and Cumulative Effect Adjustment........ $3.73 $3.61 $3.35 $2.84 $2.48
Loss from Discontinued Operations (A)........ (0.07) (0.06) (0.06) (0.05) (0.07)
Extraordinary Item (B)................... -- -- (3.66) -- --
Cumulative Effect Adjustment (C) ........ 0.04 -- -- -- --
------------- ------------- ------------- ------------- -------------
Total Earnings per Average Share....... $3.70 $3.55 $(0.37) $2.79 $2.41
============= ============= ============= ============= =============
Dividends Paid per Share.................... $2.16 $2.16 $2.16 $2.16 $2.16
As of December 31:
Total Assets............................. $25,430 $21,526 $19,015 $17,991 $17,943
Long-Term Liabilities:
Long-Term Debt (D) .................... $10,191 $5,296 $4,575 $4,763 $4,873
Other Noncurrent Liabilities (F)....... $2,014 $1,759 $1,561 $764 $609
Preferred Stock With Mandatory Redemption... -- $75 $75 $75 $75
Monthly Guaranteed Preferred Beneficial
Interest
in PSE&G's Subordinated Debentures....... $60 $210 $210 $210 $210
Quarterly Guaranteed Preferred Beneficial
Interest
in PSE&G's Subordinated Debentures....... $95 $303 $303 $303 $303
Quarterly Guaranteed Preferred Beneficial
Interest
in PSEG's Subordinated Debentures........ $525 $525 $525 $525 --
Ratio of Earnings to Fixed Charges (E)... 2.04 2.60 3.07 2.80 2.43
(A) The reclassification of Global's investment in Tanir Bavi and Energy
Technologies' HVAC/mechanical contracting business to Loss from
Discontinued Operations.
(B) 2001 charge relates to loss on early debt retirement. For the
extraordinary charge recorded in 1999, see Note 4.Regulatory Issues and
Accounting Impacts of Deregulation.
(C) Impact of SFAS 133 Adoption, See Note 9. Financial Instruments, Energy
Trading and Risk Management.
(D) Increase in debt partially related to securitization transaction in 2001
and consolidation of non-recourse debt.
(E) Excludes Extraordinary Item.
(F) Excludes Deferred Taxes and ITC and the Excess Depreciation Reserve
portion of Regulatory Liabilities.
1
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
This discussion makes reference to the Consolidated Financial Statements
and related Notes to Consolidated Financial Statements (Notes) of Public Service
Enterprise Group Incorporated and should be read in conjunction with such
statements and notes.
CORPORATE STRUCTURE
We are a holding company and, as such, have no operations of our own. We
have four principal direct wholly-owned subsidiaries: Public Service Electric
and Gas Company (PSE&G), PSEG Power LLC (Power), PSEG Energy Holdings Inc.
(Energy Holdings) and PSEG Services Corporation (Services).
PSE&G is an operating public utility company engaged principally in the
transmission, distribution and sale of electric energy and gas service in New
Jersey. On August 21, 2000, pursuant to the terms of the Final Order issued by
the New Jersey Board of Public Utilities (BPU), PSE&G transferred its
generation-related assets and liabilities and its wholesale power contracts to
Power and its subsidiaries in exchange for a promissory note in an amount equal
to the total purchase price of $2.786 billion. Power paid the promissory note on
January 31, 2001 at which time the transferred assets were released from the
lien of PSE&G's First and Refunding Mortgage. PSE&G continues to own and operate
its regulated electric and gas transmission and distribution business. A
bankruptcy-remote subsidiary of PSE&G, PSE&G Transition Funding LLC, issued
$2.525 billion of securitization bonds in January of 2001 in partial recovery of
PSE&G's stranded cost resulting from New Jersey deregulation and restructuring.
An additional $540 million of PSE&G's stranded costs is being recovered from its
customers over a four-year transition period ending July 31, 2003 through a
Market Transition Charge (MTC).
Power is an independent wholesale energy supply company that has three
principal direct wholly-owned subsidiaries: PSEG Nuclear LLC (Nuclear) which
owns and operates nuclear generating stations, PSEG Fossil LLC (Fossil), which
develops, owns and operates domestic fossil generating stations and PSEG Energy
Resources & Trade LLC (ER&T), a fully integrated wholesale energy supply
business. We also have a finance company subsidiary, PSEG Power Capital
Investment Co. (Power Capital), which provides certain financing for its
subsidiaries.
Energy Holdings participates in three energy-related reportable segments
through its principal wholly-owned subsidiaries: PSEG Global Inc. (Global),
which develops, acquires, owns and operates electric generation and distribution
facilities; PSEG Resources Inc. (Resources), which provides energy
infrastructure financing and invests in energy-related financial transactions
and manages a diversified portfolio of investments including leveraged leases,
operating leases, leveraged buyout (LBO) funds, limited partnerships and
marketable securities; and PSEG Energy Technologies Inc. (Energy Technologies),
an energy management company that constructs, operates and maintains heating,
ventilating and air conditioning (HVAC) systems for, and provides energy-related
engineering, consulting and mechanical contracting services to, industrial and
commercial customers in the Northeastern and Middle Atlantic United States.
Energy Technologies is also comprised of an asset management group, which
includes various Demand Side Management (DSM) investments. In 2002, we announced
our decision to exit the HVAC/mechanical operating business of Energy
Technologies. The sale of these businesses is expected to be completed by June
2003. Energy Holdings also has a finance subsidiary, PSEG Capital Corporation
(PSEG Capital), which serves as a financing vehicle for Energy Holdings'
subsidiaries and borrows on the basis of a minimum net worth maintenance
agreement with PSEG. See Liquidity and Capital Resources for further detail.
Energy Holdings is also the parent of Enterprise Group Development Corporation
(EGDC), a property management business and is conducting a controlled exit from
this business.
Services was formed in 1999 and provides management and administrative
services to us and our subsidiaries.
2
OVERVIEW OF 2001 AND FUTURE OUTLOOK
The Energy Competition Act and the related BPU proceedings, including the
Final Order and the Energy Master Plan Proceedings, have dramatically reshaped
the utility industry in New Jersey and have directly affected how we will
conduct business, and therefore, our financial prospects in the future.
Deregulation, restructuring, privatization and consolidation are creating
opportunities and risks for us and our subsidiaries. We have realigned our
organizational structure to address the competitive environment brought about by
the deregulation of the electric generation industry in New Jersey and the
Eastern U.S and have transitioned from primarily being a regulated New Jersey
utility to operating as a competitive global energy company. We have been
engaged in the competitive energy business for a number of years through certain
of our unregulated subsidiaries; however, competitive businesses now constitute
a much larger portion of our activities. As of December 31, 2001, Power, PSE&G,
and Energy Holdings comprised approximately 20%, 51% and 29% of PSEG's
consolidated assets and contributed approximately 50%, 30% and 20% of our net
income for the year ended December 31, 2001. Our projected earnings
contributions for 2002 and 2003 are 50% to 55% from Power, 25% to 30% from
Energy Holdings and 20% to 25% from PSE&G. Additionally, we will be more
dependent on cash flows generated from our unregulated operations for our
capital needs. As the unregulated portion of the business continues to grow,
financial risks and rewards will be greater, financial requirements will change
and the volatility of earnings and cash flows will increase.
Our subsidiaries consist of a portfolio of energy-related businesses that
together are designed to produce a coherent energy market strategy. Because the
nature and risks of these businesses are different, and because they operate in
different geographic locations, the combined entity is designed to produce
consistent earnings growth in a manner that will mitigate the adverse financial
effects of business losses or an economic downturn is any one sector or
geographic region.
For 2001, we earned $3.70 per share. Our improved earnings for 2001 as
compared to 2000 were due primarily to new acquisitions, asset sales and
improved operations at Global, new leveraged lease investments at Resources,
continued strong performance of our nuclear generating facilities and improved
performance of our energy trading operations, which saw an increase in margins
from $72 million in 2000 to $140 million in 2001. These improvements more than
offset the effects of comparatively unfavorable weather conditions, two BPU
mandated 2% rate reductions, effective in February 2001 and August 2001, and the
effects of the securitization transaction that occurred on January 31, 2001.
We estimate a 7% compound annual growth rate in earnings per share over the
next five years. Our earnings for 2002 will depend on several factors, including
our ability to effectively manage our commitments under contracts to deliver
energy, capacity and ancillary services to the various suppliers of BGS to New
Jersey's utilities and our ability to minimize the effects, including potential
asset impairments, brought about by the economic, political and social crisis in
Argentina, where we face considerable fiscal and cash uncertainties. For further
discussion of our $632 million investment exposure in Argentina, see Note 10.
Commitments and Contingent Liabilities.
Looking beyond 2002, our earnings will depend on the outcome of future BGS
auctions in New Jersey, energy prices, which are currently depressed, in the
United States markets in which Power and Global participate, the successful
operation of our generation stations, PSE&G's ability to obtain timely and
adequate rate relief, regulatory decisions affecting our interests in
distribution companies in South America, and the effect of economic conditions
in foreign countries in which we invest.
PSE&G
PSE&G operates under cost-based regulation by the BPU for its distribution
operations and by the Federal Energy Regulatory Commission (FERC) for its
electric transmission operations. As such, the earnings of PSE&G are largely
determined by the regulation of its rates. PSE&G is expected to continue to make
a steady contribution to earnings in the future as it continues its transmission
and distribution and sale of electric energy and gas service in New Jersey.
PSE&G's success will be determined by its ability to maintain system reliability
and safety, effectively manage costs and obtain timely and adequate rate relief.
The risks from this business are relatively modest and generally relate to the
regulatory treatment of the various rate and other issues by the BPU and the
FERC.
3
On January 9, 2002, the BPU approved an additional $90 million of gas base
rate revenues for PSE&G, simultaneously with other PSE&G rate filings related to
underrecovered gas costs which were deferred on its balance sheet. All three
rate changes were effective January 9, 2002.
Also on January 9, 2002, the BPU approved the transfer of the utility's gas
supply business, including its transportation and storage contracts, to Power.
As a result, after April 1, 2002, Power will provide gas supply to PSE&G to
serve its Basic Gas Supply Service (BGSS) customers under a Requirements
Contract at market prices. Industrial and commercial BGSS customers will be
priced under PSE&G's Market Priced Gas Service (MPGS) and residential BGSS
customers will remain under current pricing until April 1, 2004 after which,
subject to further BPU approval, those residential gas customers would also move
to MPGS service.
On February 15, 2002, the BPU announced the successful outcome of the BGS
auction. Through the auction, PSE&G contracted for sufficient electricity to
serve all of its BGS customers and any difference between the existing tariff
rates and the rates set through the auction for the one-year contract period
beginning August 1, 2002 will be deferred and recovered over future periods as a
regulatory asset.
POWER
Power is focused on a generation market extending from Maine to the
Carolinas and the Atlantic Coast to Indiana (Super Region). The risks of Power's
business are that the competitive wholesale power prices that it is able to
obtain are sufficient to provide a profit and sustain the value of its assets.
It is also subject to credit risk of the counterparties to whom it sells energy
products, the successful operation of its generating facilities, fluctuations in
market prices of energy and imbalances between obligations and available supply.
These risks are higher than those for a regulated business. Therefore, they
provide the opportunity for greater returns, but they also present the greater
possibility of business losses and counterparty credit risk. Power is currently
constructing projects which will increase capacity by over 3,500 MW, net of
planned retirements.
Power currently sells approximately 95% of the output from its generation
facilities under bilateral contracts, primarily the BGS contract with PSE&G, and
the remaining 5% to customers in the competitive wholesale (spot) market. Within
the spot market, Power sells into the energy, capacity and ancillary services
markets. Ancillary services include operating reserves and area regulation.
Power has entered into one-year contracts commencing August 1, 2002 with
various direct bidders in the New Jersey BGS Auction, which was approved by the
BPU on February 15, 2002. Power believes that its obligations under these
contracts are reasonably balanced by its available supply.
In addition, Power is projected to continue its strong growth by using
energy trading to optimize the value of its portfolio of generating assets and
its supply obligations. In 2001, energy trading realized a gross margin of $140
million and Power forecasts an increase for 2002 due in part to the transfer of
PSE&G's gas supply business to Power, discussed below. We marked to market
energy trading contracts and include gains and losses in earnings. The vast
majority of these contracts have terms of less than one year and are valued
using market exchange prices and broker quotes. Energy trading provides the
opportunity for greater returns, but it also is more risky than the regulated
business, and can be adversely impacted by fluctuating energy market prices and
by the credit quality of the counterparties with which it does business. Power
utilizes a conservative risk management strategy to minimize exposure to market
and credit risk. For further information, see Accounting Issues, Note 1.
Organization and Summary of Significant Accounting Policies and Note 9.
Financial Instruments, Energy Trading and Risk Management.
ENERGY HOLDINGS
Energy Holdings is a major part of our growth strategy. In order to achieve
this strategy, Global will focus on generation and distribution investments
within targeted high-growth regions. Resources will utilize its market access,
industry knowledge and transaction structuring capabilities to expand its
energy-related financial investment portfolio. Resources' assets generate cash
flow and earnings in the near term, while investments at Global generally have a
longer time horizon before achieving expected cash flow and earnings. Also,
Resources' passive lower-risk assets serve to balance the higher risk associated
with operating assets at Global and Energy Technologies.
4
Global's more recent activities have been concentrated on developing
generation internationally and in acquiring distribution businesses, principally
in South America, that have been privatized by the local governments. As Global
has grown, its objective has evolved from being a minority or equal partner to
seeking to be the majority or sole owner of many of its investments. Global's
business depends on the ability to negotiate or obtain favorable prices and
terms for the output of its generating facilities nationally and
internationally, and to obtain favorable governmental and regulatory treatment
for its distribution assets in foreign countries. Global undertakes investments
where the expected return is commensurate with the market, regulatory,
international and currency risks that are inherent with its investments. Since
these risks are priced in the original investment decision, to the extent that
market, regulatory international or currency conditions evolve differently than
originally forecast, the investment performance of Global's assets will differ
form the expected performance. Thus, the expected investment returns from
Global's projects are priced to produce relatively high returns to compensate
for the high level of risk associated with this business.
Global has investment exposure of $632 million in four distribution
companies and two generation plants in Argentina. For further discussion of our
$632 million investment exposure in Argentina, see Note 10. Commitments and
Contingent Liabilities.
Resources invests principally in energy-related financing transactions,
principally leveraged leases. As such, it is designed to produce predictable
earnings at reasonable levels with relatively low risk. The modest risks faced
by Resources are the credit risk of its counterparties and the tax treatment of
its investment structures. Resources' earnings and cash flow streams are
dependent upon the availability of and its ability to continue to enter into
these transactions.
Energy Technologies is a business that principally constructs and installs
heating, ventilating and air conditioning equipment and related services. Energy
Technologies is comprised of 11 HVAC and mechanical operating companies and an
asset management group which includes various DSM investments.
RESULTS OF OPERATIONS
Our business consists of five reportable segments which are Power, PSE&G,
Global, Resources and Energy Technologies. The following is a discussion of the
major year-to-year financial statement variances and follows the financial
statement presentation as it relates to each of our segments. For a discussion
of management's determination of our reportable segments and related
disclosures, see Note 15. Financial Information by Business Segments.
Prior to April 1999, the discussion that follows reports on business
conducted under full monopoly regulation of the utility businesses. It must be
understood that such businesses have changed due to the deregulation of the
electric generation and natural gas commodity sales businesses, the subsequent
transfer of the generation business, and the anticipated transfer of the gas
supply business from PSE&G to Power. Past results are not an indication of
future business prospects or financial results.
5
Earnings (Losses)
------------------------------------------------
Year Ended December 31,
------------------------------------------------
2001 2000 1999 (A)
------------ ------------ ------------
(Millions of Dollars)
Power........................... $394 $313 $513
PSE&G........................... 230 369 131
Resources....................... 64 65 66
Global.......................... 116 40 28
Energy Technologies............. (18) (10) (6)
Other (B)....................... (16) (13) (9)
------------ ------------ ------------
Total PSEG................. $770 $764 $723
============ ============ ============
Contribution to Earnings Per Share
(Basic and Diluted)
------------------------------------------------
Year Ended December 31,
------------------------------------------------
2001 2000 1999 (A)
------------ ------------ ------------
Power........................... $1.89 $1.46 $2.33
PSE&G........................... 1.11 1.71 0.60
Resources....................... 0.31 0.30 0.30
Global.......................... 0.55 0.19 0.13
Energy Technologies............. (0.08) (0.05) (0.03)
Other (B)....................... (0.08) (0.06) (0.04)
------------ ------------ ------------
Total PSEG................. $3.70 $3.55 $3.29
============ ============ ============
(A) Excludes $804 million, net of tax, extraordinary item recorded in
1999.
(B) Other activities include amounts applicable to PSEG (parent
corporation), Energy Holdings (parent corporation) and EGDC. Losses
primarily result from after-tax effect of interest on certain
financing transactions and certain other administrative and general
expenses at parent companies.
For the Year Ended December 31, 2001 compared to the Year Ended December 31,
2000
Basic and diluted earnings per share of our common stock (Common Stock)
were $3.70 for the year ended December 31, 2001, an increase of $0.15 per share,
or 4.2% from the comparable 2000 period, including $0.12 of accretion as a
result of our stock repurchase program, discussed in Liquidity and Capital
Resources. In addition, our improved earnings for 2001 as compared to 2000
resulted from improved energy trading margins, Global's withdrawal and sale of
its interest in the Eagle Point Cogeneration Partnership (Eagle Point),
acquisitions and expanded operations at Global, new leveraged lease investments
at Resources and continued strong performance of our nuclear facilities. These
improvements more than offset the effects of unfavorable weather conditions at
PSE&G, two BPU mandated 2% rate reductions effective in February 2001 and August
2001, which reduced generation revenues, and the effects of the securitization
transaction that occurred on January 31, 2001.
Operating Revenues
For the year ended December 31, 2001, Operating Revenues increased by $534
million or 8%, primarily due to Global's withdrawal and sale of its interest in
the Eagle Point Cogeneration Partnership (Eagle Point), acquisitions and
expanded operations at Global, new leveraged lease investments at Resources, an
increase in BGS revenues and trading margins. These improvements more than
offset the effects of unfavorable weather conditions at PSE&G, two BPU mandated
2% rate reductions effective in February 2001 and August 2001, which reduced
generation revenues.
Revenues from Power's operations increased $176 million in 2001 as compared
to 2000 primarily due to an increase of $180 million in BGS revenue for the year
ended December 31, 2001 as compared to 2000 which resulted
6
from customers returning to PSE&G in 2001 from third party suppliers (TPS) as
wholesale market prices exceeded fixed BGS rates. At December 31, 2001, TPS were
serving less than 1% of the customer load traditionally served by PSE&G as
compared to the December 31, 2000 level of 10.5%. Also, margins from energy
trading increased by $68 million or 94% for the year ended December 31, 2001.
Partially offsetting this increase was a net $40 million decrease in MTC
revenues, relating to two 2% rate reductions offset by a pre-tax charge to
income related to MTC recovery in 2000. As of December 31, 2001, as required by
the Final Order, PSE&G has had rate reductions totaling 9% since August 1, 1999
and will have an additional 4.9% rate reduction effective August 1, 2002, which
will be in effect until July 31, 2003.
In our PSE&G segment, gas distribution revenues increased $153 million or
7% in 2001 as compared to 2000 primarily due to higher gas costs experienced in
2001. Customer rates in all classes of business have increased in 2001 to
recover a portion of the higher natural gas costs. The commercial and industrial
classes fuel recovery rates vary monthly according to the market price of gas.
The BPU also approved increases in the fuel component of the residential class
rates of 16% in November 2000 and 2% for each month from December 2000 through
July 2001. These increased revenues were partially offset by lower sales volumes
in the fourth quarter of 2001 than the comparable period in 2000, primarily
resulting from warmer weather.
Pursuant to a settlement, the BPU issued an order approving a $90 million
gas base rate increase effective January 9, 2002. The BPU approved the
settlement simultaneously with the implementation of PSE&G's previously approved
Gas Cost Underrecovery Adjustment (GCUA) surcharge to recover its October 31,
2001 gas cost under-recovery balance of approximately $130 million over a three
year period with interest and also approved PSE&G's proposal to reduce its
2001/2003 Commodity Charges (formerly Levelized Gas Adjustment Clause (LGAC)) by
approximately $140 million. The net impact of simultaneously implementing the
above three proceedings for the typical gas residential heating customers is an
approximate rate reduction of 2%.
The remaining $39 million of the increase related to the PSE&G segment and
was primarily related to increases in electric distribution and appliance
service revenue.
Electric revenues in the Global segment increased $128 million primarily
due to revenues related to various majority-owned acquisitions and plants going
into operation at our Global segment in 2001.
Global's other revenues increased $99 million primarily realized from the
gain of $75 million on the withdrawal and sale of Global's interest in Eagle
Point and was partially offset by a loss in equity earnings of $17 million,
which was recorded in 2000 and not recorded in 2001, as a result of the
withdrawal. In addition, revenues benefited from an increase of $45 million in
interest income related to certain loans, notes and approximately $29 million of
increased revenues relating primarily to improved earnings of certain
non-consolidated projects. These increases were partially offset by lower
revenues due to a reduction in earnings related to the adverse effect of foreign
currency exchange rate movements between the United States Dollar and Brazilian
Real.
Revenues in the Resources segment increased by $9 million primarily due to
improved revenues of $45 million from higher leveraged lease income from new
leveraged lease transactions that was partially offset by lower Net Investment
Gains of $37 million.
Revenues at Energy Technologies decreased $67 million from 2000 to 2001 due
to our decision in June 2000 to exit the retail commodity business. Energy
Technologies recorded $67 million of energy supply revenues related to the
retail commodity business in 2000 and none in 2001. In 2002, we announced our
intention to sell the HVAC/mechanical contracting businesses of Energy
Technologies and all periods presented herein have been restated to reflect
those businesses as discontinued operations.
Operating Expenses
Energy Costs
Energy Costs increased $254 million or 11% in 2001 as compared to 2000.
This increase was due to increased electric energy costs of $129 million and
increased gas costs of $125 million.
7
Energy costs at Global increased by $55 million due to plant acquisitions
and other projects going into operation at Global in 2001.
Energy costs also increased due to higher costs at Power of $73 million.
The increase was largely due to increased load served under the BGS contracts.
The higher volumes produced coupled with increased in fuel costs, mainly natural
gas, added to the year-to-year variance. These increases were partially offset
by low cost generation from the continued strong performance of our nuclear
generation facilities.
Energy Costs in the PSE&G segment increased $125 million or 8% in 2001 as
compared to 2000 due to higher natural gas prices at our PSE&G segment in the
early part of 2001. Under the LGAC in PSE&G, underrecoveries or overrecoveries,
together with interest (in the case of net overrecoveries), are deferred and
included in operations in the period in which they are reflected in rates.
Operation and Maintenance
Operation and Maintenance expense increased $137 million or 8% in 2001 as
compared to 2000. Contributing to the increase were higher operating expenses
relating to various majority-owned acquisitions and new plants going into
operation at Global in 2001. Additionally, operation and maintenance expenses
increased due to planned generation outage work in the first quarter of 2001 and
higher expenses relating to projects going into operation during the second
quarter of 2000 for our Power segment and the deferral of costs incurred during
2000 in connection with deregulation that PSE&G expects to recover in future
rates.
Depreciation and Amortization
Depreciation and Amortization expense increased $156 million or 44% in 2001
as compared to 2000. The 2001 increase was due primarily due to $180 million of
amortization of the regulatory asset recorded for PSE&G's stranded costs, which
commenced with the issuance of the transition bonds, previously discussed. These
increases were partially offset by a reduction in the accrual for the estimated
cost of removal in our Power segment.
Taxes Other Than Income Taxes
Taxes Other Than Income Taxes decreased $14 million or 10% in 2001 as
compared to 2000. This decrease was primarily due to a reduction in the net
taxable Transitional Energy Facility Assessment (TEFA) sales and the scheduled
phase out of the TEFA. The TEFA was enacted as part of the energy tax reform
bill and was scheduled to be phased out by 2003. Recent legislation delayed the
phase out until 2007.
Interest Expense
Interest expense increased $124 million or 22% in 2001 as compared to 2000.
The increase was primarily due to increased debt associated with the issuance of
$2.525 billion securitization bonds by Transition Funding and the issuance of
$1.8 billion of senior notes by Power to finance the generation asset transfer.
These increases were offset by a general reduction in the amount of short-term
and long-term debt at PSEG and PSE&G using proceeds from securitization bonds.
Interest expense at Energy Holdings increased $46 million primarily from
additional borrowings used for equity investments in Global and Resources.
Preferred Securities Dividend Requirements of Subsidiaries
Preferred Securities Dividend Requirements decreased $22 million or 23% in
2001 as compared to 2000 due to redemption of trust preferred securities.
Income Taxes
Income Taxes decreased $115 million or 23% in 2001 as compared to 2000. The
decrease was primarily due to lower pre-tax income and normal adjustments as a
result of closing the audit for the 1994-1996 tax years and upon filing our
actual tax return for 2000.
8
Losses From Discontinued Operations
Energy Technologies' Investments
Energy Technologies is comprised of 11 heating, ventilating and air
conditioning (HVAC) and mechanical operating companies and an asset management
group, which includes various Demand Side Management (DSM) investments. DSM
investments in long-term contracts represent expenditures made by Energy
Technologies to share DSM customers' costs associated with the installation of
energy efficient equipment. DSM revenues are earned principally from monthly
payments received from utilities, which represent shared electricity savings
from the installation of the energy efficient equipment.
In 2002, we adopted a plan to sell our interests in the HVAC/mechanical
operating companies. The sale of the HVAC/mechanical operating companies is
planned to be completed by June 30, 2003. We have retained the services of an
investment banking firm which is marketing the HVAC/mechanical operating
companies to interested parties. Operating results of the HVAC/mechanical
operating companies of Energy Technologies, less certain allocated costs from
Energy Holdings, have been reclassified as discontinued operations in our
Consolidated Statements of Income. For the years ended December 31, 2000 and
1999, the businesses of Energy Technologies included retail commodity sales of
electricity and natural gas, which do not qualify for accounting treatment as
discontinued operations. The HVAC/mechanical operating companies results of
operations of discontinued operations for the three years ended December 31,
2001, 2000 and 1999, respectively, are disclosed below:
Years Ended December 31,
--------------------------------------------
2001 2000 1999
--------------------------------------------
(Millions of Dollars)
Operating Revenues.............. $ 441 $ 316 $ 183
Pre-Tax Operating Loss............ (31) (20) (21)
Loss Before Income Taxes............ (34) (17) (19)
Net Loss............................ (22) (12) (13)
Tanir Bavi
As of September 30, 2002, Global owned a 74% interest in Tanir Bavi Power
Company Private Ltd. (Tanir Bavi), which owns and operates a 220 MW barge
mounted, combined-cycle generating facility in India. A plan to exit Tanir Bavi
was adopted in 2002. Global signed an agreement in August 2002 under which an
affiliate of its partner in this venture, GMR Vasavi Group, a local Indian
company, purchased Global's majority interest in Tanir Bavi. The sale was
completed in October 2002. In the second quarter of 2002, we reduced the
carrying value of Tanir Bavi to the contracted sales price of $45 million and
recorded a loss on disposal in the second quarter of 2002 of $14 million
(after-tax). The operating results of Tanir Bavi for the six months ended June
30, 2002 yielded income of $5 million (after-tax).
Tanir Bavi meets the criteria for classification as a component of
discontinued operations and all prior periods have been reclassified to conform
to this reclassification. Our share of operating results of this discontinued
operation are summarized in the following table:
Years Ended December 31,
---------------------------------------------
2001 2000 1999
------------ ----------- ------------
(Millions of dollars)
Operating Revenues................. $ 56 $ -- $ --
Operating Income .................. 16 -- --
Income Before Income Taxes......... 14 -- --
Net Income.......................... 7 -- --
9
For the Year Ended December 31, 2000 compared to the Year Ended December 31,
1999
Excluding the $804 million, net of tax, extraordinary charge recorded in
1999, resulting from charges incurred related to the deregulation, basic and
diluted earnings per share increased $0.26 for the year ended December 31, 2000
as compared to 1999, including $0.08 of accretion as a result of our stock
repurchase program. For further discussion, see Note 4. Regulatory Issues and
Accounting Impacts of Deregulation of Notes. This increase was primarily due to
lower depreciation and amortization resulting from the amortization of the
excess depreciation reserve at our PSE&G segment beginning in January 2000 and
the lower depreciation resulting from the lower recorded amounts of the
generation-related assets in Power resulting from the 1999 impairment recorded
pursuant to SFAS No. 121, "Accounting for the Impairment of Long Lived Assets
and for Long Lived Assets to be Disposed Of". Also contributing to the increase
were increased sales due to favorable weather conditions in the fourth quarter
of 2000 and higher profits realized from our energy trading transactions. In
addition, better overall performance of our Global segment, which benefited from
favorable performance by its domestic generation assets and by its investments
made in South America distribution assets in 1999, contributed to the increase.
The increase in earnings was partially offset by the 5% electric rate reduction,
beginning August 1, 1999 coupled with a charge to income in the third quarter of
2000 related to MTC recovery at Power.
Operating Revenues
For the year ended December 31, 2000, Operating Revenues increased by $182
million or 3%, primarily due to increased revenues from gas distribution, net
trading revenues and leveraged lease investments partially offset by decreased
electric revenues due to rate reductions required by deregulation.
Power's revenues decreased $244 million or 6% in 2000 as compared to 1999
due to a 5% rate reduction, which decreased our revenues by approximately $120
million combined with a $115 million deferral of MTC revenues, and reduced
retail demand as PSE&G lost retail customers to TPS which amounted to
approximately $182 million partially offset by increased trading margins. See
Accounting Issues - Accounting for the Effects of Regulation for a discussion of
the deferral of MTC revenues. These decreases were partially offset by increased
revenues from our PSE&G segment relating to higher transmission and distribution
sales.
To the extent fuel expense flowed through the Electric Levelized Energy
Adjustment Clause (LEAC) through July 31, 1999, the Levelized Gas Adjustment
Clause (LGAC), the Societal Benefits Clause (SBC) or the non-utility generation
market transition charge (NTC) mechanisms, as established by the BPU with
respect to PSE&G's rates, variances in certain revenues and expenses offset and
thus had no effect on earnings. On August 1, 1999, the LEAC mechanism was
eliminated as a result of the Final Order. This has increased earnings
volatility since Power now bears the full risks and rewards of changes in
nuclear and fossil generating fuel costs and purchased power costs. See Note 4.
Regulatory Issues and Accounting Impacts of Deregulation for a discussion of
LEAC, LGAC, SBC, NTC, Remediation Adjustment Clause (RAC) and Demand Side
Management (DSM) and their status under the Energy Master Plan Proceedings.
Revenues from our PSE&G segment for gas distribution increased $423 million
or 25% in 2000 as compared to 1999 primarily due to increases in natural gas
prices being passed along to customers under certain transportation only
contracts. Under these contracts, PSE&G is responsible only for delivery of gas
to its customers. Such customers are responsible for payment to PSE&G for the
cost of the commodity and as PSE&G's costs for these customers increase, the
customer's rates will increase. Also contributing to this increase were higher
sales resulting from colder weather in the fourth quarter of 2000 as compared to
the same period in 1999 and higher rates approved by the BPU to allow PSE&G to
recover for increasing natural gas costs.
Revenues for Global decreased by $42 million primarily due to a gain on
sale of Newark Bay recorded in 1999 as compared to no significant gain on sale
of assets in 2000.
Revenues for Resources increased by $26 million due to higher leveraged
lease income from new leveraged lease investments.
Revenues at Energy Technologies decreased $19 million from 1999 to 2000 due
to our decision in June 2000 to exit the retail commodity business. In 2002, we
announced our intention to sell the HVAC businesses of Energy
10
Technologies and all periods presented herein have been restated to reflect
those businesses as discontinued operations.
Operating Expenses
Energy Costs
Energy Costs increased $397 million or 20% in 2000 as compared to 1999.
This increase was primarily due to increased gas costs of approximately $364
million and increased electric energy costs of approximately $33 million.
Energy Costs increased $364 million or 33% in 2000 as compared to 1999
primarily due to the higher prices for natural gas and increased demand for
natural gas at our PSE&G segment due to colder weather in the fourth quarter of
2000 as compared to the same period in 1999. Due to the operation of the
Levelized Gas Adjustment Clause (LGAC) mechanism, variances in gas revenues and
costs at PSE&G offset and had no direct effect on earnings.
Energy costs increased $38 million primarily due to higher fuel costs in
Power and additional costs related to projects in our Global segment.
Due to the elimination of the LEAC on August 1, 1999, the historical trends
can no longer be considered an indication of future Electric Energy Costs. Given
the elimination of the LEAC, the lifting of the requirements that electric
energy offered for sale in the Pennsylvania-New Jersey-Maryland Power Pool (PJM)
not exceed the variable cost of producing such energy (capped at $1,000 per
megawatt-hour), the absence of a PJM price cap in situations involving emergency
purchases and the potential for plant outages, price movements could have a
material impact on our financial condition, results of operations or net cash
flows.
Operation and Maintenance
Operation and Maintenance expense decreased $44 million or 3% in 2000 as
compared to 1999. The decrease was mainly due to a $55 million pre-tax charge to
earnings to reduce the carrying value of certain assets at Global and EGDC in
1999.
Depreciation and Amortization
Depreciation and Amortization expense decreased $177 million or 33% in 2000
as compared to 1999. The decrease was primarily due to the amortization of the
regulatory liability for the excess electric distribution depreciation reserve
at PSE&G, which amounted to approximately $125 million as of December 31, 2000.
Also contributing to the decrease was lower depreciation resulting from the
lower net book value balances of Power's generation assets. The generation asset
balances were reduced as of April 1, 1999 as a result of the impairment recorded
pursuant to SFAS 121.
Taxes Other Than Income Taxes
Taxes Other Than Income Taxes, which include TEFA, decreased $20 million or
13% in 2000 as compared to 1999 due to New Jersey Energy tax reform and the
five-year commencing in January 1999. Effective January 1, 2000, revised rates
became effective which reflected two years phase out of the TEFA discussed
previously.
Interest Expense
Interest expense increased $82 million or 17% in 2000 as compared to 1999.
The increase was primarily due to interest expense associated with recourse
financing activities at Energy Holdings which increased $51 million from
additional borrowings incurred as a result of equity investments in distribution
and generation facilities and the repayment of non-recourse debt. Also
contributing to the increase was the interest related to higher levels of
short-term debt.
11
Income Taxes
Income Taxes decreased $73 million or 13% in 2000 as compared to 1999. The
decrease is primarily due to a decrease in the foreign tax liability from
foreign investments at Global recorded under the equity method. Under such
accounting method, Global reflects in revenues its pro rata share of investments
net income. Under this accounting method, the foreign income taxes are a
component of equity in earnings, thereby distorting the effective tax rate
downward. During 1999, there was an increase in state income taxes at Resources
totaling $11 million due to the early termination of a leveraged lease. The
decrease was also due to lower effective tax rates relating to the amortization
of the excess depreciation reserve for electric distribution.
Losses From Discontinued Operations
See the discussion of Losses from Discontinued Operations above for the
comparison of results for the year ended December 31, 2000 compared to the year
ended December 31, 1999.
LIQUIDITY AND CAPITAL RESOURCES
The following discussion of our liquidity and capital resources is on a
consolidated basis, noting the uses and contributions of our three direct
operating subsidiaries in 2001, PSE&G, Power and Energy Holdings.
Our capital requirements and those of our subsidiaries are met and
liquidity provided by internally generated cash flow and external financings.
PSEG, Power and Energy Holdings from time to time make equity contributions to
their respective direct and indirect subsidiaries to provide for part of their
capital and cash requirements, generally relating to long-term investments. At
times, we utilize inter-company dividends and inter-company loans to satisfy
various subsidiary needs and efficiently manage our and our subsidiaries'
short-term cash needs. Any excess funds are invested in accordance with
guidelines adopted by our Board of Directors.
External funding to meet our needs and the needs of PSE&G, the majority of
the requirements of Power and a substantial portion of the requirements of
Energy Holdings, is comprised of corporate finance transactions. The debt
incurred is the direct obligation of those respective entities. Some of the
proceeds of these debt transactions are used by the respective obligor to make
equity investments in its subsidiaries.
All of our publicly traded debt, as well as that of PSE&G, Power and Energy
Holdings, have received investment grade ratings from each of the three major
credit rating agencies. The changes in the energy industry and the recent
bankruptcy of Enron Corp. are attracting increased attention from the rating
agencies which regularly assess business and financial matters. Given the
changes in the industry, attention to and scrutiny of our, PSE&G's, Power's and
Energy Holdings' performance, capital structure and competitive strategies by
rating agencies will likely continue. These changes could affect the bond
ratings, cost of capital and market prices of our respective securities. We will
continue to evaluate our capital structure, financing requirements, competitive
strategies and future capital expenditures to maintain our current credit
ratings.
The current ratings of securities of PSEG and its subsidiaries are shown
below and reflect the respective views of the rating agencies, from whom an
explanation of the significance of their ratings may be obtained. There is no
assurance that these ratings will continue for any given period of time or
that they will not be revised or withdrawn entirely by the rating agencies,
if, in their respective judgments, circumstances so warrant. Any downward
revision or withdrawal may adversely effect the market price of PSEG's, Energy
Holdings' Powers and PSE&G's securities and serve to increase those companies'
cost of capital.
12
Moody's Standard & Poor's Fitch
------------------------------------------------------------------
PSEG
-----------------------------
Extendible Notes Baa2 BBB BBB+
Preferred Securities Baa3 BB+ BBB
Commercial Paper P2 A2 Not Rated
PSE&G
-----------------------------
Mortgage Bonds A3 A- A
Preferred Securities Baa1 BBB A-
Commercial Paper P2 A2 F1
Power
-----------------------------
Senior Notes Baa1 BBB BBB+
Energy Holdings
-----------------------------
Senior Notes Baa3 BBB- BBB-
PSEG Capital
-----------------------------
Medium Term Notes Baa2 BBB Not Rated
Depending on the particular company, external financing may consist of
public and private capital market debt and equity transactions, bank revolving
credit and term loan facilities, commercial paper and/or project financings.
Some of these transactions involve special purpose entities. These are
corporations, limited liability companies or partnerships formed in accordance
with applicable tax, accounting and legal requirements in order to achieve
specified beneficial financial advantages, such as favorable tax, legal
liability or accounting treatment.
The availability and cost of external capital could be affected by each
subsidiary's performance as well as by the performance of their respective
subsidiaries and affiliates. This could include the degree of structural or
regulatory separation between us and our subsidiaries and between PSE&G and its
non-utility affiliates and the potential impact of affiliate ratings on
consolidated and unconsolidated credit quality. Additionally, compliance with
applicable financial covenants will depend upon future financial position and
levels of earnings and net cash flows, as to which no assurances can be given.
Financing for Global's projects and investments is generally provided by
non-recourse project financing transactions. These consist of loans from banks
and other lenders that are typically secured by project and special purpose
subsidiary assets and/or cash flows. Two of Power's projects currently under
construction have similar financing. Non-recourse transactions generally impose
no obligation on the parent-level investor to repay any debt incurred by the
project borrower. However, in some cases, certain obligations relating to the
investment being financed, including additional equity commitments, are
guaranteed by Global, Energy Holdings, and/or Power. Further, the consequences
of permitting a project-level default include loss of any invested equity by the
parent.
Our debt indentures and credit agreements and those of our subsidiaries
contain cross-default provisions under which a default by us or by specified
subsidiaries involving specified levels of indebtedness in other agreements
would result in a default and the potential acceleration of payment under such
indentures and credit agreements. For example, a default for a specified amount
with respect to any indebtedness of Global and Power, as set forth in various
credit agreements, including obligations in non-recourse transactions, could
cause a cross-default in one of our or our subsidiaries' credit agreements.
Such lenders, or the debt holders under any of our or our subsidiaries'
indentures, could determine that debt payment obligations may be accelerated as
a result of a cross-default. These occurrences could severely limit our
liquidity and restrict our ability to meet our debt, capital and, in extreme
cases, operational cash requirements. Any inability to satisfy required
covenants and/or borrowing conditions would have a similar impact. This would
have a material adverse effect on our financial condition, results of operations
and net cash flows, and those of our subsidiaries.
In addition, our credit agreements and those of our subsidiaries generally
contain provisions under which the lenders could refuse to advance loans in the
event of a material adverse change in the borrower's, and as may be relevant,
our, Energy Holdings', Power's or PSE&G's business or financial condition. In
the event that we or the
13
lenders in any of our or our subsidiaries' credit agreements determine that a
material adverse change has occurred, loan funds may not be advanced.
Some of these credit agreements also contain maximum debt to equity ratios,
minimum cash flow tests and other restrictive covenants and conditions to
borrowing. Compliance with applicable financial covenants will depend upon our
future financial position and the level of earnings and cash flow, as to which
no assurances can be given. As part of our financial planning forecast, we
perform stress tests on our financial covenants. These tests include a
consideration of the impacts of potential asset impairments, foreign currency
fluctuations, and other items. Our current analyses and projections indicate
that, even in a worst-case scenario with respect to our investments in Argentina
and considering other potential events, we will still be able to meet our
financial covenants.
Our debt indentures and credit agreements and those of our subsidiaries do
not contain any "ratings triggers" that would cause an acceleration of the
required interest and principal payments in the event of a ratings downgrade.
However, in the event of a downgrade we and/or our subsidiaries may be subject
to increased interest costs on certain bank debt. Also, in connection with its
energy trading business, Power must meet certain credit quality standards as are
required by counterparties. If Power loses its investment grade credit rating,
ER&T would have to provide credit support (letters of credit or cash), which
would significantly impact the energy trading business. These same contracts
provide reciprocal benefits to Power. Global and Energy Holdings may have to
provide collateral for certain of their equity commitments if Energy Holdings'
ratings should fall below investment grade. This would increase our costs of
doing business and limit our ability to successfully conduct our energy trading
operations. In addition, our counterparties may require us to meet margin or
other security requirements which may include cash payments.
Capital resources and investment requirements could be affected by the
outcome of proceedings by the BPU pursuant to the Energy Competition Act and the
requirements of the 1992 Focused Audit conducted by the BPU, of the impact of
our non-utility businesses, owned by Energy Holdings, on PSE&G. As a result of
the Focused Audit, the BPU ordered that, among other things:
(1) We will not permit Energy Holdings' investments to exceed 20% of our
consolidated assets without prior notice to the BPU;
(2) PSE&G's Board of Directors would provide an annual certification that
the business and financing plans of Energy Holdings will not adversely
affect PSE&G
(3) We will (a) limit debt supported by the minimum net worth maintenance
agreement between us and PSEG Capital to $650 million and (b) make a
good-faith effort to eliminate such support over a six to ten year
period from May 1993; and
(4) Energy Holdings will pay PSE&G an affiliation fee of up to $2 million
a year which is to be used to reduce customer rates.
In the Final Order the BPU noted that, due to significant changes in the
industry and, in particular, our corporate structure as a result of the Final
Order, modifications to or relief from the Focused Audit order might be
warranted. PSE&G has notified the BPU that PSEG will eliminate PSEG Capital debt
by the end of 2003 and that it believes that the Final Order otherwise
supercedes the requirements of the Focused Audit. While we believe that this
issue will be satisfactorily resolved, no assurances can be given.
In addition, if we were no longer to be exempt under the Public Utility
Holding Company Act of 1935 (PUHCA), we and our subsidiaries would be subject to
additional regulation by the SEC with respect to financing and investing
activities, including the amount and type of non-utility investments. We believe
that this would not have a material adverse effect on our financial condition,
results of operations and net cash flows.
Over the next several years, we and our subsidiaries will be required to
refinance maturing debt, incur additional debt and provide equity to fund
investment activity. Any inability to obtain required additional external
capital or to extend or replace maturing debt and/or existing agreements at
current levels and reasonable interest rates may affect our financial condition,
results of operations and net cash flows.
14
We and our subsidiaries have the following credit facilities for various
funding purposes and to provide liquidity for our $850 million commercial
program and PSE&G's $900 million commercial paper program. These agreements are
with a group of banks and provide for borrowings with maturities of up to one
year. The following table summarizes our various facilities as of December 31,
2001.
Commercial
Maturity Total Primary Amount Paper (Cp)
Company Date Facility Purpose Outstanding Outstanding
------------------------------------------- -------- -------- ------- ----------- -----------
(MILLIONS OF DOLLARS)
PSEG
-------------------------------------------
364-day Credit Facility March 2002 $570 CP Support $ -- $475
5-year Credit Facility March 2002 280 CP Support -- N/A
5-year Credit Facility December 2002 150 Funding 125 N/A
Bilateral Credit Agreement N/A No Limit Funding 153 N/A
PSE&G
-------------------------------------------
364-day Credit Facility June 2002 390 CP Support -- --
5-year Credit Facility June 2002 450 CP Support -- --
Bilateral Credit Agreement June 2002 60 CP Support -- --
Bilateral Credit Agreement N/A No Limit Funding -- N/A
Energy Holdings
-------------------------------------------
364-day Credit Facility May 2002 200 Funding -- N/A
5-year Credit Facility May 2004 495 Funding 250 N/A
Bilateral Credit Agreement N/A 100 Funding 50 N/A
---- ----
Total N/A $578 $475
==== ====
PSEG
As of December 31, 2001, we had repurchased approximately 26.5 million
shares of Common Stock, at a cost of approximately $997 million since 1998. The
repurchased shares have primarily been held as treasury stock with the balance
used for general corporate purposes.
Dividend payments on Common Stock were $2.16 per share and totaled
approximately $449 million and $464 million for the years ended December 31,
2001 and 2000, respectively. Our dividend rate has remained constant since 1992
in order to retain additional capital for reinvestment and to reduce the payout
ratio as earnings grow. Although we presently believe we will have adequate
earnings and cash flow in the future from our subsidiaries to maintain common
stock dividends at the current level, earnings and cash flows required to
support the dividend will become more volatile as our business continues to
change from one that is principally regulated to one that is principally
competitive. Future dividends declared will necessarily be dependent upon our
future earnings, cash flows, financial requirements, alternate investment
opportunities and other factors.
We have issued Deferrable Interest Subordinated Debentures in connection
with the issuance of tax deductible preferred securities. If payments on these
Deferrable Interest Subordinated Debentures are deferred, in accordance with
their terms, PSEG may not pay any dividends on its common stock until such
default is cured. Currently, there has been no deferral or default.
Financial covenants contained in our facilities include the ratio of debt
(excluding non-recourse project financings and securitization debt and including
commercial paper and loans) to total capitalization. At the end of any quarterly
financial period such ratio shall not be more than .70 to 1. As of December 31,
2001, the ratio of debt to capitalization was .64 to 1.
In June 2001, $300 million of Extendible Notes, Series C matured.
In 2001, we invested $400 million in Energy Holdings and expect to make
approximately the same contribution in 2002.
15
PSE&G
Under its Mortgage, PSE&G may issue new First and Refunding Mortgage Bonds
against previous additions and improvements and/or retired Mortgage Bonds
provided that its ratio of earnings to fixed charges calculated in accordance
with its Mortgage is at least 2:1. At December 31, 2001, PSE&G's Mortgage
coverage ratio was 3:1. As of December 31, 2001, the Mortgage would permit up to
approximately $1 billion aggregate principal amount of new Mortgage Bonds to be
issued against previous additions and improvements. PSE&G will need to obtain
BPU authorization to issue any incremental debt financing necessary for its
capital program, including refunding of maturing debt and opportunistic
refinancing. In January 2002, PSE&G filed a petition with the BPU for
authorization to issue $1 billion of long-term debt through December 31, 2003.
On December 27, 2001, PSE&G filed a shelf registration statement on Form
S-3 for the issuance of $1 billion of debt and tax deferred preferred
securities, which was declared effective by the SEC in February 2002.
On January 31, 2001, $2.525 billion of transition bonds were issued by
PSE&G Transition Funding LLC, a bankruptcy-remote, wholly-owned subsidiary of
PSE&G, in eight classes with maturities ranging from 1 year to 15 years. PSE&G
also received payment from Power on its $2.786 billion promissory note used to
finance the transfer of its generation business to Power. The proceeds from
these transactions were used to pay for certain debt issuance and related costs
for securitization, retire a portion of PSE&G's outstanding short-term debt,
reduce PSE&G's common equity, loan funds to us and make various short-term
investments.
In March 2001, PSE&G redeemed all of its $150 million of 9.375% Series A
cumulative monthly income preferred securities, all of its $75 million of 5.97%
preferred stock, $15 million of its 6.75% preferred stock and $52 million of its
floating rate notes due December 7, 2002. In June 2001, PSE&G redeemed the
remaining $248 million outstanding of floating rate notes due December 7, 2002.
In June 2001, PSE&G redeemed all of its $208 million of 8.625% Series A
cumulative quarterly income preferred securities.
In November 2001, $100 million of PSE&G Mortgage Bonds, Series FF matured.
Also in November 2001, PSE&G redeemed $105 million of its variable rate
Pollution Control Notes. In December 2001, PSE&G redeemed an additional $19
million of its variable rate Pollution Control Notes.
Since 1986, PSE&G has made regular cash payments to us in the form of
dividends on outstanding shares of PSE&G's common stock. PSE&G paid common stock
dividends of $112 million and $638 million to us for the years ended December
31, 2001 and 2000, respectively.
PSE&G has issued Deferrable Interest Subordinated Debentures in connection
with the issuance of tax deductible preferred securities. If payments on those
Deferrable Interest Subordinated Debentures are deferred, in accordance with
their terms, PSE&G may not pay any dividends on its common or preferred stock
until such default is cured. Currently, there has been no deferral or default.
Power
Power's short-term financing needs will be met using our commercial paper
program or lines of credit discussed above. As of December 31, 2001, letters of
credit were issued in the amount of approximately $100 million.
In April 2001, Power issued $500 million of 6.875% Senior Notes due 2006,
$800 million of 7.75% Senior Notes due 2011 and $500 million 8.625% Senior Notes
due 2031. The net proceeds from the sale of the senior notes were used primarily
for the repayment of loans from us.
In August 2001, subsidiaries of Power closed on $800 million of
non-recourse project bank financing for projects in Waterford, Ohio and
Lawrenceburg, Indiana. The total combined project cost for Waterford and
Lawrenceburg is estimated at $1.2 billion. Power's required estimated equity
investment in these projects is approximately $400 million. In connection with
these projects, ER&T has entered into a five-year tolling agreement pursuant to
which it is obligated to purchase the output of these facilities at stated
prices. As a result, ER&T will bear the price risk related to the output of
these generation facilities, which are scheduled to be completed in 2003.
16
In the fourth quarter of 2001, Power issued $124 million in Pollution
Control Notes.
Energy Holdings
As of December 31, 2001, Energy Holdings had two separate senior revolving
credit facilities with a syndicate of banks as discussed in the table above. The
five-year facility permits up to $250 million of letters of credit to be issued
of which $57 million are outstanding as of December 31, 2001.
Financial covenants contained in these facilities include the ratio of cash
flow available for debt service (CFADS) to fixed charges. At the end of any
quarterly financial period such ratio shall not be less than 1.50x for the
12-month period then ending. As a condition of borrowing, the pro-forma CFADS to
fixed charges ratio shall not be less than 1.75x as of the quarterly financial
period ending immediately following the first anniversary of each borrowing or
letter of credit issuance. CFADS includes, but is not limited to, operating cash
before interest and taxes, pre-tax cash distributions from all asset
liquidations and equity capital contributions from us to the extent not used to
fund investing activity. In addition, the ratio of consolidated recourse
indebtedness to recourse capitalization, as at the end of any quarterly
financial period, shall not be greater than 0.60 to 1.00. This ratio is
calculated by dividing the total recourse indebtedness of Energy Holdings by the
total recourse capitalization. This ratio excludes the debt of PSEG Capital,
which is supported by us. As of December 31, 2001, the latest 12 months CFADS
coverage ratio was 4.4 and the ratio of recourse indebtedness to recourse
capitalization was .45 to 1.
PSEG Capital has a $750 million MTN program which provides for the private
placement of MTNs. This MTN program is supported by a minimum net worth
maintenance agreement between PSEG Capital and us which provides, among other
things, that we (1) maintain its ownership, directly or indirectly, of all
outstanding common stock of PSEG Capital, (2) cause PSEG Capital to have at all
times a positive tangible net worth of at least $100,000 and (3) make sufficient
contributions of liquid assets to PSEG Capital in order to permit it to pay its
debt obligations. We believe that we are capable of eliminating our support of
PSEG Capital debt within the time period set forth in the Focused Audit. In
October 2001, $135 million of 6.74% MTNS matured and were refinanced with funds
from the issuance of short-term debt at Energy Holdings. At December 31, 2001
and December 31, 2000, total debt outstanding under the MTN program was $480
million and $650 million, respectively maturing from 2002 to 2003.
In February 2001, Energy Holdings sold $400 million of 8.625% Senior Notes
due 2008 and in July 2001, sold $550 million of 8.50% Senior Notes due 2011. The
net proceeds were used to repay short-term debt outstanding from intercompany
loans and borrowings under Energy Holdings' revolving credit facilities and for
general corporate purposes.
In March 2001, $160 million of non-recourse bank debt originally incurred
to fund a portion of the purchase price of Global's interest in Chilquinta
Energia, S.A. was refinanced. The private placement offering by Chilquinta
Energia Finance Co. LLC, a Global affiliate, of senior notes was structured in
two tranches: $60 million due 2008 at an interest rate of 6.47% and $100 million
due 2011 at an interest rate of 6.62%. An extraordinary loss of $2 million
(after-tax) was recorded in connection with the refinancing of the $160 million
non-recourse bank debt.
In October 2001, PSEG Chile Holdings, a wholly-owned subsidiary of Global
and a United States functional currency entity closed on $150 million of project
financing related to its investment in SAESA, a Chilean Peso functional currency
entity. The debt is variable and is based on LIBOR. In connection with this
project financing, PSEG Chile Holdings entered into two foreign currency forward
exchange contracts with a total notional amount of $150 million. The two
contracts were entered into to hedge the Peso/United States Dollar exposure on
the net investment.
17
CAPITAL REQUIREMENTS
For the year ended December 31, 2001, we made net plant additions of $2.053
billion, excluding Allowance for Funds Used During Construction (AFDC) and
capitalized interest. The majority of these additions, $1.5 billion, primarily
related to Power for developing the Lawrenceburg, Indiana and the Waterford,
Ohio sites and adding capacity to the Bergen, Linden, Burlington and Kearny
stations in New Jersey. In addition, PSE&G had net plant additions of $398
million related to improvements in its transmission and distribution system, gas
system and common facilities.
Also in 2001, Energy Holdings' subsidiaries made investments totaling
approximately $1.7 billion. These investments included leveraged lease
investments totaling $460 million by Resources and new acquisitions by Global
and additional investments in existing domestic and international facilities.
Forecasted Expenditures
Our subsidiaries have substantial commitments as part of their growth
strategies and ongoing construction programs. We expect that the majority of
each subsidiaries' capital requirements over the next five years will come from
internally generated funds, with the balance to be provided by the issuance of
debt at the subsidiary or project level and equity contributions from us.
Projected construction and investment expenditures for our subsidiaries for
the next five years are as follows:
2002 2003 2004 2005 2006
(Millions of Dollars)
Power........................ $ 960 $ 700 $ 340 $ 250 $ 230
Energy Holdings.............. 450 600 600 600 600
PSE&G........................ 485 440 440 450 465
----------------------------------------------------------------------------------
Total................... $ 1,895 $ 1,740 $ 1,380 $ 1,300 $ 1,295
==================================================================================
For a discussion of new generation and development and other commitments to
purchase equipment and services, all of which are included in our forecasts
above, see Note 10. Commitments and Contingent Liabilities
Power's capital needs will be dictated by its strategy to continue to
develop as a profitable, growth-oriented supplier in the wholesale power market.
Power will size its fleet of generation assets to take advantage of market
opportunities, while seeking to increase its value and manage commodity price
risk through its wholesale energy trading activity. A significant portion of
Power's projected investment expenditures in the latter part of this forecast
are not yet committed to specific projects.
Energy Holdings plans to continue the growth of Global and Resources. The
majority of Energy Holdings' projected investment expenditures are not yet
committed to specific projects. Investment activity is subject to periodic
review and revision and may vary significantly depending upon the opportunities
presented.
PSE&G's construction expenditures are primarily to maintain the safety and
reliability of its electric and gas transmission and distribution facilities.
Factors affecting our subsidiaries' actual expenditures and investments,
including ongoing construction programs, include: availability of capital,
suitable investment opportunities, prices of energy and supply in markets in
which we participate, economic and political trends, revised load forecasts,
business strategies, site changes, cost escalations under construction
contracts, requirements of regulatory authorities and laws, and the timing of
and amount of electric and gas transmission and/or distribution rate changes.
18
Disclosures about Contractual Obligations and Commercial Obligations and
Certain Investments
The following tables, reflect our and our subsidiaries' contractual cash
obligations and other commercial commitments in the respective periods in which
they are due.
Less
Total Amounts Than
Contractual Cash Obligations Committed 1 year 2 - 3 years 4 - 5 years Over 5 years
(Millions of Dollars)
------------------------------------------------------------------------------
Long - Term Debt $11,377 $1,066 $1,327 $1,586 $7,398
Capital Lease Obligations 102 8 16 16 62
Operating Leases 64 14 20 11 19
------------------------------------------------------------------------------
Total Contractual Cash Obligations $11,543 $1,088 $1,363 $1,613 $7,479
==============================================================================
We, Power, and Energy Holdings have guaranteed certain obligations of
affiliates, including the successful completion, performance or other
obligations and have contract equity contribution obligations related to certain
projects in an aggregate amount of approximately $730 million, as of December
31, 2001. A substantial portion of such guarantees is eliminated upon successful
completion, performance and/or refinancing of construction debt with
non-recourse project term debt.
In the normal course of business, Energy Technologies secures construction
obligations with performance bonds issued by insurance companies. In the event
that Energy Technologies' tangible equity falls below $100 million, Energy
Holdings would be required to provide additional support for the performance
bonds. As of December 31, 2001, Energy Technologies had tangible equity of $114
million and performance bonds outstanding of $124 million. The performance bonds
are not included in the table below.
Total Less
Amounts Than
Other Commercial Commitments Committed 1 year 2 - 3 years 4 - 5 years Over 5 years
--------- ------ ----------- ----------- ------------
(Millions of Dollars)
------------------------------------------------------------------------------
Standby Letters of Credit $159 $144 $5 $4 $ 6
Guarantees and Equity Commitments 571 428 101 - 42
------------------------------------------------------------------------------
Total Commercial Commitments $730 $572 $106 $4 $ 48
==============================================================================
Off Balance Sheet Arrangements
Global has certain investments that are accounted for under the equity
method in accordance with generally accepted accounting principles (GAAP).
Accordingly, an amount is recorded on our balance sheet which is primarily
Energy Holdings' equity investment and is increased for Energy Holdings'
pro-rata share of earnings less any dividend distribution from such investments.
The companies in which we invest that are accounted for under the equity method
have an aggregate $1.88 billion of debt on their combined, consolidated
financial statements. Our pro-rata share of such debt is $737 million and is
non-recourse to us, Energy Holdings and Global. We are generally not required to
support the debt service obligations of these companies. However, default with
respect to this non-recourse debt could result in a loss of invested equity.
Resources has investments in leveraged leases that are accounted for in
accordance with SFAS 13 "Accounting for Leases." Leveraged lease investments
generally involve three parties: an owner/lessor, a creditor, and a lessee. In a
typical leveraged lease financing, the lessor purchases an asset to be leased.
The purchase price is typically financed 80% with debt provided by the creditor
and the balance comes from equity funds provided by Resources. The creditor
provides long term financing to the transaction, and is secured by the property
subject to lease. Such long term financing is non-recourse to Resources. As
such, in the event of default the creditor may only look to the leased asset as
security for his loan. As a lessor, Resources has ownership rights to the
property and rents the property to the lessee for use in its business operation.
As of December 31, 2001 Resources' equity investment in leased assets was
approximately $1.6 billion, net of deferred taxes of approximately $1.2 billion.
For additional information, see Note 6. Long-Term Investments.
19
In the event that collectibility of the minimum lease payments to be
received by the lessor is no longer reasonably predictable, the accounting
treatment for some of the leases may change. In such cases, Resources may deem
that a lessee has a high probability of defaulting on the lease obligation. In
many instances, Resources has protected its equity investment in such
transactions by providing for the direct right to assume the debt obligation.
Debt assumption would be at Resources' sole discretion, and normally only would
occur if an appraisal of the leased property yielded a value that exceeds the
present value of the debt outstanding. Should Resources ever directly assume a
debt obligation, the fair value of the underlying asset and the associated debt
would be recorded on the balance sheet instead of the net equity investment in
the lease. In the events described above, the lease essentially changes from
being classified as a capital lease to a conventional operating lease.
QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The market risk inherent in our market risk sensitive instruments and
positions is the potential loss arising from adverse changes in foreign currency
exchange rates, commodity prices, equity security prices, and interest rates as
discussed in the notes to the financial statements. Our policy is to use
derivatives to manage risk consistent with our business plans and prudent
practices. We have a Risk Management Committee comprised of executive officers
which utilizes an independent risk oversight function to ensure compliance with
corporate policies and prudent risk management practices.
Counterparties expose us to credit losses in the event of non-performance
or non-payment. We have a credit management process which is used to assess,
monitor and mitigate counterparty exposure for us and our subsidiaries. In the
event of non-performance or non-payment by a major counterparty, there may be a
material adverse impact on our and our subsidiaries' financial condition,
results of operations or net cash flows.
Foreign Currencies
The objective of our foreign currency risk management policy is to preserve
the economic value of cash flows in non-functional currencies. Toward this
end, Energy Holdings' policy is to hedge all significant firmly committed cash
flows identified as creating foreign currency exposure. In addition, we
typically hedge a portion of exposure resulting from identified anticipated
cash flows, providing the flexibility to deal with the variability of
longer-term forecasts as well as changing market conditions, in which the cost
of hedging may be excessive relative to the level of risk involved.
As of December 31, 2001, Global and Resources had assets located or held in
international locations of approximately $3.4 billion and $1.3 billion,
respectively.
Resources' international investments are primarily leveraged leases of
assets located in Australia, Austria, Belgium, China, Germany, the Netherlands,
the United Kingdom, and New Zealand with associated revenues denominated in
United States Dollars ($US) and therefore, not subject to foreign currency risk.
Global's international investments are primarily in companies that generate
or distribute electricity in Argentina, Brazil, Chile, China, India, Italy,
Oman, Peru, Poland, Taiwan, Tunisia and Venezuela. Investing in foreign
countries involves certain additional risks. Economic conditions that result in
higher comparative rates of inflation in foreign countries are likely to result
in declining values in such countries' currencies. As currencies fluctuate
against the $US, there is a corresponding change in Global's investment value in
terms of the $US. Such change is reflected as an increase or decrease in the
investment value and Other Comprehensive Income (Loss), a separate component of
Stockholder's Equity. As of December 31, 2001, net foreign currency devaluations
have reduced the reported amount of Energy Holdings' total Stockholder's Equity
by $258 million (after-tax), of which $79 million (after-tax) was caused by
the devaluation of the Chilean Peso and $169 million (after-tax) was caused by
the devaluation of the Brazilian Real.
Global holds a 60% ownership interest in a Tunisian generation facility
under construction. The Power Purchase Agreement, signed in 1999, contains an
embedded derivative that indexes the fixed Tunisian dinar payments to United
States Dollar exchange rates. The embedded derivative is being marked to market
through the income statement. As of January 1, 2001, a $9 million gain was
recorded in the cumulative effect of accounting change for
20
SFAS No. 133. During 2001, an additional gain of $1.4 million was recorded to
the income statement as a result of favorable movements in the United States
Dollar to Tunisian dinar exchange rate.
Global holds approximately a 32% ownership interest in RGE whose debt is
denominated in United States Dollars. In December 2001, the distribution
company entered into a series of three forward exchange contracts to purchase
United States Dollars for Brazilian Reals in order to hedge the risk of
fluctuations in the exchange rate between the two currencies associated with
the upcoming principal payments on the debt. These contracts expire in May,
June and July 2002. As of December 31, 2001, Global's share of the fair value
and aggregate notional value of the contracts was approximately $13 million.
These contracts were established as hedges for accounting purposes resulting
in an after tax charge to Other Comprehensive Income (OCI) of approximately
$1.2 million. In addition, in order to hedge the foreign currency exposure
associated with the outstanding portion of the debt, Global entered into a
forward exchange contract in December 2001 to purchase United States Dollars
for Brazilian Reals in approximately their share of the total debt outstanding
($61 million). The contract expired prior to December 31, 2001 and was not
designated as a hedge for accounting purposes. As a result of unfavorable
movements in the United States Dollars to Brazilian Real exchange rates, a
loss of $4 million, after-tax was recorded related to this derivative upon
maturity of the contract. This amount was recorded in Other Income.
Through its 50% joint venture, Meiya Power Company, Global holds a 17.5%
ownership interest in a Taiwanese generation project under construction where
the construction contractor's fees, payable in installments through July 2003,
are payable in Euros. To manage the risk of foreign exchange rate fluctuations
associated with these payments, the project entered into a series of forward
exchange contracts to purchase Euros in exchange for Taiwanese dollars. As of
December 31, 2001, Global's share of the fair value and aggregate notional value
of these forward exchange contracts was approximately $1 million and $16
million, respectively. These forward exchange contracts were not designated as
hedges for accounting purposes, resulting in an after-tax gain of approximately
$0.5 million. In addition, after-tax gains of $1 million were recorded during
2001 on similar forward exchange contracts expiring during the year.
During 2001, Global purchased approximately 100% of a Chilean distribution
company. In order to hedge final Chilean peso denominated payments required to
be made on the acquisition, Global entered into a forward exchange contract to
purchase Chilean Pesos for United States Dollars. This transaction did not
qualify for hedge accounting, and, as such, upon settlement of the transaction,
Global recognized an after-tax loss of $0.5 million. Furthermore, as a
requirement to obtain certain debt financing necessary to fund the acquisition,
and in order to hedge against fluctuations in the United States Dollars to
Chilean Peso foreign exchange rates, Global entered into a forward contract with
a notional value of $150 million to exchange Chilean Pesos for United States
Dollars. This transaction expires in October 2002 and is considered a hedge for
accounting purposes. As of December 31, 2001, the derivative asset value of $4
million has been recorded to OCI, net of taxes ($1.4 million). In addition,
Global holds a 50% interest in another Chilean distribution company, which was
anticipating paying its U.S. investors a return of capital. In order to hedge
the risk of fluctuations in the Chilean peso to U.S. dollar exchange rate, the
distribution company entered into a forward exchange contract to purchase United
States Dollars for Chilean Pesos. Global's after-tax share of the loss on
settlement of this transaction (recorded by the distribution company) was $0.3
million.
In January 2002, RGE entered into a series of nine cross currency interest
rate swaps for the purpose of hedging its exposure to fluctuations in the
Brazilian Real to United States Dollars exchange rates with respect to its
United States Dollars denominated debt principal payments due in 2003 through
2006. The instruments convert the variable LIBOR based interest payments on
the loan balance to variable CDI based interest payments. CDI is the Brazilian
interbank interest rate. As a result, the distribution company has hedged its
foreign currency exposure but is still at risk for variability in the
Brazilian CDI interest rate during the terms of the instruments. Global's
share of the notional value of the instruments is approximately $15 million
for the instruments maturing in May, June and July of 2003 through 2005 and
approximately $19 million for the instruments maturing in May, June and July
2006. Also in January 2002, the distribution company entered into two similar
cross currency interest rate swaps to hedge the United States Dollar
denominated interest payments due on the debt in February 2002 and May 2002.
Global's share of the notional value of these two instruments is approximately
$3 million each.
21
Commodity Contracts
During 2001, Power entered into electric physical forward contracts and gas
futures and swaps with a maximum term of approximately one year, to hedge our
forecasted BGS requirements and gas purchases requirements for generation. These
transactions qualified for hedge accounting treatment under SFAS 133 and were
settled prior to the end of 2001. The majority of the marked-to-market
valuations were reclassified from OCI to earnings during the quarter ended
September 30, 2001. As of December 31, 2001, we did not have any outstanding
derivatives accounted for under this methodology. However, there was substantial
activity during the year ended December 31, 2001. In 2001, the values of these
forward contracts, gas futures and swaps as of June 30 and September 30 were
$(34.2) million and $(0.4) million.
Also as of December 31, 2001, PSE&G had entered into 330 MMBTU of gas
futures, options and swaps to hedge forecasted requirements. As of December 31,
2001, the fair value of those instruments was $(137) million with a maximum term
of approximately one year. PSE&G utilizes derivatives to hedge its gas
purchasing activities which, when realized, are recoverable through its
Levelized Gas Adjustment Clause (LGAC). Accordingly, these commodity contracts
are recognized at fair value as derivative assets or liabilities on the balance
sheet and the offset to the change in fair value of these derivatives is
recorded as a regulatory asset or liability.
The availability and price of energy commodities are subject to
fluctuations from factors such as weather, environmental policies, changes in
supply and demand, state and federal regulatory policies and other events. To
reduce price risk caused by market fluctuations, we enter into derivative
contracts, including forwards, futures, swaps and options with approved
counterparties, to hedge our anticipated demand. These contracts, in conjunction
with owned electric generation capacity, are designed to cover estimated
electric customer commitments.
We use a value-at-risk (VAR) model to assess the market risk of our
commodity business. This model includes fixed price sales commitments, owned
generation, native load requirements, physical contracts and financial
derivative instruments. VAR represents the potential gains or losses for
instruments or portfolios due to changes in market factors, for a specified time
period and confidence level. PSEG estimates VAR across its commodity business
using a model with historical volatilities and correlations.
The Risk Management Committee (RMC) established a VAR threshold of $25
million. If this threshold was reached, the RMC would be notified and the
portfolio would be closely monitored to reduce risk and potential adverse
movements. In anticipation of the completion of the current BGS contract with
PSE&G on July 31, 2002, and the BGS auction, the VAR threshold was increased
to $75 million.
The measured VAR using a variance/co-variance model with a 95% confidence
level and assuming a one-week time horizon as of December 31, 2001 was
approximately $18 million, compared to the December 31, 2000 level of $19
million. This estimate was driven by our assumption that Power would enter
into contracts for approximately 50% of its generating capacity during the BGS
auction. Since Power obtained contracts in excess of this amount, the VAR at
December 31, 2001 would have been even lower. This estimate, however, is not
necessarily indicative of actual results, which may differ due to the fact
that actual market rate fluctuations may differ from forecasted fluctuations
and due to the fact that the portfolio of hedging instruments may change over
the holding period and due to certain assumptions embedded in the calculation.
22
Interest Rates
PSEG, PSE&G, Power and Energy Holdings are subject to the risk of
fluctuating interest rates in the normal course of business. Their policy is to
manage interest rate risk through the use of fixed rate debt, floating rate
debt, interest rate swaps and interest rate lock agreements. As of December 31,
2001, a hypothetical 10% change in market interest rates would result in a $3
million, $4 million, and $2 million, change in annual interest costs related to
short-term and floating rate debt at PSEG, PSE&G, and Energy Holdings,
respectively. The following table shows details of the interest rate swaps at
PSEG, PSE&G, Power and Energy Holdings and their associated values that are
still open at December 31, 2001:
Total Fair Other
Project Notional Pay Receive Market Comprehensive
Underlying Securities Percent Amount Rate Rate Value Income
-------------------------------------------------------------------------------------------------------------------
(millions of dollars, where applicable)
PSEG:
Enterprise Capital Trust II 100% $150.0 5.975% 3-month LIBOR $(5.1) $(3.0)
Securities
PSE&G:
Transition Funding Bonds 100% $497.0 6.287% 3-month LIBOR $(18.5) $ -
Power:
Construction Loan - Waterford 100% $177.5 4.23% 3-month LIBOR $2.3 $1.3
Energy Holdings:
Construction Loan - Tunisia (US$) 60% $60.0 6.9% 3-month LIBOR $(4.4) $(1.7)
Construction Loan - Tunisia (EURO) 60% $67.2 5.2% 3-month EURIBOR* $(1.5) $(0.6)
Construction Loan - Poland (US$) 55% $85.0 8.4% 3-month LIBOR $(30.1) $(8.5)
Construction Loan - Poland (PLN) 55% $37.6 13.2% 3-month WIBOR** $(21.9) $(9.3)
Construction Loan - Oman 81% $18.2 6.3% 3-month LIBOR $(3.3) $(1.7)
Construction Loan - Kalaeloa 50% $57.3 6.6% 3-month LIBOR $(1.8) $(1.2)
Construction Loan - Guadalupe 50% $126.8 6.57% 3-month LIBOR $(4.1) $(2.7)
Construction Loan - Odessa 50% $138.3 7.39% 3-month LIBOR $(6.0) $(3.9)
----------- ---------- -------------- --------------------------
Total Energy Holdings $590.4 $(73.1) $(29.6)
----------- ---------- -------------- --------------------------
Total PSEG $1,414.9 $(94.4) $(31.3)
=========== ========== ============== ==========================
* EURIBOR - EURO Area Inter-Bank Offered Rate
** WIBOR - Warsaw Inter-Bank Offered Rate
We expect to reclass approximately $14.0 million of open interest rate
swaps from OCI to earnings during the next twelve months. As of December 31,
2001, there was a $31.3 million balance remaining in the Accumulated Other
Comprehensive Loss Account, as indicated in the table above.
We have also entered into several interest rate swaps that were closed out
during 2001 and are being amortized to earnings over the life of the underlying
debt. These items, along with their current and anticipated effect on earnings
discussed below.
23
In February 2001, we entered into various forward-interest rate swaps, with
an aggregate notional amount of $400 million, to hedge the interest rate risk
related to the anticipated issuance of debt. On April 11, 2001, Power issued
$1.8 billion in fixed-rate Senior Notes and closed out the forward starting
interest rate swaps. The aggregate loss, net of tax, of $3.2 million was
classified as Accumulated Other Comprehensive Loss and is being amortized and
charged to interest expense over the life of the debt. During the year ended
December 31, 2001, approximately $0.6 million was reclassified from OCI to
earnings. Management expects it will amortize approximately $0.8 million from
OCI to earnings during the next twelve months.
In March 2001, $160 million of non-recourse bank debt originally incurred
to fund a portion of the purchase price of Global's interest in Chilquinta
Energia, S.A. was refinanced. The private placement offering by Chilquinta
Energia Finance Co. LLC, a Global affiliate, of senior notes was structured in
two tranches: $60 million due 2008 at an interest rate of 6.47% and $100 million
due 2011 at an interest rate of 6.62%.
Equity Securities
Resources has investments in equity securities and limited partnerships.
Resources carries its investments in equity securities at their approximate fair
value as of the reporting date. Consequently, the carrying value of these
investments is affected by changes in the fair value of the underlying
securities. Fair value is determined by adjusting the market value of the
securities for liquidity and market volatility factors, where appropriate. The
aggregate fair values of such investments, which had quoted market prices at
December 31, 2001 and December 31, 2000 were $34 million and $115 million,
respectively. The potential change in fair value resulting from a hypothetical
10% change in quoted market prices of these investments amounted to $3 million
and $9 million at December 31, 2001 and December 31, 2000, respectively.
Credit Risk
Credit risk relates to the risk of loss that we would incur as a result of
non-performance by counterparties pursuant to the terms of their contractual
obligations. We have established credit policies that we believe significantly
minimize credit risk. These policies include an evaluation of potential
counterparties' financial condition (including credit rating), collateral
requirements under certain circumstances and the use of standardized agreements,
which may allow for the netting of positive and negative exposures associated
with a single counterparty.
As a result of the BGS auction, Power has contracted to provide generating
capacity to the direct suppliers of New Jersey electric utilities, including
PSE&G, commencing August 1, 2002. These bilateral contracts are subject to
credit risk. This credit risk relates to the ability of counterparties to meet
their payment obligations for the power delivered under each BGS contract. This
risk is substantially higher than the risk associated with potential nonpayment
by PSE&G under the BGS contract expiring July 31, 2002 since PSE&G is a
rate-regulated entity. Any failure to collect these payments under the new BGS
contracts could have a material impact on our results of operations, cash flows,
and financial position.
In December 2001, Enron Corp. (Enron) filed for reorganization under
Chapter 11 of the U.S. Bankruptcy Code. Power had entered into a variety of
energy trading contracts with Enron and its affiliates in the Pennsylvania-New
Jersey-Maryland Power Pool (PJM) area as part of its energy trading activities.
We took proper steps to mitigate our exposures to both Enron and other
counterparties who could have been affected by Enron. As of December 31, 2001,
we owed Enron approximately $23 million, net, and Enron held a letter of credit
from Power for approximately $40 million.
As a result of the California Energy Crisis, Pacific Gas & Electric Company
(PG&E) filed for protection under Chapter 11 of the US Bankruptcy Code on April
16, 2001. GWF, Hanford and Tracy had combined pre-petition receivables due from
PG&E, for all plants amounting to approximately $62 million. Of this amount,
approximately $25 million had been reserved as an allowance for doubtful
accounts resulting in a net receivable balance of approximately $37 million.
Global's pro-rata share of this gross receivable and net receivable was
approximately $30 million and $18 million, respectively.
In December 2001, GWF, Hanford and Tracy reached an agreement with PG&E
which stipulates that PG&E will make full payment of the $62 million in 12 equal
installments, including interest by the end of 2002. On
24
December 31, 2001, PG&E paid GWF $8 million, representing the initial
installment payment and all accrued interest due, pursuant to the agreement.
As of December 31, 2001, GWF, Hanford and Tracy still had combined
pre-petition receivables due from PG&E for all plants amounting to approximately
$57 million. Global's pro-rata share of this receivable was $27 million. As a
result of this agreement, GWF, Hanford and Tracy reversed the reserve of $25
million which increased operating income by $25 million (of which Global's share
was $11 million).
FOREIGN OPERATIONS
As of December 31, 2001, Global and Resources had approximately $3.4
billion and $1.3 billion, respectively, of international assets. As of December
31, 2001, foreign assets represented 19% of our consolidated assets and the
revenues related to those foreign assets contributed 5% to consolidated revenues
for the year ended December 31, 2001. For discussion of foreign currency risk
and potential asset impairments related to our investments in Argentina, see
Note 9. Financial Instruments, Energy Trading and Risk Management, Note 10.
Commitments and Contingent Liabilities and Note 19. Subsequent Events of
Notes. For a discussion of the foreign assets that have been reclassified
to discontinued operations, see Note 3. Discontinued Operations.
ACCOUNTING ISSUES
Critical Accounting Policies and Other Accounting Matters
Our most critical accounting policies include the application of SFAS 71
"Accounting for the Effects of Certain Types of Regulation" for PSE&G, our
regulated transmission and distribution business; Emerging Issues Task Force
(EITF) Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts
Held for Trading Purposes and Contracts Involved in Energy Trading and Risk
Management Activities" (EITF 02-3), for our energy trading contracts; and SFAS
No. 133, "Accounting for Derivative Instruments and Hedging Activities", as
amended (SFAS 133), to account for our various hedging transactions, and SFAS
52, "Foreign Currency Translation" and its impacts on Global's foreign
investments.
Accounting for the Effects of Regulation
PSE&G prepares its financial statements in accordance with the provisions
of SFAS No. 71, which differs in certain respects from the application of GAAP
by non-regulated businesses. In general, SFAS 71 recognizes that accounting for
rate-regulated enterprises should reflect the economic effects of regulation. As
a result, a regulated utility is required to defer the recognition of costs (a
regulatory asset) or the recognition of obligations (a regulatory liability) if
it is probable that, through the rate-making process, there will be a
corresponding increase or decrease in future rates. Accordingly, PSE&G has
deferred certain costs, which will be amortized over various future periods. To
the extent that collection of such costs or payment of liabilities is no longer
probable as a result of changes in regulation and/or PSE&G's competitive
position, the associated regulatory asset or liability is charged or credited to
income.
As a result of New Jersey deregulation legislation and regulatory orders
issued by the BPU, certain regulatory assets and liabilities were recorded. The
amortization of two of these regulatory liabilities will have a significant
effect on our annual earnings. They include the estimated amount of MTC revenues
to be collected in excess of the authorized amount of $540 million and the
amount of excess electric distribution depreciation reserves. The amount of
these regulatory liabilities will be amortized to earnings over the four-year
transition period from August 1, 1999 through July 31, 2003.
The MTC was authorized by the BPU as an opportunity to recover up to $540
million (net of tax) of our unsecuritized generation-related stranded costs on a
net present value basis. As a result of the appellate reviews of the Final
Order, PSE&G's securitization transaction was delayed until the first quarter of
2001, causing a delay in the implementation of the Securitization Transition
Charge (STC) which would have reduced the MTC. As a result, MTC was being
recovered at a faster rate than intended under the Final Order and a significant
overrecovery was probable. In order to properly recognize the recovery of the
allowed unsecuritized stranded costs over the transition
25
period, PSE&G recorded a regulatory liability and Power recorded a charge to net
income of $88 million, pre-tax, or $52 million, after tax, in the third quarter
of 2000 for the cumulative amount of estimated collections in excess of the
allowed unsecuritized stranded costs from August 1, 1999 through September 30,
2000. PSE&G then began deferring a portion of these revenues each month to
recognize the estimated collections in excess of the allowed unsecuritized
stranded costs. As of December 31, 2001, this deferred amount was $168 million
and is aggregated with the Societal Benefits Clause. After deferrals, pre-tax
MTC revenues recognized were $220 million in 1999, $239 million in 2000, and
$196 million in 2001. In 2002 and 2003, we expect to record approximately $90
million and $121 million, respectively.
The amortization of the Excess Depreciation Reserve is another significant
regulatory liability affecting our earnings. As required by the BPU, PSE&G
reduced its depreciation reserve for its electric distribution assets by $569
million and recorded such amount as a regulatory liability to be amortized over
the period from January 1, 2000 to July 31, 2003. In 2000 and 2001, $125 million
was amortized and recorded as a reduction of depreciation expense pursuant to
the Final Order. The remaining $319 million will be amortized through July 31,
2003.
See Note 5. Regulatory Assets and Liabilities of Notes for further
discussion of these and other regulatory issues.
Accounting, Valuation and Presentation of Our Energy Trading
Accounting - We account for our energy trading business in accordance with
the provisions of EITF Issue No. 98-10 which requires that energy trading
contracts be marked to market with gains and losses included in current
earnings.
Valuation - Since the vast majority of our energy trading contracts have
terms of less than one year, valuations for these contracts are readily
obtainable from the market exchanges, such as PJM, and over the counter
quotations. The valuations also include a credit reserve and a liquidity
reserve, which is determined using financial quotation systems, monthly bid-ask
prices and spread percentages. We have consistently applied this valuation
methodology for each reporting period presented. The fair values of these
contracts and a more detailed discussion of credit risk are reflected in Note 9.
Financial Instruments, Energy Trading and Risk Management.
Presentation - Pursuant to EITF 99-19, "Reporting Revenue Gross as a
Principal versus Net as an Agent" (EITF 99-19), prior to July 1, 2002, we
recorded our energy trading revenues and energy trading costs on a gross basis
for physical energy and capacity sales and purchases. In accordance with the
consensus reached in June 2002 relating to EITF Issue No. 02-3, "Issues Involved
in Accounting for Derivative Contracts Held for Trading Purposes and Contracts
Involved in Energy Trading and Risk Management Activities" (EITF 02-3),
beginning in the third quarter of 2002, we started reporting energy trading
revenues and energy trading costs on a net basis and have reclassified prior
periods to conform with this net presentation. As a result, both Operating
Revenues and Operating Costs were reduced by approximately $2.3 billion, $2.7
billion and $1.8 billion for the fiscal years ended December 31, 2001, 2000 and
1999, respectively. This change in presentation did not have an effect on
trading margins, net income or cash flows.
SFAS 133 - Accounting for Derivative Instruments and Hedging Activities
SFAS 133 established accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities. It requires an entity to recognize the
fair value of derivative instruments held as assets or liabilities on the
balance sheet. In accordance with SFAS 133, the effective portion of the change
in the fair value of a derivative instrument designated as a cash flow hedge is
reported in Other Comprehensive Income (OCI), net of tax, or as a Regulatory
Asset (Liability). Amounts in accumulated OCI are ultimately recognized in
earnings when the related hedged forecasted transaction occurs. The change in
the fair value of the ineffective portion of the derivative instrument
designated as a cash flow hedge is recorded in earnings. Derivative instruments
that have not been designated as hedges are adjusted to fair value through
earnings. We have entered into several derivative instruments, including hedges
of anticipated electric and gas purchases, interest rate swaps and foreign
currency hedges which have been designated as cash flow hedges.
The fair value of the derivative instruments is determined by reference to
quoted market prices, listed contracts, published quotations or quotations from
counterparties. In the absence thereof, we utilize mathematical models
26
based on current and historical data. The fair value of most of our derivatives
is determined based upon quoted market prices. Therefore, the effect on earnings
of valuations from our models is minimal.
For additional information regarding Derivative Financial Instruments, See
Note 9. Financial Instruments, Energy Trading and Risk Management - Derivative
Instruments and Hedging Activities of Notes.
SFAS 52 - Foreign Currency Translation
Our financial statements are prepared using the United States Dollar as the
reporting currency. In accordance with SFAS 52 "Foreign Currency Translation",
foreign operations whose functional currency is deemed to be the local (foreign)
currency, asset and liability accounts are translated into United States Dollars
at current exchange rates and revenues and expenses are translated at average
exchange rates prevailing during the period. Translation gains and losses (net
of applicable deferred taxes) are not included in determining net income but are
reported in other comprehensive income. Gains and losses on transactions
denominated in a currency other than the functional currency are included in the
results of operations as incurred.
The determination of an entity's functional currency requires management's
judgment. It is based on an assessment of the primary currency in which
transactions in the local environment are conducted, and whether the local
currency can be relied upon as a stable currency in which to conduct business.
As economic and business conditions change, we are required to reassess the
economic environment and determine the appropriate functional currency. The
impact of foreign currency accounting could have a material adverse impact on
our financial condition, results of operation and net cash flows.
Other Accounting Issues
For additional information on our accounting policies and the
implementation of recently issued accounting standards, see Note 1. Organization
and Summary of Significant Accounting Policies and Note 2. Accounting Matters.
FORWARD LOOKING STATEMENTS
Except for the historical information contained herein, certain of the
matters discussed in this report constitute "forward-looking statements" within
the meaning of the Private Securities Litigation Reform Act of 1995. Such
forward-looking statements are subject to risks and uncertainties which could
cause actual results to differ materially from those anticipated. Such
statements are based on management's beliefs as well as assumptions made by and
information currently available to management. When used herein, the words
"will", "anticipate", "intend", "estimate", "believe", "expect", "plan",
"hypothetical", "potential", variations of such words and similar expressions
are intended to identify forward-looking statements. We undertake no obligation
to publicly update or revise any forward-looking statements, whether as a result
of new information, future events or otherwise. The following review of factors
should not be construed as exhaustive or as any admission regarding the adequacy
of our disclosures prior to the effective date of the Private Securities
Litigation Reform Act of 1995.
In addition to any assumptions and other factors referred to specifically
in connection with such forward-looking statements, factors that could cause
actual results to differ materially from those contemplated in any
forward-looking statements include, among others, the following:
o because a portion of our business is conducted outside the United
States, adverse international developments could negatively impact our
business;
o credit, commodity, and financial market risks may have an adverse
impact;
o energy obligations, available supply and trading risks may have an
adverse impact;
o the electric industry is undergoing substantial change;
o generation operating performance may fall below projected levels;
o ability to obtain adequate and timely rate relief;
o we and our subsidiaries are subject to substantial competition from
well capitalized participants in the worldwide energy markets;
o our ability to service debt could be limited;
27
o if our operating performance or cash flow from minority interests
falls below projected levels, we may not be able to service our debt;
o power transmission facilities may impact our ability to deliver our
output to customers;
o government regulation affects many of our operations;
o environmental regulation significantly impacts our operations;
o we are subject to more stringent environmental regulation than many of
our competitors;
o insurance coverage may not be sufficient;
o acquisition, construction and development may not be successful; and
o recession, acts of war or terrorism could have an adverse impact.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
Information relating to quantitative and qualitative disclosures about
market risk is set forth under the caption "Qualitative and Quantitative
Disclosures About Market Risk" in Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operations. Such information is
incorporated herein by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
28
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars, except for Per Share Data)
For The Years Ended December 31,
-------------------------------------------------
2001 2000 1999
-------------- ------------- ------------
OPERATING REVENUES 7,055 6,521 6,339
OPERATING EXPENSES
Energy Costs 2,677 2,432 2,026
Operation and Maintenance 1,838 1,701 1,745
Depreciation and Amortization 511 355 532
Taxes Other Than Income Taxes 121 135 155
------- ------- -------
Total Operating Expenses 5,147 4,614 4,458
------- ------- -------
OPERATING INCOME 1,908 1,907 1,881
Other Income and Deductions 16 30 7
Interest Expense (695) (571) (489)
Preferred Securities Dividend Requirements
and Premium on Redemption (72) (94) (94)
------- ------- -------
INCOME BEFORE INCOME TAXES,
EXTRAORDINARY ITEM AND CUMULATIVE
EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE 1,157 1,272 1,305
Income Taxes (381) (496) (569)
------- ------- -------
INCOME BEFORE EXTRAORDINARY ITEM
AND CUMULATIVE EFFECT OF A CHANGE IN
ACCOUNTING PRINCIPLE 776 776 736
DISCOUNTED OPERATIONS
Loss from Discounted Operations, net of tax (15) (12) (13)
INCOME BEFORE CUMULATIVE PRINCIPLE 761 764 723
Extraordinary Item (net of tax of $345) - - (804)
Cumulative Effect of a Change in Accounting Principle
(net of tax) 9 - -
------- ------- -------
NET INCOME (LOSS) $ 770 $ 764 $ (81)
======= ======= =======
WEIGHTED AVERAGE COMMON SHARES
OUTSTANDING (000's) 208,226 215,121 219,814
======= ======= =======
EARNINGS PER SHARE (BASIC AND DILUTED):
INCOME BEFORE EXTRAORDINARY ITEM
DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF
A CHANGE IN ACCOUNTING PRINCIPLE $ 3.73 $ 3.61 $ 3.35
Loss from Discontinued Operations, net of tax (0.07) (0.06) (0.06)
Extraordinary Item (net of tax) - - (3.66)
Cumulative Effect of a Change in Accounting Principle
(net of tax) 0.04 - -
------- ------- -------
NET INCOME (LOSS) $ 3.70 $ 3.55 $ (0.37)
======= ======= =======
DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 2.16 $ 2.16 $ 2.16
======= ======= =======
See Notes to Consolidated Financial Statements.
29
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions of Dollars)
December 31,
-----------------------------------
2001 2000
--------------- -------------
CURRENT ASSETS
Cash and Cash Equivalents $ 167 $ 96
Accounts Receivable:
Customer Accounts Receivable 664 651
Other Accounts Receivable 340 408
Allowance for Doubtful Accounts (38) (39)
Unbilled Electric and Gas Revenues 291 357
Fuel 494 430
Materials and Supplies 186 155
Prepayments 74 28
Energy Trading Contracts 419 799
Restricted Cash 12 1
Assets held for Sale 422 48
Current Assets of Discontinued Operations 483 242
Other 25 50
--------------- -------------
Total Current Assets 3,539 3,226
--------------- -------------
PROPERTY, PLANT AND EQUIPMENT
Generation 4,690 2,860
Transmission and Distribution 9,500 8,479
Other 510 558
--------------- -------------
Total 14,700 11,897
Accumulated depreciation and amortization (4,789) (4,233)
--------------- -------------
Net Property, Plant and Equipment 9,911 7,664
--------------- -------------
NONCURRENT ASSETS
Regulatory Assets 5,247 4,995
Long-Term Investments, net of accumulated amortization
and net of valuation allowances - 2001, $30; 2000, $72 4,761 4,596
Nuclear Decommissioning Fund 817 716
Other Special Funds 222 122
Goodwill, net of accumulated amortization 569 22
Energy Trading Contracts 46 -
Other, net of accumulated amortization 318 185
--------------- -------------
Total Noncurrent Assets 11,980 10,636
--------------- -------------
TOTAL ASSETS $ 25,430 $ 21,526
=============== =============
See Notes to Consolidated Financial Statements.
30
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND CAPITALIZATION
(Millions of Dollars)
December 31,
------------------------------------
2001 2000
--------------- ---------------
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 1,185 $ 667
Commercial Paper and Loans 1,338 2,885
Accounts Payable 698 925
Energy Trading Contracts 554 730
Current Liabilities of Discontinued Operations 251 80
Other 778 429
--------------- ---------------
Total Current Liabilities 4,804 5,716
--------------- ---------------
NONCURRENT LIABILITIES
Deferred Income Taxes and ITC 3,205 3,107
Regulatory Liabilities 373 470
Nuclear Decommissioning 817 716
OPEB Costs 476 448
Cost of Removal 146 157
Energy Trading Contracts 54 -
Other 467 412
--------------- ---------------
Total Noncurrent Liabilities 5,538 5,310
--------------- ---------------
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 10)
CAPITALIZATION:
Long-Term Debt 6,437 5,040
Securitization Debt 2,351 -
Project Level, Non-Recourse Debt 1,403 256
--------------- ---------------
Total Long-Term Debt 10,191 5,296
--------------- ---------------
SUBSIDIARIES' PREFERRED SECURITIES:
Preferred Stock Without Mandatory Redemption 80 95
Preferred Stock With Mandatory Redemption - 75
Guaranteed Preferred Beneficial Interest in Subordinated Debentures 680 1,038
--------------- ---------------
Total Subsidiaries' Preferred Securities 760 1,208
--------------- ---------------
COMMON STOCKHOLDERS' EQUITY:
Common Stock, issued; 2001 and 2000, 231,957,608 shares 3,599 3,604
Treasury Stock, at cost; 2001 - 26,118,590 shares,
2000 - 23,986,290 shares (981) (895)
Retained Earnings 1,809 1,493
Accumulated Other Comprehensive Loss (290) (206)
--------------- ---------------
Total Common Stockholders' Equity 4,137 3,996
--------------- ---------------
Total Capitalization 15,088 10,500
--------------- ---------------
TOTAL LIABILITIES AND CAPITALIZATION $ 25,430 $ 21,526
=============== ==============
See Notes to Consolidated Financial Statements.
31
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
For the Years Ended December 31,
-------------------------------------------------
2001 2000 1999
------------ ------------- -------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 770 $ 764 $ (81)
Adjustments to reconcile net income (loss) to net cash flows from
operating activities:
Extraordinary Loss - net of tax - - 804
Depreciation and Amortization 522 362 536
Amortization of Nuclear Fuel 99 96 92
Recovery (Deferral) of Electric Energy and Gas Costs - net (86) 16 61
Excess Unsecuritized Stranded Costs 54 115 -
Provision for Deferred Income Taxes and ITC - net (179) (11) (215)
Investment Distributions 73 56 134
Equity Income from Partnerships (107) (28) (53)
Unrealized Gains on Investments (67) (39) (63)
Leasing Activities (7) 74 6
Proceeds from Sale of Capital Leases 104 89 125
Proceeds from Withdrawal/Sale of Partnerships 75 - 71
Net Changes in certain current assets and liabilities:
Inventory - Fuel and Materials and Supplies (84) (145) 9
Accounts Receivable and Unbilled Revenues 272 (299) (236)
Prepayments (40) 8 8
Accounts Payable (406) 260 57
Other Current Assets and Liabilities 515 (53) 59
Other (162) (42) 114
------------ ------------- -------------
Net Cash Provided By Operating Activities 1,346 1,223 1,428
------------ ------------- -------------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment, excluding IDC and AFDC (2,053) (959) (582)
Net Change in Long-Term Investments (709) (678) (1,127)
Acquisitions, Net of Cash Provided (756) (14) (49)
Other (260) (53) (70)
------------ ------------- -------------
Net Cash Used In Investing Activities (3,778) (1,704) (1,828)
------------ ------------- -------------
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt (1,512) 913 916
Issuance of Long-Term Debt 6,317 1,200 1,143
Redemption/Purchase of Long-Term Debt (1,292) (1,033) (676)
Redemption of Preferred Securities (448) - -
Purchase of Treasury Stock (91) (298) (400)
Cash Dividends Paid on Common Stock (449) (464) (474)
Other (22) - 11
------------ ------------- -------------
Net Cash Provided By (Used In) Financing Activities 2,503 318 520
------------ ------------- -------------
Net Change In Cash And Cash Equivalents 71 (163) 120
Cash And Cash Equivalents At Beginning Of Period 96 259 139
------------ ------------- -------------
Cash And Cash Equivalents At End Of Period $ 167 $ 96 $ 259
============ ============= =============
Income Taxes Paid $ 87 $ 485 $ 534
Interest Paid $ 700 $ 550 $ 494
See Notes to Consolidated Financial Statements.
32
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
(Millions)
Common Treasury
Stock Stock
------------------- ----------------------
Shs. Amount Shs. Amount
------- ---------- ------- -----------
BALANCE AS OF JANUARY 1, 1999 232 3,603 (5) (207)
Net Income (Loss) - - - -
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax of $(17) - - - -
Other Comprehensive Income (Loss) - - - -
Comprehensive Income (Loss) - - - -
Cash Dividends on Common Stock - - - -
Purchase of Treasury Stock - - (11) (400)
Other - 1 - 10
------------------- ----------------------
BALANCE AS OF DECEMBER 31, 1999 232 3,604 (16) (597)
------------------- ----------------------
Net Income (Loss) - - - -
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax of $(0) - - - -
Other Comprehensive Income (Loss) - - - -
Comprehensive Income (Loss) - - - -
Cash Dividends on Common Stock - - - -
Purchase of Treasury Stock - - (8) (298)
------------------- ----------------------
BALANCE AS OF DECEMBER 31, 2000 232 $ 3,604 (24) $ (895)
------------------- ----------------------
Net Income (Loss) - - - -
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax $(12) - - - -
Change in Fair Value of Derivative Instruments, net of tax $(31)
and minority interest $(6) - - - -
Cumulative Effect of Change in Accounting Principle net of tax $(14) - - - -
Reclassification Adjustments for Net Amounts included in Net Income,
net of tax of $19 and minority interest of $3 - - - -
Pension Adjustments, net of tax $(1) - - - -
Change in Fair Value of Equity Investments, net of tax $(1) - - - -
Other Comprehensive Income (Loss) - - - -
Comprehensive Income (Loss) - - - -
Cash Dividends on Common Stock - - - -
Purchase of Treasury Stock - - (2) (92)
Other - (5) - 6
=================== ======================
BALANCE AS OF DECEMBER 31, 2001 232 $ 3,599 (26) $ (981)
=================== ======================
Accumulated
Other
Retained Comprehensive
Earnings Income (Loss) Total
------------ ----------------- ------------
Balance as of January 1, 1999 1,748 (46) 5,098
Net Income (Loss) (81) - (81)
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax of $(17) - (158) (158)
------------
Other Comprehensive Income (Loss) - - (158)
------------
Comprehensive Income (Loss) - - (239)
Cash Dividends on Common Stock (474) - (474)
Purchase of Treasury Stock - - (400)
Other - - 11
------------ ----------------- ------------
Balance as of December 31, 1999 1,193 (204) 3,996
------------ ----------------- ------------
Net Income (Loss) 764 - 764
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax of $(0) - (2) (2)
------------
Other Comprehensive Income (Loss) - - (2)
------------
Comprehensive Income (Loss) - - 762
Cash Dividends on Common Stock (464) - (464)
Purchase of Treasury Stock - - (298)
------------ ----------------- ------------
Balance as of December 31, 2000 $1,493 $ (206) $3,996
------------ ----------------- ------------
Net Income (Loss) 770 - 770
Other Comprehensive Income (Loss), net of tax:
Currency Translation Adjustment, net of tax $(12) - (34) (34)
Change in Fair Value of Derivative Instruments, net of tax $(31)
and minority interesf $(6) - (57) (57)
Cumulative Effect of Change in Accounting Principle net of tax $(14) - (15) (15)
Reclassification Adjustments for Net Amounts included in Net Income,
net of tax of $19 and minority interest of $3 - 26 26
Pension Adjustments, net of tax $(1) - (2) (2)
Change in Fair Value of Equity Investments, net of tax $(1) - (2) (2)
------------
Other Comprehensive Income (Loss) - - (84)
------------
Comprehensive Income (Loss) - - 686
Cash Dividends on Common Stock (449) - (449)
Purchase of Treasury Stock - - (92)
Other (5) - (4)
------------ ----------------- ------------
Balance as of December 31, 2001 $1,809 $ (290) $4,137
============ ================= ============
See Notes to Consolidated Financial Statements.
33
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization and Summary of Significant Accounting Policies
Organization
We have four principal direct wholly-owned subsidiaries: Public Service
Electric and Gas Company (PSE&G), PSEG Power LLC (Power), PSEG Energy Holdings
Inc. (Energy Holdings) and PSEG Services Corporation (Services).
PSE&G is an operating public utility providing electric and gas service in
certain areas within the State of New Jersey. Following the transfer of its
generation-related assets to Power in August 2000, PSE&G continues to own and
operate its transmission and distribution business.
Power has three principal direct wholly-owned subsidiaries: PSEG Nuclear
LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC
(ER&T). Power and its subsidiaries were established to acquire, own and operate
the electric generation-related business of PSE&G pursuant to the Final Decision
and Order (Final Order) issued by the New Jersey Board of Public Utilities (BPU)
under the New Jersey Electric Discount and Energy Competition Act (Energy
Competition Act) discussed below. Power uses energy trading to optimize the
value of its portfolio of generating assets and its supply obligations. Power
also has a finance company subsidiary, PSEG Power Capital Investment Co. (Power
Capital), which provides certain financing for Power's subsidiaries.
Energy Holdings participates in three energy-related reportable segments
through its wholly-owned subsidiaries: PSEG Global Inc. (Global), PSEG Resources
Inc. (Resources) and PSEG Energy Technologies Inc. (Energy Technologies). Energy
Holdings also has a finance subsidiary, PSEG Capital Corporation (PSEG Capital)
and is also the parent of Enterprise Group Development Corporation (EGDC), a
commercial real estate property management business, and is conducting a
controlled exit from this business.
Services provides management and administrative services at cost to us and
our subsidiaries.
Summary of Significant Accounting Policies
Consolidation
Our consolidated financial statements include our accounts and those of our
subsidiaries. We and our subsidiaries consolidate those entities in which we
have a controlling interest. Those entities in which we and our subsidiaries do
not have a controlling interest are being accounted for under the equity method
of accounting. For investments in which significant influence does not exist,
the cost method of accounting is applied. All significant intercompany accounts
and transactions are eliminated in consolidation.
Regulation
PSE&G prepares its financial statements in accordance with the provisions
of Statement of Financial Accounting Standard (SFAS) No. 71, "Accounting for
Effects of Certain Types of Regulation" (SFAS 71). In general, SFAS 71
recognizes that accounting for rate-regulated enterprises should reflect the
economic effects of regulation. As a result, a regulated utility is required to
defer the recognition of costs (a regulatory asset) or the recognition of
obligations (a regulatory liability) if it is probable that, through the
rate-making process, there will be a corresponding increase or decrease in
future rates. Accordingly, PSE&G has deferred certain costs and recoveries,
which will be amortized over various future periods. To the extent that
collection of such costs or payment of liabilities is no longer probable as a
result of changes in regulation and/or PSE&G's competitive position, the
associated regulatory asset or liability is charged or credited to income.
PSE&G's transmission and distribution business continues to meet the
requirements for application of SFAS 71.
34
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Derivative Financial Instruments
We use derivative financial instruments to manage our risk from changes in
interest rates, commodity prices and foreign currency exchange rates, pursuant
to its business plans and prudent practices.
On January 1, 2001, we adopted SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities", as amended (SFAS 133). SFAS 133 established
accounting and reporting standards for derivative instruments, including certain
derivative instruments included in other contracts, and for hedging activities.
It requires an entity to recognize the fair value of derivative instruments held
as assets or liabilities on the balance sheet. For cash flow hedging purposes,
changes in the fair value of the effective portion of the gain or loss on the
derivative are reported in Other Comprehensive Income (OCI) or as a Regulatory
Asset (Liability), net of tax. Amounts in accumulated OCI are ultimately
recognized in earnings when the related hedged forecasted transaction occurs.
The change in the fair value of the ineffective portion of the gain or loss on a
derivative instrument designated as a cash flow hedge is recorded in earnings.
Derivative instruments that have not been designated as hedges are adjusted to
fair value through earnings. We recorded a cumulative effect in a change in
accounting principle of $9 million, net of tax and a decrease to OCI of ($15)
million, respectively, in connection with the adoption of SFAS 133.
The fair value of the derivative instruments is determined by reference to
quoted market prices, listed contracts, published quotations or quotations from
counterparties. In the absence thereof, we utilize mathematical models based on
current and historical data.
Prior to the adoption of SFAS 133, we accounted for the results of our
derivative activities for hedging purposes utilizing the settlement method. The
settlement method provided for recognizing gains or losses from derivatives when
the related physical transaction was completed. Derivatives that were not
entered into for hedging purposes were valued at fair value and changes in fair
value were recorded in earnings.
For additional information regarding Derivative Financial Instruments, See
Note 9. Financial Instruments, Energy Trading and Risk Management.
Commodity Contracts
PSE&G enters into natural gas commodity forwards, futures, swaps and
options with counterparties to reduce exposure to price fluctuations from
factors such as weather, changes in demand and changes in supply. These
instruments, in conjunction with physical gas supply contracts, are designed to
cover estimated gas customer commitments. In accordance with SFAS 133, such
energy contracts are recognized at fair value as derivative assets or
liabilities on the balance sheet. These derivatives, when realized, are
recoverable through the Levelized Gas Adjustment Clause (LGAC). Accordingly, the
offset to the change in fair value of these derivatives is specified as a
regulatory asset or liability.
Power enters into electricity forward purchases and natural gas commodity
futures and swaps with counterparties to manage exposure to electricity and
natural gas price risk. These contracts, in conjunction with owned electric
generating capacity, are designed to manage price risk exposure for electric
customer commitments. In accordance with SFAS 133, such energy contracts are
recognized at fair value as derivative assets or liabilities on the balance
sheet and the effective portion of the gain of loss on the contracts is reported
in OCI, net of tax. Amounts in accumulated OCI are ultimately recognized in
earnings when the related hedged forecasted transaction occurs.
Power also enters into forwards, futures, swaps and options as part of its
energy trading operations. Effective January 1, 1999, Power adopted Emerging
Issues Task Force (EITF) Issue 98-10, "Accounting for Contracts Involved in
Energy Trading and Risk Management Activities" (EITF 98-10). EITF 98-10 requires
that energy trading contracts be marked to market with gains and losses included
in current earnings.
35
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
The vast majority of these commodity-related contracts have terms of less
than one year. Valuations for these contracts are readily obtainable from the
market exchanges, such as PJM, and over the counter quotations. The fair value
of the financial instruments that are marked to market are based on management's
best estimates. The valuations also take into account a liquidity reserve, which
is determined by using financial quotation systems, monthly bid-ask prices and
spread percentages. The valuations also take into account credit reserves,
discussed in Note 9. Financial Instruments, Energy Trading and Risk Management -
Credit Risk. We have consistently applied this valuation methodology for each
reporting period presented.
Pursuant to EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal
versus Net as an Agent" (EITF 99-19), we previously recorded our trading
revenues and trading related costs on a gross basis for physical energy and
capacity sales and purchases. In accordance with Emerging Issues Task Force
(EITF) Issue No. 02-3, "Issues Involved in Accounting for Derivative Contracts
Held for Trading Purposes and Contracts Involved in Energy Trading and Risk
Management Activities" (EITF 02-3), beginning in the third quarter of 2002, we
started reporting energy trading revenues and energy trading costs on a net
basis and have reclassified prior periods to conform with this net presentation.
This change in presentation did not have an effect on trading margins, net
income or cash flows. We continue to report swaps, futures, option premiums,
firm transmission rights, transmission congestion credits, and purchases and
sales of emission allowances on a net basis.
For additional information regarding commodity-related contracts, see Note
9 - Financial Instruments, Energy Trading and Risk Management.
Revenues and Fuel Costs
Power's and PSE&G's Revenues are recorded based on services rendered to
customers during each accounting period. PSE&G records unbilled revenues for the
estimated amount customers will be billed for services rendered from the time
meters were last read to the end of the respective accounting period.
Prior to August 1, 1999, fuel revenue and expense flowed through the
Electric Levelized Energy Adjustment Clause (LEAC) mechanism. Variances in fuel
revenues and expenses were subject to deferral accounting and had no direct
effect on earnings. Under the LEAC and the Levelized Gas Adjustment Clause
(LGAC), any LEAC and LGAC underrecoveries or overrecoveries, together with
interest (in the case of net overrecoveries), are deferred and included in
operations in the period in which they are reflected in rates. Following the
transfer of generation-related assets and liabilities in August 2000, Power
bears the full risks and rewards of changes in nuclear and fossil generating
fuel costs and replacement power costs.
Cash and Cash Equivalents
Cash and cash equivalents consists primarily of working funds and highly
liquid marketable securities (commercial paper and money market funds) with an
original maturity of three months or less.
Restricted Cash
Transition Funding has deposited funds with a Trustee which are required to
be used for payment of principal, interest and other expenses related to its
transition bonds (see Note 4. Regulatory Issues and Accounting Impacts of
Deregulation). Accordingly, these funds are classified as "Restricted Cash" on
our Consolidated Balance Sheets
Materials and Supplies and Nuclear Fuel
PSE&G's materials and supplies are carried on the books at average cost in
accordance with rate based regulation. The carrying value of the materials and
supplies and nuclear fuel for our non-utility subsidiaries is valued at lower of
cost or market.
36
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Depreciation and Amortization
PSE&G calculates depreciation under the straight-line method based on
estimated average remaining lives of the several classes of depreciable
property. These estimates are reviewed on a periodic basis and necessary
adjustments are made as approved by the BPU. The depreciation rate stated as a
percentage of original cost of depreciable property was 3.32% for 2001 and 3.52%
for 2000 and 1999. PSE&G has certain regulatory assets and liabilities resulting
from the use of a level of depreciation expense in the ratemaking process that
differs from the amount that is recorded under generally accepted accounting
principles (GAAP) for non-regulated companies.
Power calculates depreciation on generation-related assets based on the
assets' estimated useful lives determined based on planned operations, rather
than using depreciation rates prescribed by the BPU in rate proceedings. The
estimated useful lives are from 3 years to 20 years for general plant. The
estimated useful lives for buildings and generating stations are as follows:
Class of Property Estimated Useful Life
----------------- ---------------------
Fossil Production 25-55 years
Nuclear Generation 30 years
Pumped Storage 45 years
Nuclear fuel burn-up costs are charged to fuel expense on a
units-of-production basis over the estimated life of the fuel. Rates for the
recovery of fuel used at all nuclear units include a provision of one mill per
kilowatt-hour (kWh) of nuclear generation for spent fuel disposal costs.
Energy Holdings calculates depreciation on property, plant and equipment
under the straight line method with estimated useful lives from 3 years to 40
years.
Unamortized Loss on Reacquired Debt and Debt Expense
Bond issuance costs and associated premiums and discounts are generally
amortized over the life of the debt issuance. In accordance with Federal Energy
Regulatory Commission (FERC) regulations, PSE&G's costs to reacquire debt are
deferred and amortized over the remaining original life of the retired debt.
When refinancing debt, the unamortized portion of the original debt issuance
costs of the debt being retired must be amortized over the life of the
replacement debt. Gains and losses on reacquired debt associated with PSE&G's
regulated operations will continue to be deferred and amortized to interest
expense over the period approved for ratemaking purposes.
Allowance for Funds Used During Construction (AFDC) and Interest
Capitalized During Construction (IDC)
AFDC represents the cost of debt and equity funds used to finance the
construction of new utility assets under the guidance of SFAS 71. The amount of
AFDC capitalized was reported in the Consolidated Statements of Income as a
reduction of interest charges. The rates used for calculating AFDC in 2001, 2000
and 1999 were 6.71%, 6.45% and 5.29%, respectively. Effective April 1, 1999,
AFDC was no longer used for any capital projects related to our generation
assets. Interest related to these capital projects is now capitalized in
accordance with SFAS No. 34, "Capitalization of Interest Cost." In 2001, 2000
and 1999, AFDC amounted to $2 million, $1 million and $3 million, respectively.
IDC represents the cost of debt used to finance the construction of
non-utility facilities. The amount of IDC capitalized is reported in the
Consolidated Statements of Income as a reduction of interest charges. The
weighted average rates used for calculating IDC in 2001 and 2000 were 7.98% and
9.98%, respectively. In 2001, 2000 and 1999, IDC amounted to $80 million, $35
million and $13 million, respectively.
37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Income Taxes
We and our subsidiaries file a consolidated Federal income tax return and
income taxes are allocated to our subsidiaries based on the taxable income or
loss of each subsidiary. Investment tax credits were deferred in prior years and
are being amortized over the useful lives of the related property.
Property, Plant and Equipment
PSE&G's additions to plant, property and equipment and replacements that
are either retirement units or property record units are capitalized at original
cost. The cost of maintenance, repair and replacement of minor items of property
is charged to appropriate expense accounts. At the time units of depreciable
property are retired or otherwise disposed, the original cost adjusted for net
salvage value is charged to accumulated depreciation.
Our non-regulated subsidiaries only capitalize costs which increase the
capacity or extend the life of an existing asset, represent a newly acquired or
constructed asset or represent the replacement of a retired asset. The cost of
maintenance, repair and replacement of minor items of property is charged to
appropriate expense accounts.
Environmental costs are capitalized if the costs mitigate or prevent future
environmental contamination or if the costs improve existing assets'
environmental safety or efficiency. All other environmental expenditures are
expensed.
Assets Held For Sale
For a discussion of the pending sale of certain investments in Argentina,
see Note 10. Commitments and Contingent Liabilities.
EGDC is conducting a controlled exit from the real estate business. In
1999, a pre-tax charge of $11 million was recorded for a property held for sale.
This amount is recorded in operations and maintenance expense. Since EGDC has
been conducting a controlled exit from the real estate business, gains and
losses from property sales are considered to be in the normal course of business
of EGDC. As of December 31, 2001 and December 31, 2000, EGDC has three
properties and four properties, respectively, reported as Assets Held for Sale
amounting to $23 and $13 million, respectively.
Foreign Currency Translation/Transactions
The assets and liabilities of foreign operations are translated into United
States dollars at current exchange rates and revenues and expenses are
translated at average exchange rates for the year. Resulting translation
adjustments are reflected as a separate component of stockholders' equity.
Transaction gains and losses that arise from exchange rate fluctuations on
normal operating transactions denominated in a currency other than the
functional currency are included in earnings as incurred.
Capital Leases as Lessee
The Consolidated Balance Sheets include assets and related obligations
applicable to capital leases under which the entity is a lessee. The total
amortization of the leased assets and interest on the lease obligations equals
the net minimum lease payments included in rent expense for capital leases.
Capital leases of PSE&G relate primarily to its corporate headquarters. See Note
10 - Commitments and Contingent Liabilities.
Impairment of Long-Lived Assets
We and our unregulated subsidiaries review long-lived assets for possible
impairment whenever events or changes in circumstances indicate that the
carrying amount of an asset may not be recoverable. In the event that facts and
circumstances indicate that the carrying amount of long-lived assets may be
impaired, an evaluation of recoverability would be performed. If an evaluation
is required, the estimated future undiscounted cash flows associated with the
asset would be compared to the asset's carrying amount to determine if a
write-down is required.
38
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
If this review indicates that the assets will not be recoverable, the carrying
value of our assets would be reduced to their estimated market value. Upon
deregulation, PSE&G evaluated the recoverability of its generation related
assets and recorded an extraordinary, non-cash charge to earnings. For the
impact of the application of SFAS 121, see Note 4. Regulatory Issues and
Accounting Impacts of Deregulation.
Goodwill
We classified the cost in excess of fair value of the net assets as
goodwill (including tax attributes) of companies acquired in purchase business
transactions.
Goodwill recorded in connection with acquisitions that occurred prior to
July 1, 2001 are amortized on a straight line basis over its estimated useful
life, principally over a forty year period, except for certain amounts with
lives determined to be shorter than forty years. For a discussion of recent
accounting standards with respect to recent business combinations and goodwill,
see Note 2. "Accounting Matters".
We evaluate the recoverability of goodwill by estimating the future
discounted cash flows of the businesses to which goodwill relates. The rate used
in determining discounted cash flows is a rate corresponding to our cost of
capital. Estimated cash flows are then determined by disaggregating our business
segments to an operational and organizational level for which meaningful
identifiable cash flows can be determined. When estimated future discounted cash
flows are less than the carrying value of the net assets (tangible or
identifiable intangibles) and related goodwill, impairment losses of goodwill
are charged to operations. Impairment losses, limited to the carrying value of
goodwill, represent the excess sum of the carrying value of the net assets
(tangible or identifiable intangibles) and goodwill over the discounted cash
flows of the business being evaluated. In determining the estimated future cash
flows, we consider current and projected future levels of income as well as
business trends, prospects and economic conditions.
For a discussion of recent accounting standards with respect to recent
business combinations and goodwill, see Note 2. Accounting Matters and Note 10.
Commitments and Contingent Liabilities.
Discontinued Operations
As disclosed in our Form 10-Q for the quarter ended September 30, 2002, we
intend to exit the heating, ventilating and air conditioning (HVAC) businesses
of PSEG Energy Technologies Inc. and PSEG Global Inc.'s interest in Tanir Bavi,
an electric generation facility in India. The results of these discontinued
operations, less applicable income taxes (benefit) are reported as a separate
component of income (loss) before extraordinary items and the cumulative effect
of a change in accounting principle. The assets and liabilities of these
entities are reflected separately in the Consolidated Balance Sheets as Current
Assets of Discontinued Operations and Current Liabilities of Discontinued
Operations. The Consolidated Statements of Cash Flows reflect the reduction in
Cash and Cash Equivalents related to the reclassification to Current Assets of
Discontinued Operations. These adjustments to the Statements of Cash Flows
related to the reduction in Cash and Cash Equivalents have been reflected within
Operating Activities. The consolidated statements for all periods have been
restated to present these businesses as discontinued operations. For additional
information, see Note 3. Discontinued Operations.
Use of Estimates
The process of preparing financial statements in conformity with GAAP
requires the use of estimates and assumptions regarding certain types of assets,
liabilities, revenues and expenses. Such estimates primarily relate to unsettled
transactions and events as of the date of the financial statements. Accordingly,
upon settlement, actual results may differ from estimated amounts.
Nuclear Decommissioning Trust Funds
Funds in our Nuclear Decommissioning Trust are stated at fair value.
Changes in the fair value of trust funds are also reflected in the accrued
liability for nuclear decommissioning.
39
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Reclassifications
Certain reclassifications of amounts reported in prior periods have been
made to conform with the current presentation.
Current Assets and Current Liabilities
The fair value of the current assets and liabilities approximate their
carrying amounts.
Note 2. Accounting Matters
In July 2001, the FASB issued SFAS No. 141, "Business Combinations" (SFAS
141). SFAS 141 was effective July 1, 2001 and requires that all business
combinations on or after that date be accounted for under the purchase method.
Upon implementation of this standard, there was no impact on our financial
position or results of operations and we do not believe it will have a
substantial effect on our strategy.
Also in July 2001, the FASB issued SFAS No. 142, "Goodwill and Other
Intangible Assets" (SFAS 142). Under SFAS 142, goodwill is considered a
nonamortizable asset and will be subject to an annual review for impairment and
an interim review when events or circumstances occur. SFAS 142 is effective for
all fiscal years beginning after December 15, 2001. The impact of adopting SFAS
142 is likely to be material to our financial position and results of
operations. For additional information relating to potential asset impairments,
see Note 10. Commitments and Contingent Liabilities.
Also in July 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS 143). Under SFAS 143, the fair value of a
liability for an asset retirement obligation should be recorded in the period in
which it is created with an offsetting amount to an asset. Upon settlement of
the liability, an entity either settles the obligation for its recorded amount
or incurs a gain or loss upon settlement. SFAS 143 is effective for fiscal years
beginning after June 15, 2002. We are currently evaluating this guidance and
cannot predict the impact on our financial position or results of operations;
however, such impact could be material.
In August 2001, FASB issued SFAS No. 144, "Accounting for Impairment or
Disposal of Long-Lived Assets" (SFAS 144). Under SFAS 144 long-lived assets to
be disposed of are measured at the lower of carrying amount or fair value less
cost to sell, whether reported in continued operations or in discontinued
operations. Discontinued operations are no longer 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. SFAS 144 is
effective for fiscal years beginning after December 15, 2001. In 2002, we
implemented a plan to exit the HVAC and mechanical operating business of Energy
Technologies and Global's interest in Tanir Bavi, an electric generation
facility in India. As a result, Global's interest in Tanir Bavi and Energy
Technologies' HVAC/mechanical operating business were reclassified to
discontinued operations and presented in accordance with SFAS No. 144,
"Accounting for Impairment or Disposal of Long-Lived Assets" (SFAS 144). Under
The consolidated statements for all periods presented have been restated to
reflect this reclassification. For additional information, see Note 3.
Discontinued Operations.
During the third quarter of 2002, we adopted SFAS 145. This Statement
rescinds SFAS No. 4, "Reporting Gains and Losses from Extinguishments of Debt,"
(SFAS 4) and an amendment of that Statement, SFAS No. 64, "Extinguishments of
Debt Made to Satisfy Sinking Fund Requirements" (SFAS 64). SFAS 4 required that
gains and losses from extinguishments of debt that were included in the
determination of net income be aggregated, and if material, classified as an
extraordinary item. Since the issuance of SFAS 4, the use of debt
extinguishments has become part of the risk management strategy of many
companies, representing a type of debt extinguishment that does not meet the
criteria for classification as an extraordinary item. Based on this trend, the
FASB issued this rescission of SFAS 4 and SFAS 64. Accordingly, under SFAS 145,
we now record these gains and losses in Other Income and Other Deductions,
respectively. We reclassified a pre-tax loss of $3 million ($2 million
after-tax) from the early retirement of debt to a component of Other Deductions
for 2001 in accordance with SFAS 145.
40
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
In accordance with Emerging Issues Task Force EITF 02-3, beginning in the
third quarter of 2002, we started reporting energy trading revenues and energy
trading costs on a net basis and have reclassified prior periods to conform with
this net presentation. As a result, both trading revenues and trading costs were
reduced by approximately $2.3 million, $2.7 million and $1.8 million for the
fiscal years ended December 31, 2001, 2000 and 1999, respectively. This change
in presentation did not have an effect on trading margins, net income or cash
flows.
NOTE 3. DISCONTINUED OPERATIONS
These financial statements include reclassifications to our Consolidated
Balance Sheets as of December 31, 2001 and 2000 and Consolidated Statements of
Income and Cash Flows for each of the three years in the period ended December
31, 2001 to reflect the effects of decisions made during the first nine months
in 2002, to discontinue operations of Energy Technologies' HVAC business and
Global's interest in Tanir Bavi, an electric generation facility in India.
Energy Technologies' Investments
Energy Technologies is comprised of 11 heating, ventilating and air
conditioning (HVAC) and mechanical operating companies and an asset management
group, which includes various Demand Side Management (DSM) investments. DSM
investments in long-term contracts represent expenditures made by Energy
Technologies to share DSM customers' costs associated with the installation of
energy efficient equipment. DSM revenues are earned principally from monthly
payments received from utilities, which represent shared electricity savings
from the installation of the energy efficient equipment.
In 2002, we adopted a plan to sell our interests in the HVAC/mechanical
operating companies. The sale of the HVAC/mechanical operating companies is
planned to be completed by June 30, 2003. We have retained the services of an
investment banking firm which is marketing the HVAC/mechanical operating
companies to interested parties. Operating results of the HVAC/mechanical
operating companies of Energy Technologies, less certain allocated costs from
Energy Holdings, have been reclassified as discontinued operations in our
Consolidated Statements of Income. For the years ended December 31, 2000 and
1999, the businesses of Energy Technologies included retail commodity sales of
electricity and natural gas, which do not qualify for accounting treatment as
discontinued operations. The HVAC/mechanical operating companies results of
operations of discontinued operations for the three years ended December 31,
2001, 2000 and 1999, respectively, are disclosed below:
Years Ended December 31,
--------------------------------------------
2001 2000 1999
--------------------------------------------
(Millions of Dollars)
Operating Revenues.............. $ 441 $ 316 $ 183
Pre-Tax Operating Loss............ (31) (20) (21)
Loss Before Income Taxes............ (34) (17) (19)
Net Loss............................ (22) (12) (13)
The carrying amounts of the assets and liabilities of Energy Technologies
investments in the discontinued HVAC/mechanical operating business, as of
December 31, 2001 and December 31, 2000, have been reclassified into Current
Assets of Discontinued Operations and Current Liabilities of Discontinued
Operations, respectively, on our Consolidated Balance Sheets.
41
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
The carrying amounts of the major classes of assets and liabilities of
Energy Technologies' investments in the discontinued HVAC/mechanical operating
business, as of December 31, 2001 and December 31, 2000, are summarized in the
following table:
----------------------- ------------------------
December 31, 2001 December 31, 2000
----------------------- ------------------------
(Millions of Dollars)
Current Assets...................... $152 $154
Net Property, Plant and Equipment... 8 18
Noncurrent Assets................... 66 70
-------------- ------------
Total Assets................... $226 $242
============== ============
Current Labilities.................. $ 76 $77
Noncurrent Liabilities.............. 2 2
Long-Term Debt...................... 1 1
-------------- ------------
Total Liabilities.............. $ 79 $80
============== ============
Tanir Bavi
As of September 30, 2002, Global owned a 74% interest in Tanir Bavi Power
Company Private Ltd. (Tanir Bavi), which owns and operates a 220 MW barge
mounted, combined-cycle generating facility in India. A plan to exit Tanir Bavi
was adopted in 2002. Global signed an agreement in August 2002 under which an
affiliate of its partner in this venture, GMR Vasavi Group, a local Indian
company, purchased Global's majority interest in Tanir Bavi. The sale was
completed in October 2002. In the second quarter of 2002, we reduced the
carrying value of Tanir Bavi to the contracted sales price of $45 million and
recorded a loss on disposal in the second quarter of 2002 of $14 million
(after-tax).
Tanir Bavi meets the criteria for classification as a component of
discontinued operations and all prior periods have been reclassified to conform
to this reclassification. Our share of operating results of this discontinued
operation are summarized in the following table:
Years Ended December 31,
---------------------------------------------
2001 2000 1999
------------ ----------- ------------
(Millions of dollars)
Operating Revenues................. $ 56 $ -- $ --
Operating Income .................. 16 -- --
Income Before Income Taxes......... 14 -- --
Net Income.......................... 7 -- --
The carrying amounts of the assets and liabilities of Tanir Bavi, as of
December 31, 2001, have been reclassified into Current Assets of Discontinued
Operations and Current Liabilities of Discontinued Operations, respectively, in
our Consolidated Balance Sheets. The carrying amounts of the major classes of
assets and liabilities of Tanir Bavi, as of December 31, 2001 are summarized in
the following tables:
December 31, 2001
-----------------------
(Millions of Dollars)
Current Assets...................... $ 37
Net Property, Plant and Equipment... 190
Noncurrent Assets................... 30
-----------------------
Total Assets.................... $ 257
=======================
Current Liabilities................. $ 45
Noncurrent Liabilities.............. 19
Long-Term Debt...................... 108
-----------------------
Total Liabilities.............. $ 172
=======================
42
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Note 4. Regulatory Issues and Accounting Impacts of Deregulation
New Jersey Energy Master Plan Proceedings and Related Orders
Following the enactment of the Energy Competition Act, the BPU rendered a
Final Order relating to PSE&G's rate unbundling, stranded costs and
restructuring proceedings (Final Order). PSE&G, pursuant to the Final Order,
transferred its electric generating facilities and wholesale power contracts to
Power and its subsidiaries on August 21, 2000 in exchange for a promissory note
in an amount equal to the purchase price.
The generating assets were transferred at the price specified in the BPU
order - $2.443 billion plus $343 million for other generation related assets and
liabilities. Because the transfer was between affiliates, PSE&G and Power
recorded the sale at the net book value of the assets and liabilities rather
than the transfer price. The difference between the total transfer price and the
net book value of the generation-related assets and liabilities was recorded as
an equity adjustment on PSE&G's and Power's Consolidated Balance Sheets. These
amounts are eliminated on our consolidated financial statements. Power paid the
promissory note on January 31, 2001, with funds provided from us via equity
contributions and loans.
Also in the Final Order, the BPU concluded that PSE&G should recover up to
$2.94 billion (net of tax) of its generation-related stranded costs through
securitization of $2.4 billion, plus an estimated $125 million of transaction
costs, and an opportunity to recover up to $540 million (net of tax) of its
unsecuritized generation-related stranded costs on a net present value basis.
The $540 million is subject to recovery through a market transition charge
(MTC). PSE&G remits the MTC revenues to Power as part of the BGS contract as
provided for by the Final Order.
In September 1999, the BPU issued its order approving PSE&G's petition
relating to the proposed securitization transaction (Finance Order) which
authorized, among other things, the imposition of a non-bypassable transition
bond charge (TBC) on PSE&G's customers; the sale of PSE&G's property right in
such charge to a bankruptcy-remote financing entity; the issuance and sale of
$2.525 billion of securitization bonds by such entity as consideration for such
property right, including an estimated $125 million of transaction costs; and
the application by PSE&G of the transition bond proceeds to retire outstanding
debt and/or equity. PSE&G Transition Funding LLC (Transition Funding) issued the
transition bonds on January 31, 2001; and the TBC and a 2% rate reduction became
effective on February 7, 2001 in accordance with the Final Order. An additional
2% rate reduction became effective on August 1, 2001 bringing the total rate
reduction to 9% since August 1, 1999. These rate reductions and the TBC were
funded through the MTC rate.
On January 31, 2001, $2.525 billion of securitization bonds (non-recourse
asset backed securities) were issued by Transition Funding, in eight classes
with maturities ranging from 1 year to 15 years. Also on January 31, 2001, PSE&G
received payment from Power on its $2.786 billion promissory note used to
finance the transfer of PSE&G's generation business. The proceeds from these
transactions were used to pay for certain debt issuance and related costs for
securitization, retire a portion of PSE&G's outstanding short-term debt, reduce
PSE&G common equity, loan funds to us and make various short-term investments.
In order to properly recognize the recovery of the allowed unsecuritized
stranded costs over the transition period, we recorded a charge to net income of
$88 million, pre-tax, or $52 million, after tax, in the third quarter of 2000
for the cumulative amount of estimated collections in excess of the allowed
unsecuritized stranded costs from August 1, 1999 through September 30, 2000. As
of December 31, 2001, the amount of estimated collections in excess of the
allowed unsecuritized stranded costs was $168 million.
Extraordinary Charge and Other Accounting Impacts of Deregulation
In April 1999, PSE&G determined that SFAS 71 was no longer applicable to
the electric generation portion of its business in accordance with the
requirements of Emerging Issues Task Force Issue 97-4, "Deregulation of the
Pricing of Electricity - Issues Related to the Application of FASB Statements
No. 71 and No. 101" (EITF 97-4). Accordingly, in 1999, we recorded an
extraordinary charge to earnings of $804 million (after tax), consisting
primarily of the write-down of PSE&G's nuclear and fossil generating stations in
accordance with SFAS 121. As a
43
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
result of this impairment analysis, the net book value of the generating
stations was reduced by approximately $5.0 billion (pre-tax) or $3.1 billion
(net of tax). This amount was offset by the creation of a $4.057 billion
(pre-tax), or $2.4 billion (net of tax) regulatory asset, as provided for in the
Final Order and Finance Order.
In addition to the impairment of PSE&G's electric generating stations, the
extraordinary charge consisted of various accounting adjustments to reflect the
absence of cost of service regulation in the electric generation portion of its
business. The adjustments primarily related to materials and supplies, general
plant items and liabilities for certain contractual and environmental
obligations.
In accordance with the Final Order, PSE&G also reclassified a $569 million
excess depreciation reserve related to PSE&G's electric distribution assets from
Accumulated Depreciation to a Regulatory Liability. Such amount is being
amortized in accordance with the terms of the Final Order over the period from
January 1, 2000 to July 31, 2003.
Note 5. Regulatory Assets and Liabilities
At December 31, 2001 and December 31, 2000, respectively, we had deferred
the following regulatory assets and liabilities on the Consolidated Balance
Sheets:
December
----------------------------
2001 2000
------------ -----------
(Millions of Dollars)
Regulatory Assets
-----------------
Stranded Costs to be Recovered................................ $4,105 $4,057
SFAS 109 Income Taxes......................................... 302 285
OPEB Costs.................................................... 212 232
Societal Benefits Charges (SBC)............................... 4 135
Environmental Costs........................................... 87 13
Unamortized Loss on Reacquired Debt and Debt Expense.......... 92 104
Underrecovered Gas Costs...................................... 120 --
Unrealized Losses on Gas Contracts............................ 137 --
Non-Utility Generation Transition Charge (NTC)................ -- 7
Other......................................................... 188 162
------------ -----------
Total Regulatory Assets................................. $5,247 $4,995
============ ===========
Regulatory Liabilities
----------------------
Excess Depreciation Reserve................................... $319 $444
Non-Utility Generation Transition Charge (NTC)................ 48 --
Overrecovered Gas Costs....................................... -- 26
Other......................................................... 6 --
------------ -----------
Total Regulatory Liabilities............................ $373 $470
============ ===========
Stranded Costs To Be Recovered: This reflects deferred costs to be
recovered through securitization transition charge which was authorized by the
Final Order and Finance Order.
SFAS 109 Income Taxes: This amount represents the portion of deferred
income taxes that will be recovered through future rates, based upon established
regulatory practices, which permit the recovery of current taxes.
OPEB Costs: Includes costs associated with the adoption of SFAS No. 106.
"Employers' Accounting for Benefits Other Than Pensions" which were deferred in
accordance with EITF Issue 92-12, "Accounting for OPEB Costs by Rate Regulated
Enterprises". Prior to the adoption of SFAS 106, post-retirement benefits costs
were recognized on a cash basis. SFAS 106 required that these costs be accrued
as the benefits were earned. Accordingly a liability and a regulatory asset were
recorded for the total benefits earned at the implementation date. Beginning
January 1, 1998, we commenced the amortization of this regulatory asset over 15
years. See Note 13. Pension, Other Postretirement Benefit and Savings Plans for
additional information.
44
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Societal Benefit Charges (SBC): The SBC includes costs related to PSE&G's
electric transmission and distribution business as follows: 1) social programs
which include the universal service fund; 2) nuclear plant decommissioning; 3)
demand side management (DSM) programs; 4) manufactured gas plant remediation; 5)
consumer education; 6) Under and overrecovered electric bad debt expenses; and
7) MTC overrecovery.
Environmental Costs: Represents environmental investigation and remediation
costs which are probable of recovery in future rates.
Unamortized Loss on Reacquired Debt and Debt Expense: Represents bond
issuance costs, premiums, discounts and losses on reacquired long-term debt.
Underrecovered/Overrecovered Gas Costs: Represents gas costs in excess of
or below the amount included in rates and probable of recovery in the future.
Unrealized Losses on Gas Contracts: This represents the recoverable portion
of unrealized losses associated with contracts used in the company's gas
distribution business
Non-utility Generation Transition Charge (NTC): This clause was established
to account for above market costs related to non-utility generation contracts.
The charge for the stranded NTC recovery was initially set at $183 million
annually. Any NUG contract costs and/or buyouts are charged to the NTC. Proceeds
from the sale of the energy and capacity purchased under these NUG contracts are
also credited to this account.
Other Regulatory Assets: Includes Decontamination and Decommissioning
Costs, Plant and Regulatory Study Costs, Repair Allowance Tax Deficiencies and
Interest, Property Abandonments and Oil and Gas Property Write-Down and recovery
of costs related to Transition Funding's interest rate swap.
Excess Depreciation Reserve: As required by the BPU, PSE&G reduced its
depreciation reserve for its electric distribution assets by $569 million and
recorded such amount as a regulatory liability to be amortized over the period
from January 1, 2000 to July 31, 2003. In 2000 and 2001, $125 million was
amortized. The remaining $319 million will be amortized through July 31, 2003.
Other Regulatory Liabilities: This includes the following: 1) Interest on
amounts collected from customers that are used to fund incentives for choosing a
third party gas supplier; 2) Interest on amounts collected early from customers
relating to the Transitional Energy Facility Assessment tax; and 3) Amounts
collected from customers in order for Transition Funding to obtain a AAA rating
on its transition bonds.
Note 6. Long-Term Investments
Long-Term Investments are primarily those of Energy Holdings' subsidiaries:
December 31,
---------------------------
2001 2000
----------- -----------
(Millions of Dollars)
Leveraged Leases................................................ $2,784 $2,253
Partnerships:
General Partnerships....................................... 44 47
Limited Partnerships....................................... 615 538
----------- -----------
Total Partnerships................................... 659 585
----------- -----------
Corporate Joint Ventures........................................ 1,115 1,584
Securities...................................................... 6 6
Other Investments............................................... 197 168
----------- -----------
Total Long-Term Investments.......................... $4,761 $4,596
=========== ===========
45
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Leveraged Leases
Resources' net investment in leveraged leases is comprised of the following
elements:
December 31,
--------------------------------
2001 2000
------------ ------------
(Millions of Dollars)
Lease rents receivable............................................ $3,644 $3,175
Estimated residual value of leased assets......................... 1,414 1,040
------------ ------------
5,058 4,215
Unearned and deferred income...................................... (2,274) (1,962)
------------ ------------
Total investments in leveraged leases........................ 2,784 2,253
Deferred taxes arising from leveraged leases...................... (1,175) (1,031)
------------ ------------
Net investment in leverage leases............................ $1,609 $1,222
============ ============
Resources' pre-tax income and income tax effects related to investments in
leveraged leases are as follows:
Years ended December 31,
-------------------------------------------------------------
2001 2000 1999
------------------ ------------------ -----------------
(Millions of Dollars)
Pre-tax income......................................... $ 206 $ 163 $ 112
================== ================== =================
Income tax effect on pre-tax income.................... $ 62 $ 58 $ 41
Amortization of investment tax credits................. $ (1) $ (1) $ (1)
Resources, as lessor, has certain ownership rights to the property through
leveraged leases, with terms ranging from 4 to 45 years. The lease investments
are recorded on a net basis by summing the lease rents receivable over the
lease term and adding the residual value, if any, less unearned income and
deferred taxes to be recognized over the lease term. Leveraged leases are
recorded net of non-recourse debt.
Income on leveraged leases is recognized by a method which produces a
constant rate of return on the outstanding net investment in the lease, net of
the related liability, in the years in which the net investment is positive.
Initial direct costs are deferred and amortized using the interest method over
the lease period.
Partnership Investments and Corporate Joint Ventures
Partnership investments of approximately $615 million and corporate joint
ventures of approximately $1.1 billion are those of Resources, Global and EGDC.
Energy Holdings accounts for such investments under the equity method of
accounting. As of December 31, 2001 Energy Holdings had approximately $1.5
billion of investments accounted for under the equity method of accounting.
46
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Summarized results of operations and financial position of all affiliates
in which Global uses the equity method of accounting are presented below:
Foreign Domestic Total
----------------- -------------- ----------------
(Millions of Dollars)
December 31, 2001
Condensed Income Statement Information
Revenue.................................................. $ 819 $ 473 $ 1,292
Gross Profit............................................. 317 165 482
Minority Interest........................................ (20) -- (20)
Net Income............................................... 141 91 232
Condensed Balance Sheet Information
Assets:
Current Assets.......................................... $ 341 $ 131 $ 472
Property, Plant & Equipment............................. 1,198 1,406 2,604
Goodwill................................................ 863 50 913
Other Non-current Assets............................... 616 23 639
----------------- -------------- ----------------
Total Assets............................................. $ 3,018 $ 1,610 $ 4,628
----------------- -------------- ----------------
----------------- -------------- ----------------
Liabilities:
Current Liabilities..................................... $ 415 $ 109 $ 524
Debt.................................................... 761 658 1,419
Other Non Current Liabilities........................... 132 212 344
Minority Interest....................................... 25 -- 25
----------------- -------------- ----------------
Total Liabilities........................................ 1,333 979 2,312
Equity................................................... 1,685 631 2,316
----------------- -------------- ----------------
Total Liabilities & Equity............................... $ 3,018 $ 1,610 $ 4,628
----------------- -------------- ----------------
Foreign Domestic Total
----------------- -------------- ----------------
(Millions of Dollars)
December 31, 2000
Condensed Income Statement Information
Revenue.................................................. $ 1,059 $ 452 $ 1,511
Gross Profit............................................. 434 256 690
Minority Interest........................................ (25) -- (25)
Net Income............................................... 156 162 318
Condensed Balance Sheet Information
Assets:
Current Assets.......................................... $ 504 $ 130 $ 634
Property, Plant & Equipment............................. 2,355 1,349 3,704
Goodwill................................................ 1,201 -- 1,201
Other Non-current Assets............................... 464 77 541
----------------- -------------- ----------------
Total Assets............................................. $ 4,524 $ 1,556 $ 6,080
----------------- -------------- ----------------
Liabilities:
Current Liabilities..................................... $ 818 $ 99 $ 917
Debt.................................................... 696 732 1,428
Other Non Current Liabilities........................... 174 90 264
Minority Interest....................................... 129 1 130
----------------- -------------- ----------------
Total Liabilities........................................ 1,817 922 2,739
Equity................................................... 2,707 634 3,341
----------------- -------------- ----------------
Total Liabilities & Equity............................... $ 4,524 $ 1,556 $ 6,080
----------------- -------------- ----------------
Foreign Domestic Total
----------------- -------------- ----------------
(Millions of Dollars)
December 31, 1999
Condensed Income Statement Information
Revenue.................................................. $ 1,184 $ 423 $ 1,607
Gross Profit............................................. 416 265 681
Minority Interest........................................ (23) -- (23)
Net Income............................................... 110 155 265
47
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Purchase Business Combinations/Asset Acquisitions
In December 2001, Global acquired Empresa de Electricidad de los Andes S.A.
(Electroandes) for $227 million, subject to certain purchase price adjustments
pending completion in April 2002. Electroandes is the sixth largest electric
generator in Peru with a 6% market share. Electroandes' main assets include four
hydroelectric facilities with a combined installed capacity of 183 MW and 460
miles of transmission lines located in the Central Andean region (northeast of
Lima). In addition, Electroandes has the exclusive rights to develop a 100 MW
expansion of an existing station and a 150 MW greenfield hydroelectric facility.
In 2000, Electroandes generated 1,150 GWH of electrical energy, of which 97% was
sold through power purchase agreements to mining companies in the region. We
have not finalized the allocation of the purchase price as of December 31, 2001.
An estimation of this allocation was prepared and included as part of our
consolidated financial statements. The purchase price was allocated $15 million
to Current Assets, $78 million to Property, Plant and Equipment, $164 million to
Goodwill, and $30 million to Current Liabilities.
In August 2001, Global purchased a 94% equity stake in SAESA and all of its
subsidiaries from Compania de Petroleos de Chile S.A. (COPEC). The SAESA group
of companies consists of four distribution companies and one transmission
company that provide electric service in the southern part of Chile.
Additionally, Global purchased from COPEC approximately 14% of Empresa Electrica
de la Frontera S.A. (Frontel) not owned by SAESA. SAESA also owns a 50% interest
in the Argentine distribution company Empresa Electrica del Rio Negro S.A. In
2001 Global spent $447 million (net of $16 million in cash acquired) to acquire
a 94% interest in SAESA and a 14% interest in Frontel. In October 2001, Global
completed a tender offer for an additional 6% of publicly trades SAESA shares,
for approximately $25 million. We have not finalized the allocation of the
purchase price as of December 31, 2001. An estimation of this allocation was
prepared and included as part of our consolidated financial statements. The
total purchase price of $488 million was allocated $55 million to Current
Assets, $210 million to Property, Plant and Equipment, $315 million to Goodwill,
$10 million to Other Non-Current Assets, $46 million to Current Liabilities, $39
million to Long-Term Debt, $17 million to Deferred Taxes and Other Non-Current
Liabilities.
In June 2001, Global exercised its option to acquire an additional 49% of
Empresa Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA), an electric
distribution company providing electric service to more than 230,000 customers
in the Province of Entre Rios, Argentina, bringing its total ownership of
EDEERSA to 90%. The additional ownership was purchased for $110 million. An
estimation of this allocation was prepared and included as part of our
consolidated financial statements. The purchase price was allocated
approximately $22 million to Current Assets, $114 million to Property, Plant and
Equipment, $30 million to Goodwill, $15 million to Current Liabilities, and $41
million to Long-Term Debt. We have not finalized the allocation of the purchase
price as of December 31, 2001.
In 2000, Global acquired a 49% interest in Tanir Bavi Power Company Private
Ltd., which was constructing a 220 MW barge mounted, combined-cycle generating
facility located near Mangalore in the state of Karnataka, India. In January
2001, Global acquired an additional 25% interest in the project bringing its
total ownership interest to 74%. In November 2001, the facility achieved full
commercial operation. A plan to exit Tanir Bavi was adopted in 2002. Global
signed an agreement in August 2002 under which an affiliate of its partner in
this venture, GMR Vasavi Group, a local Indian company, purchased Global's
majority interest in Tanir Bavi. The sale was completed in October 2002. Tanir
Bavi meets the criteria for classification as a component of discontinued
operations and all
48
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
prior periods have been reclassified to conform to the
current year's presentation. See Note 3. Discontinued Operations for further
discussion.
Other Investments
Other investments primarily include amounts related to Life Insurance and
Energy Technologies' investments in DSM projects. As of December 31, 2001,
amounts related to such items were $108 million and $45 million, respectively.
As of December 31, 2000, amounts related to such items were $89 million and $51
million, respectively.
Note 7. Schedule of Consolidated Capital Stock and Other Securities
Outstanding Current
Shares Redemption
At December 31, Price December 31, December 31,
2001 Per Share 2001 2000
---------------------------------- -------------- ----------------
(Millions of Dollars)
PSEG Common Stock (no par) (A)
Authorized 500,000,000 shares; issued and outstanding
at December 31, 2001, 205,839,018 shares and at
December 31, 2000, shares 207,971,318 $2,618 $2,709
PSEG Preferred Securities (B)
PSEG Quarterly Guaranteed Preferred Beneficial
Interest in
PSEG's Subordinated Debentures (D)(E)(G)
7.44%........................................... 9,000,000 -- $225 $225
Floating Rate................................... 150,000 -- 150 150
7.25%........................................... 6,000,000 -- 150 150
-------------- ----------------
Total Quarterly Guaranteed Preferred Beneficial
Interest in
PSEG's Subordinated Debentures.................. $525 $525
============== ================
PSE&G Preferred Securities
PSE&G Cumulative Preferred Stock (C) without Mandatory
Redemption (D)(E) $100 par value series
4.08%........................................... 146,221 103.00 $15 $15
4.18%........................................... 116,958 103.00 12 12
4.30%........................................... 149,478 102.75 15 15
5.05%........................................... 104,002 103.00 10 10
5.28%........................................... 117,864 103.00 12 12
6.92%........................................... 160,711 -- 16 16
$25 par value series
6.75%........................................... -- -- -- 15
-------------- ----------------
Total Preferred Stock without Mandatory Redemption $80 $95
============== ================
With Mandatory Redemption (D)(E) $100
par value series
5.97%........................................... -- -- $-- $75
-------------- ----------------
Total Preferred Stock with Mandatory Redemption... $-- $75
============== ================
PSE&G Monthly Guaranteed Preferred Beneficial
Interest in
PSE&G's Subordinated Debentures (D)(E)(F)
9.375%.......................................... -- -- $-- $150
8.00%........................................... 2,400,000 25.00 60 60
-------------- ----------------
Total Monthly Guaranteed Preferred Beneficial
Interest in
PSE&G's Subordinated Debentures................. $60 $210
============== ================
PSE&G Quarterly Guaranteed Preferred Beneficial
Interest in
PSE&G's Subordinated Debentures (D)(E)(F)
8.625%.......................................... -- -- $-- $208
8.125%.......................................... 3,800,000 -- 95 95
-------------- ----------------
Total Quarterly Guaranteed Preferred Beneficial
Interest in
PSE&G's Subordinated Debentures................. $95 $303
============== ================
(A) Our Board of Directors authorized the repurchase of up to 30 million
shares of its common stock in the open market. At December 31, 2001, we
had repurchased approximately 26.5 million shares of common stock at a
49
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
cost of approximately $997 million. The repurchased shares have been held
as treasury stock or used for other corporate purposes. Total authorized
and unissued shares include 7,302,488 shares of common stock available
for issuance through our Dividend Reinvestment and Stock Purchase Plan
and various employee benefit plans. In 2001 and 2000, no shares of common
stock were issued or sold through these plans.
(B) We have authorized a class of 50,000,000 shares of Preferred Stock
without par value, none of which is outstanding.
(C) At December 31, 2001, there were an aggregate of 6,704,766 aggregates of
shares of $100 par value and 10,000,000 shares of $25 par value
Cumulative Preferred Stock which were authorized and unissued and which,
upon issuance, may or may not provide for mandatory sinking fund
redemption. If dividends upon any shares of Preferred Stock are in
arrears in an amount equal to the annual dividend thereon, voting rights
for the election of a majority of PSE&G's Board of Directors become
operative and continue until all accumulated and unpaid dividends thereon
have been paid, whereupon all such voting rights cease, subject to being
revived from time to time.
(D) At December 31, 2001 and 2000, the annual dividend requirement of our
Trust Preferred Securities (Guaranteed Preferred Beneficial Interest in
our Subordinated Debentures) and their embedded costs were $38,433,000
and 4.91%, respectively.
At December 31, 2001 and 2000, the annual dividend requirement and
embedded dividend rate for PSE&G's Preferred Stock without mandatory
redemption was $10,127,383 and 5.03%, $10,886,758 and 5.18%,
respectively, and for our Preferred Stock with mandatory redemption was
$1,119,375 and 6.02%, $4,477,500 and 6.02%, respectively.
At December 31, 2001 and 2000, the annual dividend requirement and
embedded cost of the Monthly Income Preferred Securities (Guaranteed
Preferred Beneficial Interest in PSE&G's Subordinated Debentures) was
$7,768,750 and 4.90%, $18,862,500 and 5.50%, respectively.
At December 31, 2001 and 2000, the annual dividend requirement of the
Quarterly Income Preferred Securities (Guaranteed Preferred Beneficial
Interest in PSE&G's Subordinated Debentures) and their embedded costs
were $16,439,584 and 4.97%, $25,658,750 and 5.18%, respectively.
(E) For information concerning fair value of financial instruments, see Note
9. Financial Instruments, Energy Trading and Risk Management.
(F) PSE&G Capital L.P., PSE&G Capital Trust I and PSE&G Capital Trust II were
formed and are controlled by PSE&G for the purpose of issuing Monthly and
Quarterly Income Preferred Securities (Monthly and Quarterly Guaranteed
Preferred Beneficial Interest in PSE&G's Subordinated Debentures). The
proceeds were loaned to PSE&G and are evidenced by PSE&G's Deferrable
Interest Subordinated Debentures. If and for as long as payments on
PSE&G's Deferrable Interest Subordinated Debentures have been deferred,
or PSE&G has defaulted on the indentures related thereto or its
guarantees thereof, PSE&G may not pay any dividends on its common and
preferred stock. The Subordinated Debentures and the indentures
constitute a full and unconditional guarantee by PSE&G of the Preferred
Securities issued by the partnership and the trusts.
(G) Enterprise Capital Trust I, Enterprise Capital Trust II, Enterprise
Capital Trust III and Enterprise Capital Trust IV were formed and are
controlled by us for the purpose of issuing Quarterly Trust Preferred
Securities (Quarterly Guaranteed Preferred Beneficial Interest in PSEG's
Subordinated Debentures). The proceeds were loaned to us and are
evidenced by our Deferrable Interest Subordinated Debentures. If and for
as long as payments on our Deferrable Interest Subordinated Debentures
have been deferred, or we have defaulted on the indentures related
thereto or its guarantees thereof, PSEG may not pay any dividends on its
common and preferred stock. The Subordinated Debentures constitute our
full and unconditional guarantee of the Preferred Securities issued by
the trusts.
50
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Note 8. Schedule of Consolidated Debt
Interest Rates Maturity 2001 2000
------------------------------------------------------ --------------------- -------------- ---------------
PSEG (Millions of Dollars)
----
Extendible Notes LIBOR plus 0.40% (A) 2001................ $ -- $300
Floating Rate Notes-LIBOR plus 0.875% 2002................ 275 275
-------------- ---------------
Principal Amount Outstanding (C)............................................. 275 575
Amounts Due Within One Year (D).............................................. (275) (300)
-------------- ---------------
Total Long-Term Debt of PSEG ......................................... $ -- $275
============== ===============
PSE&G
-----
First and Refunding Mortgage Bonds (B):
7.875% 2001................ $ -- $100
6.125% 2002................ 258 258
6.875%-8.875% 2003................ 300 300
6.50% 2004................ 286 286
9.125% 2005................ 125 125
6.75% 2006................ 147 147
6.25% 2007................ 113 113
Variable 2008-2012........... -- 66
6.75%-7.375% 2013-2017........... 330 330
6.45%-9.25% 2018-2022........... 139 139
Variable 2018-2022........... -- 14
5.20%-7.50% 2023-2027........... 434 434
5.45%-6.55% 2028-2032........... 499 499
Variable 2028-2032........... -- 25
5.00%-8.00% 2033-2037........... 160 160
Medium-Term Notes:
7.19% 2002................ 290 290
8.10%-8.16% 2008-2012........... 60 60
7.04% 2018-2022........... 9 9
7.15%-7.18% 2023-2027........... 39 39
-------------- ---------------
Total First and Refunding Mortgage Bonds............................ 3,189 3,394
-------------- ---------------
Unsecured Bonds-7.43% (L) 2002............... -- 300
Unsecured Bonds-Variable 2027............... -- 19
-------------- ---------------
Total Unsecured Bonds............................................... -- 319
-------------- ---------------
Principal Amount Outstanding (C)............................................. 3,189 3,713
Amounts Due Within One Year (D).............................................. (547) (100)
Net Unamortized Discount..................................................... (16) (23)
-------------- ---------------
Total Long-Term Debt of PSE&G (E)................................... $2,626 $3,590
============== ===============
51
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
December 31,
---------------------------------
Interest Rates Maturity 2001 2000
------------------------------------------------------ --------------------- -------------- ---------------
Transition Funding (Millions of Dollars)
------------------
Securitization Bonds (I):
5.46%................................................. 2004................ $52 --
5.74%................................................. 2007................ 369 --
5.98%................................................. 2008................ 183 --
LIBOR plus 0.30%...................................... 2011................ 496 --
6.45%................................................. 2013................ 328 --
6.61%................................................. 2015................ 454 --
6.75%................................................. 2016................ 220 --
6.89%................................................. 2017................ 370 --
-------------- ---------------
Principal Amount Outstanding (C)............................................. 2,472 --
Amounts Due Within One Year (I).............................................. (121) --
-------------- ---------------
Total Long-Term Debt of Transition Funding, LLC ...................... $2,351 --
============== ===============
Power
-----
Senior Notes:
6.88%............................................... 2006................. $500 --
7.75%............................................... 2011................. 800 --
8.63%............................................... 2031................. 500 --
Pollution Control Bonds (J)............................
5.00%............................................... 2012................. 66 --
5.50%............................................... 2020................. 14 --
5.85%............................................... 2027................. 19 --
5.75%............................................... 2031................. 25 --
Non-recourse debt (K):
Variable............................................ 2005................. 770 --
------------ ------------
Principal Amount Outstanding (C).............................................. 2,694 --
Amounts Due Within One Year (D)............................................... -- --
Net Unamortized Discount...................................................... (9) --
-------------- ---------------
Total Long-Term Debt of Power ....................................... $2,685 --
============== ===============
52
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
December 31,
---------------------------------
Interest Rates Maturity 2001 2000
------------------------------------------------------ --------------------- -------------- ---------------
Energy Holdings (Millions of Dollars)
---------------
Senior Notes:
9.125% 2004................. $300 $ 300
8.625% 2008................. 400 --
10.00% 2009................. 400 400
8.50% 2011................. 550 --
-------------- ------------
Principal Amount Outstanding (C)............................................. 1,650 700
Net Unamortized Discount..................................................... (6) (5)
-------------- ------------
$1,644 $695
-------------- ------------
PSEG Capital
------------
Medium-Term Notes (F):
6.73% - 6.74% 2001................ -- 170
3.12% - 7.72% 2002................ 228 228
6.25% 2003................ 252 252
-------------- ------------
Principal Amount Outstanding (C)............................................. 480 650
-------------- -------------
Amounts Due Within One Year (D).............................................. (228) (170)
Net Unamortized Discount..................................................... -- (1)
-------------- -------------
Total Long-Term Debt of PSEG Capital................................ 252 479
-------------- -------------
Global
------
Non-recourse Debt (G):
10.01% -10.385% - Bank Loan 2001................ -- 96
5.47% - 10.385 - Bank Loan 2002................ 14 64
6.64% - 9.46 - Bank Loan 2003-2019........... 602 160
14.00% - Minority Shareholder Loan 2027................ 10 10
-------------- ------------
Principal Amount Outstanding (C)............................................. 626 330
Amounts Due Within One Year (D).............................................. (14) (96)
-------------- -------------
Total Long-Term Debt of Global...................................... 612 234
-------------- -------------
Resources
---------
8.60% - Bank Loan 2001-2020........... 22 24
-------------- -------------
Principal Amount Outstanding (C)............................................. 22 24
Amounts Due Within One Year (D)..............................................
(1) (1)
-------------- -------------
Total Long-Term Debt of Resources................................... 21 23
-------------- -------------
Total Long-Term Debt of Energy Holdings (M) ................... 2,529 1,431
============== =============
Consolidated Long-Term Debt (H)(M)......................... $10,191 $5,296
============== =============
(A) In June 1999, we issued $300 million of Extendible Notes, Series C, due
June 15, 2001. At December 31, 2000, the interest rate on Series C was
6.955%. These Extendible Notes were repurchased in 2001 and are no longer
outstanding. In November 2000, we issued $275 million of Floating Rate
Notes due May 21, 2002 with an interest rate is at three-month LIBOR,
plus 0.875%.
(B) PSE&G's First and Refunding Mortgage (Mortgage), securing the Bonds,
constitutes a direct first mortgage lien on substantially all of PSE&G's
property and franchises.
(C) For information concerning fair value of financial instruments, see Note
9. Financial Instruments Energy Trading and Risk Management.
53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
(D) The aggregate principal amounts of mandatory requirements for sinking
funds and maturities for each of the five years following December 31,
2001 are as follows:
Transition PSEG Energy PSEG
Year PSEG PSE&G Funding Power Holdings Capital Global Resources Total
------ -------- -------- ----------- ------- ---------- -------- ------- -------- --------
2002 275 547 -- -- -- 228 14 1 1,066
2003 -- 300 -- -- -- 252 37 1 590
2004 -- 286 52 -- 300 -- 98 1 737
2005 -- 125 -- 770 -- -- 21 1 917
2006 147 -- 500 -- -- 21 1 669
-------- -------- ----------- ------- ---------- -------- ------- -------- --------
275 1,405 52 1,270 300 480 191 5 3,979
======== ======== =========== ======= ========== ======== ======= ======== ========
(E) At December 31, 2001 and 2000, PSE&G's annual interest requirement on
long-term debt was $220 million and $256 million, of which $220 million
and $233 million, respectively, was the requirement for Mortgage Bonds.
The embedded interest cost on long-term debt on such dates was 7.46% and
7.30%, respectively. The embedded interest cost on long-term debt due
within one year at December 31, 2001 was 6.76%.
(F) PSEG Capital has provided up to $750 million debt financing for Energy
Holdings' businesses, except Energy Technologies, on the basis of a net
worth maintenance agreement with PSEG. Since 1995, PSEG Capital has
limited its borrowings to no more than $650 million.
(G) Global's projects are generally financed with non-recourse debt at the
project level, with the balance in the form of equity investments by the
sponsors in the project. The non-recourse debt shown in the above table
is that of consolidated subsidiaries which have equity investments in
distribution facilities in Argentina, Chile and Peru and generation
facilities under construction in Poland and Tunisia. Global's capital at
risk on the projects is limited to its original investment.
(H) At December 31, 2001 and 2000, our annual interest requirement on
long-term debt was $645 million and $440 million. The embedded interest
cost on long-term debt on such dates was 7.83% and 7.66%, respectively.
(I) At January 31, 2001, Transition Funding issued $2.525 billion of Bonds in
eight classes with estimated final payment dates from one year to fifteen
years. The net proceeds were remitted to PSE&G as consideration for the
property right in the TBC. At December 31, 2001, Transition Funding
annual interest requirement on securitization bonds was $148 million. The
current portion of Transition Funding's debt is based on estimated
payment dates, with final estimated payment dates at two years earlier
than the final maturity dates for each respective class of Bonds. At
December 31, 2001, Transition Funding's annual interest requirement on
its Bonds was $137 million.
(J) At November 20, 2001 & December 5, 2001, Power issued $124 million of
Pollution Control Notes in four classes with maturities ranging from 11
years to 30 years.
(K) In August 2001, subsidiaries of Power closed with a group of banks on
$800 million of non-recourse project financing for projects in Waterford,
Ohio and Lawrenceburg, Indiana. The Waterford project will be completed
in two phases and will increase Power's capacity by 850 MW. The first
phase and second phase of the project are expected to achieve commercial
operation in June 2002 and May 2003, respectively. The Lawrenceburg
project will increase Power's capacity by 1,150 MW and is expected to
achieve commercial operation by May 2003. The total combined project cost
for Waterford and Lawrenceburg is estimated at $1.2 billion. Power's
required estimated equity investment in these projects is approximately
$400 million. In connection with these projects, ER&T has entered into a
tolling agreement pursuant to which it is obligated to purchase the
output of these facilities at stated prices. As a result, ER&T bears the
price risk related to the output of these generation facilities.
(L) On December 7, 2000, PSE&G issued $300 million of Floating Rate Notes at
7.4275%, due December 7, 2002. The proceeds were used for general
corporate purposes including the repayment of short-term debt. These
notes were repurchased during 2001.
(M) Excludes Long-Term Debt of $109 million for Global and $1 million for
Energy Technologies related to discontinued operations. See Note 3.
Discontinued Operations.
54
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
SHORT-TERM DEBT
At December 31, 2001, we and Energy Holdings had a $753 million and $585
million of short-term debt as detailed below. As of December 31, 2001 the
weighted-average short-term debt rates for us and Energy Holdings were 2.8% and
3.3%, respectively.
Commercial
Maturity Total Primary Amount Paper (Cp)
Company Date Facility Purpose Outstanding Outstanding
------------------------------------------- -------- -------- ------- ----------- -----------
(MILLIONS OF DOLLARS)
PSEG
-------------------------------------------
364-day Credit Facility March 2002 $570 CP Support $ -- $475
5-year Credit Facility March 2002 280 CP Support -- N/A
5-year Credit Facility December 2002 150 Funding 125 N/A
Bilateral Credit Agreement N/A No Limit Funding 153 N/A
PSE&G
-------------------------------------------
364-day Credit Facility June 2002 390 CP Support -- --
5-year Credit Facility June 2002 450 CP Support -- --
Bilateral Credit Agreement June 2002 60 CP Support -- --
Bilateral Credit Agreement N/A No Limit Funding -- N/A
Energy Holdings
-------------------------------------------
364-day Credit Facility May 2002 200 Funding -- N/A
5-year Credit Facility May 2004 495 Funding 250 N/A
Bilateral Credit Agreement N/A 100 Funding 50 N/A
---- ----
Total N/A $578 $475
==== ====
Energy Holdings' five-year facility also permits up to $250 million of
letters of credit to be issued of which $57 million are outstanding as of
December 31, 2001. In addition, Global had $285 million of non-recourse
short-term debt outstanding as of December 31, 2001.
As of December 31, 2001, Power had issued letters of credit in the amount
of approximately $100 million.
Note 9. Financial Instruments, Energy Trading and Risk Management
Our operations are exposed to market risks from changes in commodity
prices, foreign currency exchange rates, interest rates and equity prices that
could affect results of operations and financial conditions. We manage our
exposure to these market risks through our regular operating and financing
activities and, when deemed appropriate, hedge these risks through the use of
derivative financial instruments. We use the term hedge to mean a strategy
designed to manage risks of volatility in prices or rate movements on certain
assets, liabilities or anticipated transactions and by creating a relationship
in which gains or losses on derivative instruments are expected to
counterbalance the losses or gains on the assets, liabilities or anticipated
transactions exposed to such market risks. We use derivative instruments as risk
management tools consistent with our business plans and prudent business
practices and for energy trading purposes.
55
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Fair Value of Financial Instruments
The estimated fair values were determined using the market quotations or
values of instruments with similar terms, credit ratings, remaining maturities
and redemptions at December 31, 2001 and December 31, 2000, respectively.
December 31, 2001 December 31, 2000
------------------------- ---------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
------------ ----------- ------------ -----------
(Millions of Dollars)
Long-Term Debt (A):
PSEG.................................................. $275 $275 $575 $575
Energy Holdings (B)................................... 2,774 2,834 1,698 1,724
PSE&G................................................. 3,173 3,290 3,690 3,453
Transition Funding.................................... 2,472 2,575 -- --
Power................................................. 2,685 2,835 -- --
Preferred Securities Subject to Mandatory Redemption:
PSE&G Cumulative Preferred Securities................. -- -- 75 60
Monthly Guaranteed Preferred Beneficial Interest in
PSE&G's Subordinated Debentures.................... 60 60 210 212
Quarterly Guaranteed Preferred Beneficial Interest in
PSE&G's Subordinated Debentures.................... 95 96 303 304
Quarterly Guaranteed Preferred Beneficial Interest in
PSEG's Subordinated Debentures..................... 525 520 525 474
(A) Includes current maturities. At December 31, 2001 we, Energy Holdings,
Power and Transition Funding had interest rate swap agreements
outstanding with notional amounts up to $150 million, $599 million, $178
million and $497 million, respectively. For additional information
concerning consolidated debt, see Note 8. Schedule of Consolidated Debt.
For additional information concerning preferred securities, see Note 7.
Schedule of Consolidated Capital Stock and Other Securities.
(B) Excludes Long-Term Debt of $109 million for Global and $1 million for
Energy Technologies related to discontinued operations. See Note 3.
Discontinued Operations.
Global had $912 million of project debt that is non-recourse to PSEG,
Energy Holdings and Global associated with investments in Argentina, India,
Chile, Peru Oman, Poland and Tunisia.
Energy Trading
Effective January 1, 1999, we adopted EITF 98-10, which requires that
energy trading contracts be recognized on the balance sheet at fair value with
resulting realized and unrealized gains and losses included in current earnings.
In 2001 we recorded $147 million of gains from energy trading, including
realized gains of $169 million and unrealized losses of $22 million. In 2000 we
recorded gains of $77 million, including $22 million of realized gains and $55
million of unrealized gains and in 1999 recorded gains of $42 million, including
$37 million of realized gains and $5 million of unrealized gains. Net of broker
fees and other trading related expenses, our energy trading business earned
margins of $140 million, $72 million and $39 million for the years ended
December 31, 2001, 2000 and 1999, respectively. As of December 31, 2001, we had
a total of $9 million of unrealized gains on our balance sheet, over 90% of
which related to contracts with terms of less than two years.
We engage in physical and financial transactions in the electricity
wholesale markets and execute an overall risk management strategy to mitigate
the effects of adverse movements in the fuel and electricity markets. We
actively trade energy, capacity, fixed transmission rights and emissions
allowances in the spot, forward and futures markets primarily in PJM, but also
throughout the Super Region. We are also involved in the financial transactions
that include swaps, options and futures in the electricity markets.
The fair values as of December 31, 2001 and December 31, 2000 and the
average fair values for the periods then ended of our financial instruments
related to the energy commodities are summarized in the following table:
56
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
December 31, 2001 December 31, 2000
----------------------------------------- ---------------------------------------------
Notional Notional Fair Average Notional Notional Fair Average
(mWh) (MMBTU) Value Fair Value (mWh) (MMBTU) Value Fair Value
------------------------------ ---------- ----------------------- ---------------------
(Millions) (Millions)
Futures and Options NYMEX .. -- 16.0 $(1.2) $(2.0) 17.0 167.0 $5.7 $(1.4)
Physical forwards........... 41.0 9.0 $(2.6) $12.1 50.0 10.0 $13.5 $13.6
Options-- OTC............... 8.0 803.0 $(19.4) $18.5 12.0 437.0 $184.2 $68.0
Swaps....................... -- 1,131.0 $23.9 $2.3 -- 218.0 $(137.8) $(42.5)
Emission Allowances......... -- -- $8.3 $23.8 -- -- $6.0 $9.5
We routinely enter into exchange traded futures and options transactions
for electricity and natural gas as part of our energy trading operations.
Generally, exchange-traded futures contracts require deposit of margin cash, the
amount of which is subject to change based on market movement in exchange rules.
The amount of the margin deposits as of December 31, 2001 and 2000 were
approximately $2.6 million and $1 million, respectively.
Derivative Instruments and Hedging Activities
Commodity Contracts
The availability and price of energy commodities are subject to
fluctuations from factors such as weather, environmental policies, changes in
supply and demand, state and federal regulatory policies and other events. To
reduce price risk caused by market fluctuations, we enter into derivative
contracts, including forwards, futures, swaps and options with approved
counterparties, to hedge our anticipated demand. These contracts, in conjunction
with owned electric generation capacity, are designed to cover estimated
electric customer commitments.
During 2001, Power entered into electric physical forward contracts and gas
futures and swaps with a maximum term of approximately one year, to hedge our
forecasted BGS requirements and gas purchases requirements for generation. These
transactions qualified for hedge accounting treatment under SFAS 133 and were
settled prior to the end of 2001. The majority of the marked-to-market
valuations were reclassified from OCI to earnings during the quarter ended
September 30, 2001. As of December 31, 2001, we did not have any outstanding
derivatives accounted for under this methodology. However, there was substantial
activity during the year ended December 31, 2001. In 2001, the values of these
forward contracts, gas futures and swaps as of June 30 and September 30 were
$(34.2) million and $(0.4) million.
Also as of December 31, 2001, PSE&G had entered into 330 MMBTU of gas
futures, options and swaps to hedge forecasted requirements. As of December 31,
2001, the fair value of those instruments was $(137) million with a maximum term
of approximately one year. PSE&G utilizes derivatives to hedge its gas
purchasing activities which, when realized, are recoverable through its
Levelized Gas Adjustment Clause (LGAC). Accordingly, these commodity contracts
are recognized at fair value as derivative assets or liabilities on the balance
sheet and the offset to the change in fair value of these derivatives is
recorded as a regulatory asset or liability.
We use a value-at-risk (VAR) model to assess the market risk of our
commodity business. This model includes fixed price sales commitments, owned
generation, native load requirements, physical contracts and financial
derivative instruments. VAR represents the potential gains or losses for
instruments or portfolios due to changes in market factors, for a specified time
period and confidence level. PSEG estimates VAR across its commodity business
using a model with historical volatilities and correlations.
The Risk Management Committee (RMC) established a VAR threshold of $25
million. If this threshold was reached, the RMC would be notified and the
portfolio would be closely monitored to reduce risk and potential adverse
movements. In anticipation of the completion of the current BGS contract with
PSE&G on July 31, 2002, the VAR threshold was increased to $75 million.
The measured VAR using a variance/co-variance model with a 95% confidence
level and assuming a one-week time horizon as of December 31, 2001 was
approximately $18 million, compared to the December 31, 2000 level of
57
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
$19 million. This estimate, however, is not necessarily indicative of actual
results, which may differ due to the fact that actual market rate fluctuations
may differ from forecasted fluctuations and due to the fact that the portfolio
of hedging instruments may change over the holding period and due to certain
assumptions embedded in the calculation.
Interest Rates
PSEG, PSE&G, Power and Energy Holdings are subject to the risk of
fluctuating interest rates in the normal course of business. Their policy is to
manage interest rate risk through the use of fixed rate debt, floating rate
debt, interest rate swaps and interest rate lock agreements. As of December 31,
2001, a hypothetical 10% change in market interest rates would result in a $3
million, $4 million, and $2 million, change in annual interest costs related to
short-term and floating rate debt at PSEG, PSE&G, and Energy Holdings,
respectively. The following table shows details of the interest rate swaps at
PSEG, PSE&G, Power and Energy Holdings and their associated values that are
still open at December 31, 2001:
Total Fair Other
Project Notional Pay Receive Market Comprehensive
Underlying Securities Percent Amount Rate Rate Value Income
-------------------------------------------------------------------------------------------------------------------
(millions of dollars, where applicable)
PSEG:
Enterprise Capital Trust II 100% $150.0 5.975% 3-month LIBOR $(5.1) $(3.0)
Securities
PSE&G:
Transition Funding Bonds 100% $497.0 6.287% 3-month LIBOR $(18.5) $ -
Power:
Construction Loan - Waterford 100% $177.5 4.23% 3-month LIBOR $2.3 $1.3
Energy Holdings:
Construction Loan - Tunisia (US$) 60% $60.0 6.9% 3-month LIBOR $(4.4) $(1.7)
Construction Loan - Tunisia (EURO) 60% $67.2 5.2% 3-month EURIBOR* $(1.5) $(0.6)
Construction Loan - Poland (US$) 55% $85.0 8.4% 3-month LIBOR $(30.1) $(8.5)
Construction Loan - Poland (PLN) 55% $37.6 13.2% 3-month WIBOR** $(21.9) $(9.3)
Construction Loan - Oman 81% $18.2 6.3% 3-month LIBOR $(3.3) $(1.7)
Construction Loan - Kalaeloa 50% $57.3 6.6% 3-month LIBOR $(1.8) $(1.2)
Construction Loan - Guadalupe 50% $126.8 6.57% 3-month LIBOR $(4.1) $(2.7)
Construction Loan - Odessa 50% $138.3 7.39% 3-month LIBOR $(6.0) $(3.9)
----------- ---------- -------------- --------------------------
Total Energy Holdings $590.4 $(73.1) $(29.6)
----------- ---------- -------------- --------------------------
Total PSEG $1,414.9 $(94.4) $(31.3)
=========== ========== ============== ==========================
* EURIBOR - EURO Area Inter-Bank Offered Rate
** WIBOR - Warsaw Inter-Bank Offered Rate
58
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
We expect to reclass approximately $14.0 million of open interest rate
swaps from OCI to earnings during the next twelve months. As of December 31,
2001, there was a $31.3 million balance remaining in the Accumulated Other
Comprehensive Loss Account, as indicated in the table above.
We have also entered into several interest rate swaps that were closed out
during 2001 and are being amortized to earnings over the life of the underlying
debt. These items, along with their current and anticipated effect on earnings
discussed.
In February 2001, we entered into various forward-interest rate swaps, with
an aggregate notional amount of $400 million, to hedge the interest rate risk
related to the anticipated issuance of debt. On April 11, 2001, Power issued
$1.8 billion in fixed-rate Senior Notes and closed out the forward starting
interest rate swaps. The aggregate loss, net of tax, of $3.2 million was
classified as Accumulated Other Comprehensive Loss and is being amortized and
charged to interest expense over the life of the debt. During the year ended
December 31, 2001, approximately $0.6 million was reclassified from OCI to
earnings. Management expects it will amortize approximately $0.8 million from
OCI to earnings during the next twelve months.
In March 2001, $160 million of non-recourse bank debt originally incurred
to fund a portion of the purchase price of Global's interest in Chilquinta
Energia, S.A. was refinanced. The private placement offering by Chilquinta
Energia Finance Co. LLC, a Global affiliate, of senior notes was structured in
two tranches: $60 million due 2008 at an interest rate of 6.47% and $100 million
due 2011 at an interest rate of 6.62%.
Equity Securities
Resources has investments in equity securities and limited partnerships.
Resources carries its investments in equity securities at their approximate fair
value as of the reporting date. Consequently, the carrying value of these
investments is affected by changes in the fair value of the underlying
securities. Fair value is determined by adjusting the market value of the
securities for liquidity and market volatility factors, where appropriate. The
aggregate fair values of such investments, which had quoted market prices at
December 31, 2001 and December 31, 2000 were $34 million and $115 million,
respectively. The potential change in fair value resulting from a hypothetical
10% change in quoted market prices of these investments amounted to $3 million
and $9 million at December 31, 2001 and December 31, 2000, respectively.
Foreign Currencies
The objective of our foreign currency risk management policy is to preserve
the economic value of cash flows in non-functional currencies. Toward this end,
Holdings' policy is to hedge all significant firmly committed cash flows
identified as creating foreign currency exposure. In addition, we typically
hedge a portion of exposure resulting from identified anticipated cash flows,
providing the flexibility to deal with the variability of longer-term forecasts
as well as changing market conditions, in which the cost of hedging may be
excessive relative to the level of risk involved.
As of December 31, 2001, Global and Resources had assets located or held in
international locations of approximately $3.4 billion and $1.3 billion,
respectively.
Resources' international investments are primarily leveraged leases of
assets located in Australia, Austria, Belgium, China, Germany, the Netherlands,
the United Kingdom, and New Zealand with associated revenues denominated in
United States Dollars ($US) and therefore, not subject to foreign currency risk.
Global's international investments are primarily in companies that generate
or distribute electricity in Argentina, Brazil, Chile, China, India, Italy,
Oman, Peru, Poland, Taiwan, Tunisia and Venezuela. Investing in foreign
countries involves certain additional risks. Economic conditions that result in
higher comparative rates of inflation in foreign countries are likely to result
in declining values in such countries' currencies. As currencies fluctuate
against the $US, there is a corresponding change in Global's investment value in
terms of the $US. Such change is reflected as an increase or decrease in the
investment value and Other Comprehensive Income (Loss), a
59
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
separate component of Stockholder's Equity. As of December 31, 2001, net foreign
currency devaluations have reduced the reported amount of Energy Holdings' total
Stockholder's Equity by $258 million (after-tax), of which $79 million
(after-tax) was caused by the devaluation of the Chilean Peso and $169 million
(after-tax) was caused by the devaluation of the Brazilian Real.
Global holds a 60% ownership interest in a Tunisian generation facility
under construction. The Power Purchase Agreement, signed in 1999, contains an
embedded derivative that indexes the fixed Tunisian dinar payments to United
States Dollar exchange rates. The embedded derivative is being marked to market
through the income statement. As of January 1, 2001, a $9 million gain was
recorded in the cumulative effect of accounting change for SFAS No. 133. During
2001, an additional gain of $1.4 million was recorded to the income statement as
a result of favorable movements in the United States Dollar to Tunisian dinar
exchange rate.
Global holds approximately a 32% ownership interest in RGE, a Brazilian
distribution company whose debt is denominated in United States Dollars. In
December 2001, the distribution company entered into a series of three forward
exchange contracts to purchase United States Dollars for Brazilian Reals in
order to hedge the risk of fluctuations in the exchange rate between the two
currencies associated with the upcoming principal payments on the debt. These
contracts expire in May, June and July 2002. As of December 31, 2001, Global's
share of the fair value and aggregate notional value of the contracts was
approximately $13 million. These contracts were established as hedges for
accounting purposes resulting in an after tax charge to Other Comprehensive
Income (OCI) of approximately $1.2 million. In addition, in order to hedge the
foreign currency exposure associated with the outstanding portion of the debt,
Global entered into a forward exchange contract in December 2001 to purchase
United States Dollars for Brazilian Reals in approximately their share of the
total debt outstanding ($61 million). The contract expired prior to December 31,
2001 and was not designated as a hedge for accounting purposes. As a result of
unfavorable movements in the United States Dollars to Brazilian Real exchange
rates, a loss of $4 million, after-tax was recorded related to this derivative
upon maturity of the contract. This amount was recorded in Other Income.
Through its 50% joint venture, Meiya Power Company, Global holds a 17.5%
ownership interest in a Taiwanese generation project under construction where
the construction contractor's fees, payable in installments through July 2003,
are payable in Euros. To manage the risk of foreign exchange rate fluctuations
associated with these payments, the project entered into a series of forward
exchange contracts to purchase Euros in exchange for Taiwanese dollars. As of
December 31, 2001, Global's share of the fair value and aggregate notional value
of these forward exchange contracts was approximately $1 million and $16
million, respectively. These forward exchange contracts were not designated as
hedges for accounting purposes, resulting in an after-tax gain of approximately
$0.5 million. In addition, after-tax gains of $1 million were recorded during
2001 on similar forward exchange contracts expiring during the year.
During 2001, Global purchased approximately 100% of a Chilean distribution
company. In order to hedge final Chilean peso denominated payments required to
be made on the acquisition, Global entered into a forward exchange contract to
purchase Chilean Pesos for United States Dollars. This transaction did not
qualify for hedge accounting, and, as such, upon settlement of the transaction,
Global recognized an after-tax loss of $0.5 million. Furthermore, as a
requirement to obtain certain debt financing necessary to fund the acquisition,
and in order to hedge against fluctuations in the United States Dollars to
Chilean Peso foreign exchange rates, Global entered into a forward contract with
a notional value of $150 million to exchange Chilean Pesos for United States
Dollars. This transaction expires in October 2002 and is considered a hedge for
accounting purposes. As of December 31, 2001, the derivative asset value of $4
million has been recorded to OCI, net of taxes ($1.4 million). In addition,
Global holds a 50% interest in another Chilean distribution company, which was
anticipating paying its U.S. investors a return of capital. In order to hedge
the risk of fluctuations in the Chilean peso to U.S. dollar exchange rate, the
distribution company entered into a forward exchange contract to purchase United
States Dollars for Chilean Pesos. Global's after-tax share of the loss on
settlement of this transaction (recorded by the distribution company) was $0.3
million.
In January 2002, RGE entered into a series of nine cross currency interest
rate swaps for the purpose of hedging its exposure to fluctuations in the
Brazilian Real to United States Dollars exchange rates with respect to its
United States Dollars denominated debt principal payments due in 2003 through
2006. The instruments convert the variable LIBOR based interest payments on the
loan balance to variable CDI based interest payments. CDI is the Brazilian
interbank interest rate. As a result, the distribution company has hedged its
foreign currency exposure but is still at
60
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
risk for variability in the Brazilian CDI interest rate during the terms of the
instruments. Global's share of the notional value of the instruments is
approximately $15 million for the instruments maturing in May, June and July of
98
--------------------------------------------
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
--------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
2003 through 2005 and approximately $19 million for the instruments maturing in
May, June and July 2006. Also in January 2002, the distribution company entered
into two similar cross currency interest rate swaps to hedge the United States
Dollars denominated interest payments due on the debt in February 2002 and May
2002. Global's share of the notional value of these two instruments is
approximately $3 million each.
Credit Risk
Credit risk relates to the risk of loss that we would incur as a result of
non-performance by counterparties pursuant to the terms of their contractual
obligations. We have established credit policies that we believe significantly
minimize credit risk. These policies include an evaluation of potential
counterparties' financial condition (including credit rating), collateral
requirements under certain circumstances and the use of standardized agreements,
which may allow for the netting of positive and negative exposures associated
with a single counterparty.
As a result of the BGS auction, Power has contracted to provide generating
capacity to the direct suppliers of New Jersey electric utilities, including
PSE&G, commencing August 1, 2002. These bilateral contracts are subject to
credit risk. This credit risk relates to the ability of counterparties to meet
their payment obligations for the power delivered under each BGS contract. This
risk is substantially higher than the risk associated with potential nonpayment
by PSE&G under the BGS contract expiring July 31, 2002. Any failure to collect
these payments under the new BGS contracts could have a material impact on our
results of operations, cash flows, and financial position.
In December 2001, Enron Corp. (Enron) filed for reorganization under
Chapter 11 of the U.S. Bankruptcy Code. Power had entered into a variety of
energy trading contracts with Enron and its affiliates in the Pennsylvania-New
Jersey-Maryland Power Pool (PJM) area as part of its energy trading activities.
We took proper steps to mitigate our exposures to both Enron and other
counterparties who could have been affected by Enron. As of December 31, 2001,
we owed Enron approximately $23 million, net, and Enron held a letter of credit
from Power for approximately $40 million.
As a result of the California Energy Crisis, Pacific Gas Electric Company
(PG&E) filed for protection under Chapter 11 of the US Bankruptcy Code on April
16, 2001. GWP, Hanford and Tracy had combined pre-petition receivables due from
PG&E, for all plants amounting to approximately $62 million. Of this amount,
approximately $25 million had been reserved as an allowance for doubtful
accounts resulting in a net receivable balance of approximately $37 million.
Global's pro-rata share of this gross receivable and net receivable was
approximately $30 million and $18 million, respectively.
In December 2001, GWF, Hanford and Tracy reached an agreement with PG&E
which stipulates that PG&E will make full payment of the $62 million in 12 equal
installments, including interest by the end of 2002. On December 31, 2001, PG&E
paid GWF $8 million, repesenting the initial installment payment and all accrued
interest due, pursuant to the agreement.
As of December 31, 2001, GWF, Hanford and Tracy still had combined
pre-petition receivables due from PG&E for all plants amounting to approximately
$57 million. Global's pro-rata share of this receivable was $27 million. As a
result of this agreement, GWF, Hanford and Tracy reversed the reserve of $25
million which increased operating income by $25 million (of which Global's share
was $11 million).
61
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Note 10. Commitments and Contingent Liabilities
Nuclear Insurance Coverages and Assessments
Our insurance coverages and maximum retrospective assessments for its
nuclear operations are as follows:
Total Site Power
Type and Source of Coverages Coverage Assessments
------------------------------------------------------- -------------------- ------------------
(Millions of Dollars)
Public and Nuclear Worker Liability (Primary Layer):
American Nuclear Insurers...................... $200.0 (A) $10.7
Nuclear Liability (Excess Layer):
Price-Anderson Act............................. 9,338.1 (B) 277.3
-------------------- ------------------
Nuclear Liability Total.................. $9,538.1 (C) $288.0
==================== ==================
Property Damage (Primary Layer):
Nuclear Electric Insurance Limited (NEIL)
Primary
(Salem/Hope Creek/Peach Bottom)....................... $500.0 $19.3
Property Damage (Excess Layers):
NEIL II (Salem/Hope Creek/Peach Bottom)........ 1,250.0 13.2
NEIL Blanket Excess
(Salem/Hope Creek/Peach Bottom)............. 1,000.0 (D) 2.1
-------------------- ------------------
Property Damage Total (Per Site)............... $2,750.0 (E) $34.6
==================== ==================
Accidental Outage:
NEIL I (Peach Bottom).......................... $245.0 (F) $6.0
NEIL I (Salem)................................. 281.3 7.7
NEIL I (Hope Creek)............................ 490.0 4.9
-------------------- ------------------
Replacement Power Total ................. $1,016.3 $18.6
==================== ==================
(A) The primary limit for Public Liability is a per site aggregate limit with
no potential for assessment. The Nuclear Worker Liability represents the
potential liability from workers claiming exposure to the hazard of
nuclear radiation. This coverage is subject to an industry aggregate
limit, includes annual automatic reinstatement if the Industry Credit
Rating Plan (ICRP) Reserve Fund exceeds $400 million, and has an
assessment potential under former canceled policies.
(B) Retrospective premium program under the Price-Anderson liability
provisions of the Atomic Energy Act of 1954, as amended. Nuclear is
subject to retrospective assessment with respect to loss from an incident
at any licensed nuclear reactor in the United States. This retrospective
assessment can be adjusted for inflation every five years. The last
adjustment was effective as of August 20, 1998. This retrospective
program is in excess over the Public and Nuclear Worker Liability primary
layers.
(C) Limit of liability under the Price-Anderson Act for each nuclear
incident.
(D) For property limits excess of $1.75 billion, we participate in a Blanket
Limit policy where the $1 billion limit is shared by Amergen, Exelon, and
us among the Clinton, Oyster Creek, TMI-1, Peach Bottom, Salem and Hope
Creek sites. This limit is not subject to reinstatement in the event of a
loss. Participation in this program significantly reduces our premium and
the associated potential assessment.
(E) Effective January 1, 2002, NEIL II coverage was reduced to $600 million.
(F) Peach Bottom has an aggregate indemnity limit based on a weekly indemnity
of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for
68 weeks. Salem has an aggregate indemnity limit based on
62
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
a weekly indemnity of 2.5 million for 52 weeks followed by 80% of the
weekly indemnity for 75 weeks. Hope Creek has an aggregate indemnity limit
based on a weekly indemnity of $3.5 million for 52 weeks followed by 80% of
the weekly indemnity for 110 weeks.
The Price-Anderson Act sets the "limit of liability" for claims that could
arise from an incident involving any licensed nuclear facility in the nation.
The "limit of liability" is based on the number of licensed nuclear reactors and
is adjusted at least every five years based on the Consumer Price Index. The
current "limit of liability" is $9.5 billion. All utilities owning a nuclear
reactor, including us, have provided for this exposure through a combination of
private insurance and mandatory participation in a financial protection pool as
established by the Price-Anderson Act. Under the Price-Anderson Act, each party
with an ownership interest in a nuclear reactor can be assessed its share of
$88.1 million per reactor per incident, payable at $10 million per reactor per
incident per year. If the damages exceed the "limit of liability," the President
is to submit to Congress a plan for providing additional compensation to the
injured parties. Congress could impose further revenue raising measures on the
nuclear industry to pay claims. PSEG Nuclear's LLC maximum aggregate assessment
per incident is $277.3 million (based on our ownership interests in Hope Creek,
Peach Bottom and Salem) and its maximum aggregate annual assessment per incident
is $31.5 million. This does not include the $10.7 million that could be assessed
under the nuclear worker policies.
Further, a decision by the U.S. Supreme Court, not involving us, has held
that the Price-Anderson Act did not preclude awards based on state law claims
for punitive damages.
We are a member of an industry mutual insurance company, Nuclear Electric
Insurance Limited (NEIL). NEIL provides the primary property and decontamination
liability insurance at Salem/Hope Creek and Peach Bottom. NEIL also provides
excess property insurance through its decontamination liability, decommissioning
liability, and excess property policy and replacement power coverage through its
accidental outage policy. NEIL policies may make retrospective premium
assessments in case of adverse loss experience. Our maximum potential
liabilities under these assessments are included in the table and notes above.
Certain provisions in the NEIL policies provide that the insurer may suspend
coverage with respect to all nuclear units on a site without notice if the NRC
suspends or revokes the operating license for any unit on a site, issues a
shutdown order with respect to such unit or issues a confirmatory order keeping
such unit down.
Guaranteed Obligations
Power has guaranteed certain energy trading contracts of ER&T. As of
December 31, 2001 Power has issued or primarily executed $506 million of
guarantees on behalf of ER&T, of which Power's exposure is $153 million.
We, Energy Holdings or Global have guaranteed certain obligations of
Global's affiliates, including the successful completion, performance or other
obligations related to certain of the projects, in an aggregate amount of
approximately $241 million as of December 31, 2001. A substantial portion of
such guarantees is eliminated upon successful completion, performance and/or
refinancing of construction debt with non-recourse project debt.
Hazardous Waste
The New Jersey Department of Environmental Protection (NJDEP) regulations
concerning site investigation and remediation require an ecological evaluation
of potential injuries to natural resources in connection with a remedial
investigation of contaminated sites. The NJDEP is presently working with
industry to develop procedures for implementing these regulations. These
regulations may substantially increase the costs of remedial investigations and
remediations, where necessary, particularly at sites situated on surface water
bodies. PSE&G and predecessor companies owned and/or operated certain facilities
situated on surface water bodies, certain of which are currently the subject of
remedial activities. The financial impact of these regulations on these projects
is not currently estimable. We do not anticipate that the compliance with these
regulations will have a material adverse effect on its financial position,
results of operations or net cash flows.
63
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
PSE&G Manufactured Gas Plant Remediation Program
PSE&G is currently working with NJDEP under a program (Remediation Program)
to assess, investigate and, if necessary, remediate environmental conditions at
PSE&G's former manufactured gas plant sites. To date, 38 sites have been
identified. The Remediation Program is periodically reviewed and revised by
PSE&G based on regulatory requirements, experience with the Remediation Program
and available remediation technologies. The long-term costs of the Remediation
Program cannot be reasonably estimated, but experience to date indicates that at
least $20 million per year could be incurred over a period of about 30 years
since inception of the program in 1988 and that the overall cost could be
material. The costs for this remediation effort are recovered through the SBC.
Net of insurance recoveries, costs incurred from January 1, 2001 through
December 31, 2001 for the Remediation Program amounted to approximately $22.8
million. Net of insurance recoveries, costs incurred through December 31, 2001
for the Remediation Program amounted to $164.6 million. In addition, at December
31, 2001, PSE&G's estimated liability for remediation costs through 2004
aggregated $87 million. Expenditures beyond 2004 cannot be reasonably
estimated.
Passaic River Site
The EPA has determined that a six mile stretch of the Passaic River in
Newark, New Jersey is a "facility" within the meaning of that term under the
Federal Comprehensive Environmental Response, Compensation and Liability Act of
1980 (CERCLA) and that, to date, at least thirteen corporations, including
PSE&G, may be potentially liable for performing required remedial actions to
address potential environmental pollution at the Passaic River "facility." PSE&G
and certain of its predecessors operated industrial facilities at properties
within the Passaic River "facility," comprised of four former manufactured gas
plants (MGP), one operating electric generating station and one former
generating station. Costs to clean up former MGPs are recoverable from utility
customers under the SBC. The operating station has been transferred to Power,
which is responsible for its clean up. We cannot predict what action, if any,
the EPA or any third party may take against PSE&G and Power with respect to
these matters, or in such event, what costs PSE&G and Power may incur to address
any such claims. However, such costs may be material.
Prevention of Significant Deterioration (PSD)/New Source Review
The EPA and NJDEP issued a demand in March 2000 under section 114 of the
Federal Clean Air Act (CAA) requiring information to assess whether projects
completed since 1978 at the Hudson and Mercer coal burning units were
implemented in accordance with applicable PSD/New Source Review regulations. We
completed our response to the section 114 information request in November 2000.
In January 2002, we reached an agreement with the state and federal governments
to resolve allegations of noncompliance with federal and State of New Jersey New
Source Review (NSR) regulations. Under that agreement, we will install advanced
air pollution controls over 10 years that will dramatically reduce emissions of
NOx, SO2, particulate matter, and mercury from the Hudson and Mercer coal units.
The estimated cost of the program is $337 million. We also will pay a $1.4
million civil penalty and spend up to $6 million on supplemental environmental
projects.
The EPA had also asserted that PSD requirements are applicable to Bergen 2,
such that we were required to have obtained a permit before beginning actual
on-site construction. We disputed that PSD requirements were applicable to
Bergen 2. The agreement resolving the NSR allegations concerning Hudson and
Mercer also resolved the dispute over Bergen 2, and allowed construction of the
unit to be completed and operation to commence.
New Generation and Development
Power
PSEG Power New York Inc., an indirect subsidiary of Power, is in the
process developing the Bethlehem Energy Center, a 750 MW combined-cycle power
plant that will replace the 400 MW Albany Steam Station, which
64
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
was acquired from Niagara Mohawk Power Corporation (Niagara Mohawk) in May 2000.
Pending a final project certification decision that is expected within 12
months, Power will be obligated to pay Niagara Mohawk up to $9 million if it
redevelops the Albany Station. However, Power expects this payment will be
reduced based on conditions related to the service date and regulatory
requirements.
Power is constructing a 546 MW natural gas-fired, combined cycle electric
generation plant at Bergen Generation Station at a cost of approximately $290
million with completion expected in June 2002. Power is also constructing an
1,218 MW combined cycle generation plant at Linden for approximately $590
million expected to be completed in May 2003.
In August 2001, subsidiaries of Power closed with a group of banks on
non-recourse project financing for projects in Waterford, Ohio and Lawrenceburg,
Indiana. The Waterford project will be completed in two phases and are expected
to achieve commercial operation in June 2002 and May 2003, respectively. The
Lawrenceburg project is expected to achieve commercial operation by May 2003.
The total combined project cost for Waterford and Lawrenceburg is estimated at
$1.2 billion. Power's required estimated equity investments for these projects
is approximately $400 million. In connection with these projects, ER&T has
entered into a five-year tolling agreement pursuant to which it is obligated to
purchase the output of these facilities at stated prices. As a result, ER&T
will bear the price risk related to the output of these generation facilities
which are scheduled to be completed in 2003.
Power has filed an application with the New York State Public Service
Commission for permission to construct and operate a direct generator lead
(dedicated transmission line) that would deliver up to 1,200 MW of electricity
to the West Side of Manhattan from the Bergen Generating Station. Applications
for New Jersey and Federal approvals are expected to be filed in the near
future. Estimated costs are not expected to exceed $100 million for one 500 MW
line.
In addition, Power has other commitments to purchase equipment and services
to meet its current plans to develop additional generating capacity. The
aggregate amount due under these commitments is approximately $ 500 million.
Energy Holdings
In March 2001, Global, through Dhofar Power Company (DPCO), signed a
20-year concession with the government of Oman to privatize the electric system
of Salalah. The project commenced construction in September 2001 and is expected
to achieve commercial operation by March 2003. Total project cost is estimated
at $277 million. Global's equity investment, including contingencies, is
expected to be approximately $82 million.
In May 2001, GWF Energy LLC (GWF Energy), a 50/50 joint venture between
Global and Harbinger GWF LLC, entered into a 10-year power purchase agreement
with the California Department of Water Resources to provide 340 MW of electric
capacity to California from three new natural gas-fired peaker plants that GWF
Energy expects to build and operate in California. Total project cost is
estimated at $325 million. The first plant, a 90 MW facility, was completed and
began operation in August 2001. Global's permanent equity investment in these
plants, including contingencies, is not expected to exceed $100 million after
completion of project financing, expected to occur in 2002.
On February 25, 2002 the Public Utilities Commission of the State of
California (CPUC) filed a complaint with the Federal Energy Regulatory
Commission (FERC) under Section 206 of the Federal Power Act against sellers
who, pursuant to long-term, FERC authorized contracts, provide power to the
California Division of Water Resources (DWR).
GWF Energy LLC, an affiliate of PSEG Global, as a long-term contract to
sell wholesale power to the DWR and is a named respondent in this proceeding.
The CPUC's complaint, which addresses 44 transactions embodied in 32 contracts
with 22 sellers, alleges that collectively, the specified long term wholesale
power contracts are priced at unjust and unreasonable levels and requests FERC
to abrogate the contracts to enable the State to obtain replacement
65
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
contracts as necessary or in the alternative, to reform the contracts to provide
for just and reasonable pricing, reduce the length of the contracts, and strike
from the contracts the specific non-price and conditions found to be unjust and
unreasonable. In the event of an adverse ruling by the FERC, Energy Holdings and
Global would reconsider any plans to invest in generation facilities in
California.
As of December 31, 2001, Global had $281 million invested in two 1000 MW
gas-fired combined cycle electric generating facilities in Texas, including
approximately $165 million of notes receivable earning an annual rate of 12%. Of
the $165 million outstanding at December 31, 2001, $88 million was repaid in
February 2002. Texas Independent Energy's (TIE) funding for these payments to
Global were made from equity contributions of $44 million from Global and $44
million from Panda Energy, our partner for this project. Earnings and cash
distributions from TIE during 2001 were $15 million and $25 million,
respectively, below expectations due to lower energy prices resulting from the
over-supply of energy in the Texas power market and mild summer temperatures
surpressing demand in the region. Global expects this trend to continue until
the 2004-2005 time frame when market prices are expected to increase, as older
less efficient plants in the Texas power market are expected to be retired and
the demand for electricity is expected to increase. However, no assurances can
be given as to the accuracy of these estimates. Current projections of future
cash flows for each plant, using independent market studies for estimating gas
and electricity prices, market heat rates and capacity prices, do not indicate
the investment to be impaired. We believe that those independent market studies
are the best available for estimating future prices.
Potential Asset Impairments
Global has total investment exposure in Argentina of approximately $632
million. The investments include the following minority interests, with
investment exposure of approximately $420 million, jointly owned by Global and
AES, which are the subject of the Stock Purchase Agreement: a 30% interest in
three Argentine electric distribution companies, Empresa Distribuidora de
Energia Norte S.A. (EDEN), Empresa Distribuidora de Energia Sur S.A. (EDES), and
Empresa Distribuidora La Plata S.A. (EDELAP); a 19% share in the 650 MW Central
Termica San Nicolas power plant (CTSN); and a 33% interest in the 850 MW Parana
power plant (Parana) nearing completion of construction. In addition to these
investments, Global owns a 90% interest in another Argentine company, Empresa
Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA), with about $212
million of investment exposure.
Global's Argentine properties continue to operate, but are faced with
considerable fiscal and cash flow uncertainties due to economic, political and
social conditions in Argentina. Moreover, Parana, EDEN, EDES and EDELAP have
recently received notices of default from its international lenders related to
their non recourse financings. If Argentine conditions do not improve soon,
Global's other Argentine properties may also default on their international
financings. Under a worst case scenario, if PSEG Global were to cease all
operations in Argentina, it would record a pre-tax write off of approximately
$632 million. See Note 19. Subsequent Events for a discussion of the sale to
AES.
As of December 31, 2001, we had recorded unamortized goodwill in the amount
of $649 million, of which $479 million was recorded in connection with Global's
acquisitions of SAESA and Electroandes in Chile and Peru in August and December
of 2001, respectively. The amortization expense related to goodwill was
approximately $3 million for the year ended December 31, 2001.
As of December 31, 2001, our pro-rata share of goodwill included in equity
method investees totaled $375 million. Such goodwill is not consolidated on our
balance sheet in accordance with generally accepted accounting principles.
Global's share of the amortization expense related to such goodwill was
approximately $8 million.
66
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
We are currently evaluating the effect of adopting SFAS 142 on the recorded
amount of goodwill. Some or all of the goodwill at: Rio Grande Energia (RGE)
totaling $142 million (PSEG share) and EDEERSA totaling $63 million could be
impaired upon completion of our evaluation. The impact of adopting SFAS 142 is
likely to be material to our financial position and results of operations. As of
December 31, 2001, our unamortized goodwill and pro-rata share of goodwill in
equity method investees was as follows:
As of
December 31, 2000
----------------------------------------------------------------------
(Millions of dollars)
EDEERSA...................................... $63
SAESA........................................ 315
ElectroAndes................................. 164
Chorzow...................................... 6
-----------------------
Total Global............................ 548
Power........................................ 21
-----------------------
Total On Balance Sheet................ $569
-----------------------
Global
---------------------------------------------
RGE.......................................... $142
Chilquinta/Luz............................... 174
Luz Del Sur.................................. 34
Kalaeloa..................................... 25
-----------------------
Total Off Balance Sheet 375
-----------------------
Total Goodwill $944
=======================
Minimum Lease Payments
We and our subsidiaries lease administrative office space under various
operating leases. As of December 31, 2001 our rental expense under these leases
was approximately $10 million dollars. Total future minimum lease payments as of
December 31, 2001 are:
(Millions of Dollars)
---------------------
2002 $14
2003 10
2004 12
2005 1
2006 4
Thereafter 19
-----------
Total minimum lease payments $60
===========
PSE&G has entered into a capital lease for administrative office space. The
total future minimum payments and present value of this capital lease as of
December 31, 2001 are:
(Millions of Dollars)
---------------------
2002 $8
2003 8
2004 8
2005 8
2006 8
Thereafter 62
-----------
Total minimum lease payments 102
-----------
Less: Imputed Interest (42)
-----------
Present Value of net minimum lease payments $60
67
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
===========
Note 11. Nuclear Decommissioning Trust
In accordance with Federal regulations, entities owning an interest in
nuclear generating facilities are required to determine the costs and funding
methods necessary to decommission such facilities upon termination of operation.
As a general practice, each nuclear owner places funds in independent external
trust accounts it maintains to provide for decommissioning. PSE&G currently
recovers from its customers the amounts to be paid into the trust fund each year
and remits these amounts to Power.
Power maintains the external master nuclear decommissioning trust
previously established by PSE&G. This trust contains two separate funds: a
qualified fund and a non-qualified fund. Section 468A of the Internal Revenue
Code limits the amount of money that can be contributed into a "qualified" fund.
Contributions made into a qualified fund are tax deductible. In the most recent
study the total cost of decommissioning its share of its five nuclear units was
estimated at $986 million in year-end 1995 dollars, excluding contingencies.
Pursuant to the Final Order, PSE&G will collect $29.6 million annually
through the SBC and will remit to Power an equivalent amount solely to fund the
trust. The fair market value of these funds as of December 31, 2001 and 2000 was
$817 million and $716 million, respectively.
Contributions made into the Nuclear Decommissioning Trust Funds are
invested in debt and equity securities. These marketable debt and equity
securities are recorded at amounts that approximate their fair market value.
Those securities have exposure to market price risk. The potential change in
fair value, resulting from a hypothetical 10% change in quoted market prices of
these securities amounts to $82 million. The ownership of the Nuclear
Decommissioning Trust Funds was transferred to Nuclear with the transfer of the
generation-related assets from PSE&G to Power.
With the purchase of Atlantic City Electric Company's (ACE) and Delmarva
Power and Light Company (DP&L)'s interests in Salem, Peach Bottom and Hope
Creek, we received a transfer of $82 million and $50 million representing those
companies respective NDT funds related to the stations in 2001 and 2000,
respectively.
68
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Note 12. Income Taxes
A reconciliation of reported income tax expense with the amount computed by
multiplying pretax income by the statutory Federal income tax rate of 35% is as
follows:
2001 2000 1999
-------------- -------------- ---------------
(Millions of Dollars)
Net Income (Loss)............................................. $770 $764 $(81)
Loss from Discontinued Operations, net of tax 15 12 13
Extraordinary Item (Net of Tax, $345).................... -- -- 804
Cumulative Effect of a Change in Accounting Principle (9) -- --
(Net of Tax)
-------------- -------------- ---------------
Net Income before Extraordinary Item.......................... 776 776 736
Preferred securities (net).................................... 5 9 9
-------------- -------------- ---------------
Subtotal............................................ 781 785 745
-------------- -------------- ---------------
Income taxes:
Federal - Current........................................ 258 157 403
Deferred ...................................... 56 228 63
ITC............................................ (3) (2) (12)
-------------- -------------- ---------------
Total Federal............................... 311 383 454
-------------- -------------- ---------------
State - Current.......................................... 64 159 133
Deferred ......................................... (1) (50) (13)
-------------- -------------- ---------------
Total State................................. 63 109 120
-------------- -------------- ---------------
Foreign - Current........................................ 1 -- --
Deferred ...................................... 6 4 (5)
-------------- -------------- ---------------
Total Foreign............................... 7 4 (5)
-------------- -------------- ---------------
Total............................................... 381 496 569
-------------- -------------- ---------------
Pretax income................................................. $1,162 $1,281 $1,314
============== ============== ===============
Reconciliation between total income tax provisions and tax computed at the
statutory tax rate on pretax income:
2001 2000 1999
------------- -------------- ---------------
(Millions of Dollars)
Tax computed at the statutory rate............................ $407 $448 $460
Increase (decrease) attributable to flow through of certain
tax adjustments:
Plant Related Items...................................... (41) (15) 35
Amortization of investment tax credits................... (3) (2) (12)
Tax Effects Attributable to Foreign Operations........... (19) (14) (7)
New Jersey Corporate Business Tax........................ 41 74 84
Other.................................................... (4) 5 9
------------- -------------- ---------------
Subtotal............................................ (26) 48 109
------------- -------------- ---------------
Total income tax provisions......................... $381 $496 $569
============= ============== ===============
Effective income tax rate..................................... 32.8% 38.7% 43.3%
We provide deferred taxes at the enacted statutory tax rate for all
temporary differences between the financial statement carrying amounts and the
tax bases of existing assets and liabilities irrespective of the treatment for
rate-making purposes. Management believes that it is probable that the
accumulated tax benefits that previously have been treated as a flow-through
item to PSE&G customers will be recovered from utility customers in the future.
Accordingly, an offsetting regulatory asset was established. As of December 31,
2001, PSE&G had a deferred tax liability and an offsetting regulatory asset of
$302 million representing the tax costs expected to be recovered through rates
based upon established regulatory practices which permit recovery of current
taxes payable. This amount was determined using the enacted Federal income tax
rate of 35% and State income tax rate of 9%.
69
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
The following is an analysis of deferred income taxes:
December 31,
-----------------------------
2001 2000
------------- -------------
Deferred Income Taxes (Millions of Dollars)
---------------------
Assets:
Current (net)........................................... $21 $23
------------- -------------
Non-current:
Unrecovered Investment Tax Credits.................... 19 20
Nuclear Decommissioning............................... 25 26
FASB 133.............................................. 16 --
New Jersey Corporate Business Tax..................... 544 544
OPEB ................................................. 83 64
Cost of Removal....................................... 54 55
Development Fees...................................... 21 17
Foreign Currency Translation.......................... 29 23
Contractual Liabilities and Environmental Costs....... 35 35
Market Transition Charge.............................. 59 40
------------- -------------
Total Non-current................................ 885 824
------------- -------------
Total Assets..................................... 906 847
------------- -------------
Liabilities:
Non-current:
Plant Related Items................................... 905 842
Securitization-EMP.................................... 1594 1,657
Leasing Activities.................................... 1146 987
Partnership Activities................................ 73 101
Conservation Costs.................................... 24 124
Pension Costs......................................... 94 58
Taxes Recoverable Through Future Rates (net).......... 130 90
Income from Foreign Operation......................... 41 14
Other................................................. 11 (16)
------------- -------------
Total Non-current................................ 4,018 3,857
------------- -------------
Total Liabilities................................ 4,018 3,857
------------- -------------
Summary -- Accumulated Deferred Income Taxes
Net Current Assets...................................... 21 23
Net Non-current Liability............................... 3,133 3,033
------------- -------------
Total.............................................. $3,112 $3,010
============= =============
70
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Note 13. Pension, Other Postretirement Benefit and Savings Plans
We sponsor several qualified and nonqualified pension plans and other
postretirement benefit plans covering our, as well as our participating
affiliates, current and former employees who meet certain eligibility
criteria. The following table provides a reconciliation of the changes in the
benefit obligations and fair value of plan assets over each of the two years
in the period ended December 31, 2001 and a reconciliation of the funded
status for at the end of both years.
Pension and Other Postretirement Benefit Plans
-----------------------------------------------------------------------------------------------------------------------------
Pension Benefits Other Benefits
---------------------------- -----------------------------------
$ in Millions 2001 2000 2001 2000
-----------------------------------------------------------------------------------------------------------------------------
Change in Benefit Obligation
Benefit Obligation at Beginning of Year $ 2,494.4 $ 2,383.6 $ 702.7 $ 691.2
Service Cost 62.8 60.5 16.3 12.0
Interest Cost 181.6 172.6 46.6 53.9
Actuarial (Gain)/Loss 90.0 (6.2) 8.2 (20.1)
Benefits Paid (153.3) (145.3) (40.4) (36.6)
Plan Amendments -- 22.2 (59.6) 0.0
Business Combinations -- 7.0 -- 2.3
------------ ------------- ------------ ---------------
Benefit Obligation at End of Year 2,675.5 2,494.4 673.8 702.7
------------ ------------- ------------ ---------------
Change in Plan Assets
Fair Value of Assets at Beginning of Year 2,376.1 2,525.6 28.4 28.5
Actual Return on Plan Assets (85.3) (11.8) (1.2) (0.1)
Employer Contributions 90.3 2.8 53.4 36.6
Benefits Paid (153.3) (145.3) (40.4) (36.6)
Business Combinations -- 4.8 -- 0.0
------------ ------------- ------------ ---------------
Fair Value of Assets at End of Year 2,227.8 2,376.1 40.2 28.4
------------ ------------- ------------ ---------------
Reconciliation of Funded Status
Funded Status (447.7) (118.3) (633.6) (674.3)
Unrecognized Net
Transition Obligation 12.7 20.8 275.8 337.9
Prior Service Cost 113.6 129.4 -- 25.1
(Gain)/Loss 455.6 70.3 (120.1) (139.0)
------------ ------------- ------------ ---------------
Net Amount Recognized $ 134.2 $ 102.2 $ (477.9) $ (450.3)
============ ============= ============ ===============
Amounts Recognized In Statement
Of Financial Position
Prepaid Benefit Cost $ 160.5 $ 125.4 $ -- $ 0.0
Accrued Cost (53.3) (49.5) (477.9) (450.3)
Intangible Asset 19.8 22.6 N/A N/A
Accumulated Other Comprehensive Income 7.2 3.7 N/A N/A
------------ ------------- ------------ ---------------
Net Amount Recognized $ 134.2 $ 102.2 $ (477.9) $ (450.3)
============ ============= ============ ===============
Separate Disclosure for Pension Plans
With Accumulated Benefit Obligation
In Excess of Plan Assets:
Projected Benefit Obligation at End of Year $ 76.3 $ 66.7
Accumulated Benefit Obligation at End of Year $ 61.3 $ 52.7
Fair Value of Assets at End of Year $ 8.4 $ 4.5
71
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
The pension benefits table above provides information relating to the
funded status of all qualified and nonqualified pension plans and other
postretirement benefit plans on an aggregate basis.
------------------------------------------------------------------------------------------------------------------------------
Pension Benefits Other Benefits
------------------------------------ ---------------------------------------
$ in Millions 2001 2000 1999 2001 2000 1999
------------------------------------------------------------------------------------------------------------------------------
Components of Net Periodic Benefit Cost
Service Cost $ 62.8 $ 60.5 $ 68.0 $ 16.3 $ 12.0 $ 13.1
Interest Cost 181.6 172.6 163.3 46.6 53.9 51.3
Expected Return on Plan Assets (211.1) (221.0) (197.3) (3.1) (2.6) (1.7)
Amortization of Net
Transition Obligation 8.1 8.1 8.1 27.3 30.4 30.4
Prior Service Cost 15.9 14.3 14.1 0.0 2.2 2.2
(Gain)/Loss 0.4 0.5 0.8 (5.9) (3.4) (3.0)
----------- ------------ ----------- ------------- ------------ ------------
Net Periodic Benefit Cost $ 57.7 $ 35.0 $ 57.0 $ 81.2 $ 92.5 $ 92.3
=========== ============ =========== ============= ============ ============
Components of Total Benefit Expense
Net Periodic Benefit Cost $ 57.7 35.0 57.0 $ 81.2 $ 92.5 $ 92.3
Effect of Regulatory Asset 0.0 0.0 0.0 19.3 19.3 19.3
Total Benefit Expense Including Effect of
----------- ------------ ----------- ------------- ------------ ------------
Regulatory Asset $ 57.7 $ 35.0 $ 57.0 $ 100.5 $ 111.8 $ 111.6
=========== ============ =========== ============= ============ ============
Components of Other Comprehensive Income
Decrease in Intangible Asset $ 2.8 $ 0.9 $ 2.6
Increase in Additional Minimum Liability 0.7 (1.8) (3.4)
----------- ------------ ----------- ------------- ------------ ------------
Other Comprehensive Income $ 3.5 $ (0.9) $ (0.8) N/A N/A N/A
=========== ============ =========== ============= ========== ============
Weighted-Average Assumptions as of December 31
Discount Rate 7.25% 7.50% 7.50% 7.25% 7.50% 7.50%
Expected Return on Plan Assets 9.00% 9.00% 9.00% 9.00% 9.00% 9.00%
Rate of Compensation Increase 4.69% 4.69% 4.69% 4.69% 4.69% 4.69%
Rate of Increase in Health Benefit Costs
Administrative Expense 5.00% 5.00% 5.00%
Dental Costs 6.00% 6.00% 5.00%
Pre-65 Medical Costs
Immediate Rate 9.50% 10.00% 11.00%
Ultimate Rate 6.00% 6.00% 5.00%
Year Ultimate Rate Reached 2008 2008 2011
Post-65 Medical Costs
Immediate Rate 7.50% 8.00% 7.00%
Ultimate Rate 6.00% 6.00% 5.00%
Year Ultimate Rate Reached 2004 2004 2003
Effect of a Change in the Assumed Rate of
Increase in Health Benefit Costs
Effect of a 1% Increase On
Total of Service Cost and Interest Cost 4.6 4.5 4.5
Postretirement Benefit Obligation 45.4 48.5 45.7
Effect of a 1% Decrease On
Total of Service Cost and Interest Cost (3.9) (3.8) (4.7)
Postretirement Benefit Obligation (39.1) (41.4) (39.3)
In 1998, the BPU ordered PSE&G to fund in an external trust its annual OPEB
obligation to the maximum extent allowable. In 1999, $12 million was funded, as
allowed. In 2001, $13 million was funded, as allowed. Remaining OPEB costs will
not be funded in an external trust, as mandated by the BPU.
72
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
In October 1999, PSE&G recorded deferred assets and liabilities associated
with the payment and collection of co-owner related OPEB costs. Such costs will
be amortized over the remainder of the twenty-year period through 2013, in
accordance with SFAS 106. No assurances for recovery of such assets and
liabilities can be given.
401K Plans
We sponsor two defined contribution plans. Represented employees of PSE&G,
Power and Services are eligible for participation in the PSEG Employee Savings
Plan (Savings Plan), while non-represented employees of PSE&G, Power, Energy
Holdings and Services are eligible for participation in the PSEG Thrift and
Tax-Deferred Savings Plan (Thrift Plan). These plans are 401(k) plans to which
eligible employees may contribute up to 25% of their compensation. Employee
contributions up to 7% for Savings Plan participants and up to 8% for Thrift
Plan participants are matched with employer contributions of cash or PSEG
common stock equal to 50% of such employee contributions. For periods prior to
March 1, 2002, Employer contributions, related to participant contributions in
excess of 5% and up to 7%, were made in shares of PSEG common stock for
Savings Plan participants. For periods prior to March 1, 2002, Employer
contributions, related to participant contributions in excess of 6% and up to
8%, were made in shares of PSEG common stock for Thrift Plan participants.
Beginning on March 1, 2002, and thereafter, all Employer contributions will be
made in cash to the each plan. The amount expensed for Employer matching
contributions to the plans was approximately $23, $22 million, and $21 million
in 2001, 2000, and 1999, respectively.
Note 14. Stock Options, Stock Purchase Plan and Stock Repurchase Program
Stock Options
We apply APB Opinion No. 25, "Accounting for Stock Issued to Employees,"
and related Interpretations in accounting for stock-based compensation plans,
which are described below. Accordingly, compensation expense has been
recognized for performance units and dividend equivalent rights issued in
tandem with an equal number of options under its fixed stock option grants
under the 1989 Long-Term Incentive Plan (1989 LTIP). Performance units and
dividend equivalents provide cash payments, dependent upon our future
financial performance in comparison to other companies and dividend payments
made on our Common Stock, to assist recipients in exercising options granted.
Prior to 1997, all options were granted in tandem with performance units and
dividend equivalent rights. In 2001, 2000 and 1999, there were no options
granted in tandem with performance units and dividend equivalent rights. No
compensation cost has been recognized for fixed stock option grants since the
exercise price of the stock options equaled the market price of the underlying
stock on the date of grant. Had compensation costs for stock option grants
been determined based on the fair value at the grant dates for awards under
these plans in accordance with SFAS No. 123 "Accounting for Stock-Based
Compensation," there would have been a charge to our net income of
approximately $9.6 million, $3.6 million and $1.8 million in 2001, 2000 and
1999, respectively, with a $(0.05), $(0.02) and $(0.01) impact on earnings per
share in 2001, 2000 and 1999, respectively.
Under our 1989 LTIP and 2001 Long-Term Incentive Plan (2001 LTIP),
non-qualified options to acquire shares of common stock may be granted to
officers and other key employees selected by the Organization and Compensation
Committee of our Board of Directors, the plan's administrative committee (the
"Committee"). Payment by option holders upon exercise of an option may be made
in cash or, with the consent of the Committee, by delivering previously acquired
shares of PSEG common stock. In instances where an optionee tenders shares
acquired from a grant previously exercised that were held for a period of less
than six months, an expense will be recorded for the difference between the fair
market value at exercise date and the option price. Options are exercisable over
a period of time designated by the Committee (but not prior to one year from the
date of grant) and are subject to such other terms and conditions as the
Committee determines. Vesting schedules may be accelerated upon the occurrence
of certain events, such as a change in control. Options may not be transferred
during the lifetime of a holder.
The 1989 LTIP currently provides for the issuance of up to 15,000,000
options to purchase shares of common stock. At December 31, 2001, there were
10,759,350 options available for future grants under the 1989 LTIP.
73
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
The 2001 LTIP currently provides for the issuance of up to 15,000,000
options to purchase shares of common stock. At December 31, 2001, there were
11,169,500 options available for future grants under the 2001 LTIP.
Since the 1989 LTIP's inception, we have purchased shares on the open
market to meet the exercise of stock options. The difference between the cost of
the shares (generally purchased on the date of exercise) and the exercise price
of the options has been reflected in Stockholders' Equity except where otherwise
discussed.
Changes in common shares under option for the three fiscal years in the
period ended December 31, 2001 are summarized as follows:
2001 2000 1999
---------------------------- ---------------------------- -----------------------------
Weighted Weighted Weighted
Average Average Average
Options Exercise Price Options Exercise Price Options Exercise Price
----------- ---------------- ----------- ---------------- ------------ ----------------
Beginning of year 5,186,099 40.38 2,561,883 $34.60 1,243,800 $36.01
Granted 2,833,000 41.84 2,745,500 45.33 1,367,000 33.13
Exercised (303,135) 32.83 (110,684) 29.87 (44,167) 30.37
Canceled (63,501) 41.27 (10,600) 31.23 (4,750) 28.01
----------- ----------- ----------- ---------- ------------ ----------
End of year 7,652,463 41.22 5,186,099 40.38 2,561,883 34.60
----------- ----------- ----------- ---------- ------------ ----------
Exercisable at end of year 2,767,830 39.19 1,170,278 $34.91 412,738 $35.07
----------- ----------- ----------- ---------- ------------ ----------
-----------------------------------------------------------------------------------------------
Weighted average fair
value of options granted
during the year $7.22 $8.73 $4.20
=========== ========== ==========
For this purpose, the fair value of each option grant is estimated on the
date of grant using the Black-Scholes option-pricing model with the following
weighted average assumptions used for grants in 2001, 2000, and 1999,
respectively: expected volatility of 28.22%, 26.63%, and 21.45%, risk free
interest rates of 4.40%, 6.06%, and 6.16%, expected lives of 4.2 years, 4.4
years, and 4 years, respectively. There was a dividend yield of 5.18% in 2001,
4.77% in 2000, and 6.52% in 1999 on the non-tandem grants.
The following table provides information about options outstanding at
December 31, 2001:
-------------------------------------------------------------------------- -------------------------------------
Options Outstanding Options Exercisable
-------------------------------------------------------------------------- -------------------------------------
Weighted Weighted Weighted
Average Average Average
Range of Outstanding at Remaining Exercise Exercisable at Exercise
Exercise Prices December 31, 2001 Contractual Life Price December 31, 2000 Price
-------------------------------------------------------------------------- -------------------------------------
$25.03-$30.02 173,300 5.6 years $ 29.56 173,300 $ 29.56
$30.03-$35.03 1,158,663 7.6 years 33.13 782,322 33.13
$35.04-$40.03 774,500 5.9 years 39.31 774,500 39.31
$40.04-$45.04 3,263,000 9.1 years 41.79 400,000 44.06
$45.05-$50.05 2,283,000 8.8 years 46.06 637,708 46.06
-------------------------------------------------------------------------- -------------------------------------
$25.03-$50.05 7,652,463 8.3 years $ 41.22 2,767,830 $ 39.19
-------------------------------------------------------------------------- -------------------------------------
In June 1998, the Committee granted 150,000 shares of restricted common
stock to a key executive. An additional 60,000 shares or restricted stock was
granted to this executive in November 2001. These shares are subject to
restrictions on transfer and subject to risk of forfeiture until earned by
continued employment. The shares vest on a staggered schedule beginning on March
31, 2002 and become fully vested on March 31, 2007. The unearned compensation
related to this restricted stock grant as of December 31, 2001 is approximately
$5 million and is included in retained earnings on the consolidated balance
sheets.
In addition the Committee granted 100,000 shares of restricted common stock
to another key executive. These shares are subject to restrictions on transfer
and subject to risk of forfeiture until earned by
74
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
continued employment. The shares vest on at one-third per year beginning on July
1, 2002 and become fully vested on July 1, 2004. The unearned compensation
related to this restricted stock grant as of December 31, 2001 is approximately
$4 million and is included in retained earnings on the consolidated balance
sheets.
Our Stock Plan for Outside Directors provides non-employee directors, as
part of their annual retainer, 600 shares of common stock, increased from 300
shares per year beginning in 1999. With certain exceptions, the restrictions on
the stock provide that the shares are subject to forfeiture if the individual
ceases to be a director at any time prior to the Annual Meeting of Stockholders
following his or her 70th birthday. The fair value of these shares is recorded
as compensation expense in the consolidated statements of income.
Employee Stock Purchase Plan
We maintain an employee stock purchase plan for all eligible employees.
Under the plan, shares of the common stock may be purchased at 95% of the fair
market value. Employees may purchase shares having a value not exceeding 10% of
their base pay. During 2001, 2000 and 1999, employees purchased 85,552, 101,986,
and 98,099 shares at an average price of $44.02, $37.06, and $38.21 per share,
respectively. At December 31, 2001, 1,289,780 shares were available for future
issuance under this plan.
Stock Repurchase Program
In September 1998, our Board of Directors authorized the repurchase of 30
million shares of Common Stock. A total of 24.3 million shares were repurchased
at a cost of approximately $905 million under this program as of December 31,
2000, when the authorization expired. In September 2001, the board re-authorized
the purchase of the balance of 5.7 million shares. As of December 31, 2001, an
additional 2.2 million shares were repurchased at a cost of approximately $92
million.
Note 15. Financial Information by Business Segments
Basis of Organization
Power's business has evolved during 2002. With the transfer of the basic
gas supply service (BGSS) contract to Power and the commencement of the new
basic generation service contracts (BGS) with wholesale electric suppliers,
Power's business has become a fully integrated wholesale energy supply business.
As a result of that evolution of Power's business, trading activities changed
from a stand-alone operation to a function that has become fully integrated with
the wholesale energy supply business, and primarily serves to optimize the value
of that business. Therefore, upon review and in accordance with SFAS No. 131,
"Disclosures About Segments of an Enterprise and Related Information" (SFAS
131), we have determined that Power's generation and trading components no
longer meet the definition of separate operating segments for financial
reporting purposes and we have reported Power's financial position and results
of operations as one segment. All prior periods have been reclassified to
conform to the current presentation.
Power
Power earns revenues by selling energy on a wholesale basis under contract
to power marketers and to load serving entities (LSEs) and by bidding the
energy, capacity and ancillary services of Power into the market. Electrical
energy is produced by generation plants and is ultimately delivered to customers
for use in lighting, heating and air conditioning and operation of other
electrical equipment. Energy is our principal product and is priced on a usage
basis, typically in cents per thousand Watt-hours (kWh) or dollars per million
Watt-hours (mWh). Capacity, as a product that is distinct from energy, is a
commitment to the Independent System Operator (ISO) that a given unit will be
available for dispatch if it is needed to meet system demand. Capacity is
typically priced in dollars per MW for a given sale period (e.g., mW-day or
mW-year). Capacity generally refers to the power output rating of a generation
plant, measured on an instantaneous basis. Ancillary services constitute another
category of energy-related activities supplied by generation unit owners to the
ISO.
75
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Power also earns revenues by trading energy, capacity, fixed transmission
rights, fuel and emission allowances in the spot, forward and futures markets
and through financial transactions, including swaps, options and futures in the
electricity markets.
Power engages in physical and financial transactions in the electricity
wholesale markets and execute an overall risk management strategy to mitigate
the effects of adverse movements in the fuel and electricity markets. We
actively trade energy, capacity, fixed transmission rights, fuel and emission
allowances in the spot, forward and futures markets primarily within PJM, but
also throughout the Super Region. We are also involved in financial transactions
that include swaps, options and futures in the electricity markets. In addition
to participating in each of the major electricity supply and capacity markets in
the Super Region, we also market and trade a broad spectrum of other energy and
energy-related products. These products include coal, oil, natural gas, sulfur
dioxide and nitrous oxide emissions allowances and financial instruments
including fixed transmission rights. Our marketing and energy trading activity
for these products extends throughout the United States and involves physical
and financially settled transactions, futures, options, swaps and basis
contracts. None of our trading revenue with any individual counterparty exceeds
10%.
We have developed a hedging and overall risk management strategy to limit
our risk exposure and to track our positions in the wholesale markets. Hedging
is used as the primary method for protecting against adverse price fluctuations
and involves taking a position in a related financial instrument that is
designed to offset the risk associated with the original position. We only use
hedging instruments that correspond to the generation, purchase or sale of
electricity and the purchase or sale of fuel.
PSE&G
All operations of this segment are conducted by PSE&G. The PSE&G segment
generates revenue from its tariffs under which it provides electric transmission
and electric and gas distribution services to residential, commercial and
industrial customers in New Jersey. The rates charged for electric transmission
are regulated by FERC while the rates charged for electric and gas distribution
are regulated by the BPU. Revenues are also earned from a variety of other
activities such as sundry sales, the appliance service business, wholesale
transmission services and other miscellaneous services.
Global
Global earns revenues from its investment in and operation of projects in
the generation and distribution of energy, both domestically (exclusive of the
Super Region included in Power above) and internationally.
Resources
Resources receives revenues from its passive investments in leveraged
leases, limited partnerships, leveraged buyout funds and marketable securities.
Resources operates both domestically and internationally.
Energy Technologies
Energy Technologies, an energy management company that constructs, operates
and maintains HVAC/mechanical operating systems for, and provides energy-related
engineering, consulting and mechanical contracting services to, industrial and
commercial customers in the Northeastern and Middle Atlantic United States.
Energy Technologies is also comprised of an asset management group, which
includes various Demand Side Management (DSM) investments. In 2002, we announced
our decision to exit the HVAC/mechanical operating business of Energy
Technologies. The sale of the HVAC/mechanical operating companies is expected to
be completed by June 2003. Operating results of the HVAC operating companies of
Energy Technologies, less certain allocated costs, have been reclassified into
discontinued operations in our Consolidated Statements of Income. For the years
ended December 31, 2000 and 1999, the businesses of Energy Technologies included
retail commodity sales of electricity and natural gas, which do not qualify for
accounting treatment as discontinued operations.
76
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
Other
Our other activities include amounts applicable to PSEG (parent
corporation), Energy Holdings (parent corporation), EGDC and intercompany
eliminations, primarily relating to intercompany transactions between Power and
PSE&G. The net losses primarily relate to financing and certain administrative
and general costs at the parent corporations.
Information related to the segments of our business is detailed below:
Power Energy Consolidated
(B) PSE&G Resources Global Technologies Other Total
------------ --------- ------------ ---------- --------------- -------- ------------
(Millions of Dollars)
-------------------------------------
For the Year Ended December 31, 2001:
Total Operating Revenues.......... $2,451 $6,091 $215 $396 $26 $(2,124) $7,055
Depreciation and Amortization..... 95 384 4 11 1 16 511
Interest Income................... 1 21 1 1 4 5 33
Net Interest Charges.............. 143 356 100 79 -- 17 695
Operating Income Before Income
Taxes............................. 644 324 100 156 8 (75) 1,157
Income Taxes...................... 250 89 30 36 3 (27) 381
Equity in earnings of
unconsolidated
Subsidiaries...................... -- -- 55 143 -- -- 198
Income (Loss) Before Discontinued
Operations and Cumulative Effect of
a Change in Accounting Principle.. 394 230 64 100 4 (16) 776
Income (Loss) from Discontinued
Operations........................ -- -- -- 7 (22) -- (15)
Cumulative Effect of a Change in
Accounting Principle.............. -- -- -- 9 -- -- 9
Segment Earnings (Loss)........... 394 230 64 116 (18) (16) 770
Gross Additions to Long-Lived
Assets............................ 1,462 398 1 167 1 24 2,053
As of December 31, 2001:
Total Assets...................... $5,503 $12,963 $3,026 $4,074 $290 $(426) $25,430
Investments in equity method
subsidiaries...................... -- -- 163 1,541 3 19 1,726
For the Year Ended December 31, 2000:
-------------------------------------
Total Operating Revenues.......... $2,275 $4,645 $206 $169 $95 $(869) $9,495
Depreciation and Amortization..... 136 213 5 1 -- -- 362
Interest Income................... 1 21 2 1 4 3 32
Net Interest Charges.............. 198 208 79 53 -- 33 571
Operating Income Before Income
Taxes............................. 521 638 111 69 4 (71) 1,272
Income Taxes...................... 208 260 40 12 2 (22) 496
Equity in earnings of
unconsolidated
Subsidiaries...................... -- -- 13 157 2 -- 172
Income (Loss) Before Discontinued
Operations and Cumulative Effect of
a Change in Accounting Principle.. 313 369 65 40 2 (13) 776
Loss from Discontinued
Operations........................ -- -- -- -- (12) -- (12)
Segment Earnings (Loss)........... 313 369 65 40 (10) (13) 764
Gross Additions to Long-Lived
Assets............................ 479 401 -- 56 7 16 959
As of December 31, 2000:
Total Assets...................... $4,530 $15,267 $2,565 $2,271 $312 $(3,419) $21,526
Investments in equity method
subsidiaries...................... -- -- 239 1,900 -- 24 2,163
For the Year Ended December 31, 1999:
-------------------------------------
Total Operating Revenues.......... $2,691 $3,146 $179 $211 $112 $-- $6,339
Depreciation and Amortization..... 224 305 1 1 1 -- 532
Interest Income................... -- 12 1 -- 2 -- 15
Net Interest Charges.............. 112 275 46 48 -- 8 489
Operating Income Before Income
Taxes............................. 807 356 123 69 10 (60) 1,305
Income Taxes...................... 291 219 50 24 4 (19) 569
Equity in earnings of
unconsolidated
Subsidiaries...................... -- -- 78 129 -- -- 207
Income (Loss) Before Extraordinary
Item, Discontinued Operations and
Cumulative Effect of
a Change in Accounting Principle.. 513 131 66 28 7 (9) 736
Extraordinary Item (A)............ (3,204) 2,400 -- -- -- -- (804)
Income (Loss) from Discontinued
Operations........................ -- -- -- -- (13) -- (13)
Segment Earnings (Loss)........... (2,691) 2,531 66 28 (6) (9) (81)
Gross Additions to Long-Lived
Assets............................ 92 387 -- 1 8 94 582
77
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
(A) See Note 4. Regulatory Issues and Accounting Impacts of Deregulation for
discussion of the extraordinary charge recorded by Power in 1999
and the related regulatory asset for securitization recorded by PSE&G.
(B) Includes approximately $2.1 billion and $870 million charges in 2001 and
2000, respectively, to PSE&G related to the BGS Contract which commenced
in August 2000, following the generation-related asset transfer to Power.
Such amounts are eliminated in consolidation.
Geographic information for us is disclosed below. The foreign assets and
operations noted below were made solely through Energy Holdings.
Revenues (1) Assets (2)
----------------------------------------------- -------------------------------
December 31, December 31,
----------------------------------------------- -------------------------------
2001 2000 1999 2001 2000
----------------------------------------------- -------------------------------
(Millions of Dollars) (Millions of Dollars)
United States................. $6,675 $6,333 $6 190 $20,666 $18,536
Foreign - Resources........... 132 109 89 1,348 1,194
Foreign - Global.............. 248 79 60 3,416 1,796
------------- ------------- ------------- -------------- ------------
Total.................... $7,055 $6,521 $6,339 $25,430 $21,526
============= ============= ============= ============== ============
Identifiable assets in foreign countries include:
Argentina $737 $470
Brazil $282 $295
Chile $880 $270
Peru $520 $250
India (3) $288 $ 51
Netherlands $911 $815
Other $1,146 $839
--------------------------------------------------------------------------------
(1) Revenues are attributed to countries based on the locations of the
investments. Global's revenue includes its share of the net income from
joint ventures recorded under the equity method of accounting.
(2) Total assets are net of foreign currency translation adjustment of $(283)
million (pre-tax) as of December 31, 2001 and $(225) million (pre-tax) as
of December 31, 2000.
(3) India includes assets classified as Current Assets of Discontinued
Operations of $257 million in 2001.
78
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
The table below reflects our investment exposure in Latin American
countries:
INVESTMENT EXPOSURE (1)
--------------------------------
DECEMBER 31,
--------------------------------
2001 2000
--------------- --------------
(MILLIONS OF DOLLARS)
Argentina..................................... $ 632 $ 622
Brazil........................................ 467 462
Chile......................................... 542 180
Peru.......................................... 387 224
Venezuela..................................... 53 51
(1) The investment exposure consists of invested equity plus equity
commitment guarantees. The investments in these Latin American
countries are Global's.
Note 16. Property, Plant and Equipment and Jointly Owned Facilities
Information related to Property, Plant and Equipment of PSEG and its
subsidiaries is detailed below:
December 31,
----------------------------------
2001 2000
---------------- ----------------
Property, Plant and Equipment: (Millions of Dollars)
Generation:
Fossil Production (A).................. $2,039 $1,829
Nuclear Production..................... 154 130
Nuclear Fuel in Service................ 486 417
Construction Work in Progress (A)...... 2,004 483
Other.................................. 7 1
---------------- ----------------
Total Generation.................. 4,690 2,860
---------------- ----------------
Transmission and Distribution:
Electric Transmission (A).............. 1,685 1,183
Electric Distribution.................. 4,254 4,056
Gas Transmission....................... 74 69
Gas Distribution....................... 3,121 2,978
Construction Work in Progress (A)...... 54 43
Plant Held for Future Use.............. 20 20
Other.................................. 292 130
---------------- ----------------
Total Transmission and Distribution 9,500 8,479
---------------- ----------------
Other.................................... 510 558
---------------- ----------------
Total........................... $14,700 $11,897
================ ================
(A) These items include the following amounts which relate to our Global
segment:
December 31,
----------------------------------
2001 2000
---------------- ----------------
Generation: (Millions of Dollars)
Fossil Production...................... $141 $10
Construction Work in Progress.......... 317 172
---------------- ----------------
Total Generation.................. $458 $182
---------------- ----------------
Transmission and Distribution:
Electric Transmission.................. 484 -
Construction Work in Progress.......... 28 -
---------------- ----------------
Total Transmission and Distribution 512 -
---------------- ----------------
Total............................ $970 $182
================ ================
79
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Continued
PSE&G and Power have ownership interests in and are responsible for
providing their share of the necessary financing for the following jointly owned
facilities. All amounts reflect the share of PSE&G's and Power's jointly owned
projects and the corresponding direct expenses are included in Consolidated
Statements of Income as operating expenses.
Plant--December 31, 2001
--------------------------------------------------------------------
Ownership Accumulated
Interest Plant Depreciation
-------------------- -------------------- -----------------
(Millions of Dollars)
Coal Generating
Conemaugh.............................. 22.50% 199 70
Keystone............................... 22.84% 128 51
Nuclear Generating
Peach Bottom........................... 50.00% 249 156
Salem.................................. 57.41% 671 582
Nuclear Support Facilities............. Various 5 1
Pumped Storage Facilities
Yards Creek............................ 50.00% 28 12
Transmission Facilities..................... Various 80 30
Merrill Creek Reservoir..................... 13.91% 2 --
Linden SNG Plant............................ 90.00% 5 4
Plant--December 31, 2000
--------------------------------------------------------------------
Ownership Accumulated
Interest Plant Depreciation
-------------------- -------------------- -----------------
(Millions of Dollars)
Coal Generating
Conemaugh.............................. 22.50% 198 63
Keystone............................... 22.84% 122 47
Nuclear Generating
Peach Bottom........................... 50.00% 88 10
Hope Creek............................. 95.00% 606 508
Salem.................................. 50.00% 645 544
Nuclear Support Facilities............. Various 5 1
Pumped Storage Facilities
Yards Creek............................ 50.00% 28 11
Transmission Facilities..................... Various 97 33
Merrill Creek Reservoir..................... 13.91% 2 --
Linden SNG Plant............................ 90.00% 16 15
80
Note 17. Selected Quarterly Data (Unaudited)
The information shown below, in our opinion, includes all adjustments,
consisting only of normal recurring accruals, necessary to a fair presentation
of such amounts. Due to the seasonal nature of the utility business, quarterly
amounts vary significantly during the year.
Calendar Quarter Ended
-----------------------------------------------------------------------------------------
March 31, June 30, September 30, December 31,
--------------------- --------------------- ----------------------- ---------------------
2001 2000 2001 2000 2001 2000 2001 2000
---------- ---------- ---------- ---------- ---------- ------------ ---------- ----------
(Millions where Applicable)
Operating Revenues......... $2,179 $1,828 $1,519 $1,404 $1,612 $1,400 $1,745 $1,889
Operating Income........... 583 610 417 398 431 392 477 507
Income before Discontinued
Operations and Cumulative
Effect of a Change in
Accounting Principle....... 255 273 153 145 175 143 193 215
Income (Loss) from
Discontinued Operations.... (3) (3) (10) (3) (3) (1) 1 (5)
Cumulative Effective Adjustment 9 -- -- -- -- -- -- --
Net Income................. 261 270 143 142 172 142 194 210
Earnings per Share
(Basic and Diluted)...... 1.25 1.25 0.68 0.66 0.82 0.66 0.95 0.98
Weighted Average Common
Shares and Potential
Dilutive Effect of Stock
Options Outstanding..... 208 216 209 215 208 215 208 215
Note 18. Related Party Transactions
We enter into a number of contracts with various suppliers, customers and
other counterparties in the ordinary course of business. Certain contracts were
entered into with subsidiaries of Foster Wheeler Ltd. E. James Ferland, our
Chairman of the Board, President and Chief Executive Officer, serves on the
Board of Directors of Foster Wheeler. Richard J. Swift, who serves on our
Board of Directors, was the President and Chief Executive Officer of Foster
Wheeler Ltd. at the time the contract was entered into. The open commitment
under the contracts is for approximately $200 million of engineering,
procurement and construction services related to the development of certain
generating facilities for Power and Global. We believe that the contracts were
entered into on commercial terms no more favorable than those available in an
arms-length transaction from other parties and the pricing is consistent with
that available from other third parties.
Note 19. Subsequent Events
On August 24, 2001, Global, entered into a Stock Purchase Agreement to sell
its minority interests in certain assets located in Argentina to the AES
Corporation (AES), the majority owner. These assets are "Assets Held for Sale"
in the December 31, 2001 balance sheet. The sale has not closed, pending receipt
of certain lender consents and regulatory approvals.
On February 6, 2002, AES notified Global of its intent to terminate the
Stock Purchase Agreement. In the Notice of Termination, AES alleged that a
"Political Risk Event", within the meaning of the Stock Purchase Agreement, had
occurred, by virtue of certain decrees of the Government of Argentina, thereby
giving AES the right to terminate. We disagree that a "Political Risk Event", as
defined in the Stock Purchase Agreement, has occurred and have so notified AES.
We will vigorously pursue our rights under the Stock Purchase Agreement
including ongoing discussions with AES to successfully resolve the matter. We
cannot predict the ultimate outcome.
81
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- Concluded
As of December 31, 2001, Global had total investment exposure in Argentina
of approximately $632 million. The investments include the following minority
interests, with investment exposure of approximately $420 million, jointly owned
by Global and AES, which are the subject of the Stock Purchase Agreement: a 30%
interest in three Argentine electric distribution companies, Empresa
Distribuidora de Energia Norte S.A. (EDEN), Empresa Distribuidora de Energia Sur
S.A. (EDES), and Empresa Distribuidora La Plata S.A. (EDELAP); a 19% share in
the 650 MW Central Termica San Nicolas power plant (CTSN); and a 33% interest in
the 850 MW Parana power plant (Parana) nearing the completion of construction.
In addition to these investments, Global has $212 million of investment
exposure with respect to its 90% interest in another Argentine company,
Inversora en Distribucion de Entre Rios S.A. (EDEERSA), inclusive of $63 million
of goodwill.
We have approximately $18 million of interest receivables due from AES, as
provided for in the Stock Purchase Agreement and is due upon resolution of the
pending sale.
82
FINANCIAL STATEMENT RESPONSIBILITY
Our management is responsible for the preparation, integrity and
objectivity of our consolidated financial statements and related notes. The
consolidated financial statements and related notes are prepared in accordance
with generally accepted accounting principles. The financial statements reflect
estimates based upon the judgment of management where appropriate. Management
believes that the consolidated financial statements and related notes present
fairly our financial position and results of operations. Information in other
parts of this Report is also the responsibility of management and is
consistent with these consolidated financial statements and related notes.
The firm of Deloitte & Touche LLP, independent auditors, is engaged to
audit our consolidated financial statements and related notes and issue a report
thereon. Deloitte & Touche's audit is conducted in accordance with generally
accepted auditing standards. Management has made available to Deloitte & Touche
all the corporation's financial records and related data, as well as the minutes
of directors' meetings. Furthermore, management believes that all
representations made to Deloitte & Touche during its audit were valid and
appropriate.
Management has established and maintains a system of internal accounting
controls to provide reasonable assurance that assets are safeguarded, and that
transactions are executed in accordance with management's authorization and
recorded properly for the prevention and detection of fraudulent financial
reporting, so as to maintain the integrity and reliability of the financial
statements. The system is designed to permit preparation of consolidated
financial statements and related notes in accordance with generally accepted
accounting principles. The concept of reasonable assurance recognizes that the
costs of a system of internal accounting controls should not exceed the related
benefits. Management believes the effectiveness of this system is enhanced by an
ongoing program of continuous and selective training of employees. In addition,
management has communicated to all employees its policies on business conduct,
safeguarding assets and internal controls.
The Internal Auditing Department of Services conducts audits and appraisals
of accounting and other operations of PSEG and its subsidiaries and evaluates
the effectiveness of cost and other controls and, where appropriate, recommends
to management improvements thereto. Management considers the internal auditors'
and Deloitte & Touche's recommendations concerning the corporation's system of
internal accounting controls and has taken actions that, in its opinion, are
cost-effective in the circumstances to respond appropriately to these
recommendations. Management believes that, as of December 31, 2001, the
corporation's system of internal accounting controls was adequate to accomplish
the objectives discussed herein.
Our Board of Directors carries out its responsibility of financial overview
through its Audit Committee, which presently consists of six directors who are
not our employees or any of our affiliates. The Audit Committee meets
periodically with management as well as with representatives of the internal
auditors and Deloitte & Touche. The Audit Committee reviews the work of each to
ensure that its respective responsibilities are being carried out and discusses
related matters. Both the internal auditors and Deloitte & Touche periodically
meet alone with the Audit Committee and have free access to the Audit Committee
and its individual members at all times.
E. JAMES FERLAND THOMAS M. O'FLYNN
Chairman of the Board, Executive Vice President and
President and Chief Executive Officer Chief Financial Officer
PATRICIA A. RADO
Vice President and Controller
(Principal Accounting Officer)
November 22, 2002
83
INDEPENDENT AUDITORS' REPORT
To the Stockholders and Board of Directors of
Public Service Enterprise Group Incorporated:
We have audited the consolidated balance sheets of Public Service
Enterprise Group Incorporated and its subsidiaries (the "Company") as of
December 31, 2001 and 2000, and the related consolidated statements of income,
common stockholders' equity and cash flows for each of the three years in the
period ended December 31, 2001. Our audits also included the consolidated
financial statement schedule listed in the Index in Item 14(B)(a). These
consolidated financial statements and the consolidated financial statement
schedule are the responsibility of the Company's management. Our responsibility
is to express an opinion on these consolidated financial statements and the
consolidated financial statement schedule 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 the Company as of December 31,
2001 and 2000, and the results of its operations and its 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. Also,
in our opinion, such consolidated financial statement schedule, when considered
in relation to the basic consolidated financial statements taken as a whole,
presents fairly in all material respects, the information set forth therein.
We have previously audited, in accordance with auditing standards generally
accepted in the United States of America, the consolidated balance sheets of the
Company as of December 31, 1999, 1998, and 1997, and the related consolidated
statements of income, common stockholders' equity and cash flows for the years
ended December 31, 1998 and 1997 (none of which are presented herein), and we
expressed unqualified opinions on those consolidated financial statements.
In our opinion, the information set forth in the Selected Financial Data
for each of the five years in the period ended December 31, 2001, presented in
Item 6, is fairly stated in all material respects, in relation to the
consolidated financial statements from which it has been derived.
As discussed in Note 1 to the consolidated financial statements, on January
1, 2001, the Company adopted Statement of Financial Accounting Standards
("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging
Activities", as amended.
As discussed in Note 2 to the consolidated financial statements, on January
1, 2002, the Company adopted SFAS No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets".
As discussed in Note 2 to the consolidated financial statements, on July 1,
2002, the Company adopted SFAS No. 145, "Rescission of FASB Statements Nos. 4,
44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections", and
the June 2002 provisions of the consensus on Emerging Issues Task Force Issue
No. 02-3, "Issues invoved in Accounting for contracts under EITF 98-10,
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities".
DELOITTE & TOUCHE LLP
Parsippany, New Jersey
February 15, 2002
(November 22, 2002 as to Notes 1, 2, 3, 6, 8, 9, 12, 15, and 16)
84
PART IV
-------
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(B) The following documents are filed as a part of this report:
a. PSEG Financial Statement Schedules:
Schedule II--Valuation and Qualifying Accounts for each of the three
years in the period ended December 31, 2001
SCHEDULE II
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
Schedule II -- Valuation and Qualifying Accounts
Years Ended December 31, 2001 -- December 31, 1999
Column A Column B Column C Column D Column E
-------- ------------- ----------------------------- ------------- -------------
Additions
-----------------------------
Balance at Charged to Charged to Balance at
beginning cost and other accounts Deductions- end of
Description of period expenses Describe describe Period
------------------------------------------- ------------- ----------------------------- ------------- -------------
(Millions of Dollars)
2001:
-----
Allowance for Doubtful Accounts.......... $39 $42 $-- $43(A) $38
Materials and Supplies Valuation Reserve. 11 -- -- 9(D) 2
Other Valuation Allowances............... 22 -- -- -- 22
2000:
-----
Allowance for Doubtful Accounts.......... $35 $45 $-- $41(A) $39
Materials and Supplies Valuation Reserve. 11 -- -- -- 11
Other Valuation Allowances............... 22 -- -- -- 22
1999:
-----
Allowance for Doubtful Accounts.......... $32 $39 $-- $36(A) $34
Discount on Property Abandonments........ 1 -- -- 1(B) --
Materials and Supplies Valuation Reserve. 12 41 -- 42(C) 11
Other Valuation Allowances............... 11 11 -- -- 22
(A) Accounts Receivable/Investments written off.
(B) Amortization of discount to income.
(C) Inventory written off.
(D) Reduced reserve to appropriate level and to remove obsolete inventory.
85
ITEM 7. Financial Statements and Exhibits
A listing of exhibits being filed with this document is as follows:
Exhibit
Number Document
12 Computation of Ratios of Earnings to Fixed Charges
23 Independent Auditors' Consent
99 Certification by E. James Ferland, Chief Executive Officer of
Public Service Enterprise Group Incorporated Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code
99.1 Certification by Thomas M. O'Flynn, Chief Financial Officer
Public Service Enterprise Group Incorporated Pursuant to Section
1350 of Chapter 63 of Title 18 of the United States Code
86
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
Public Service Enterprise Group Incorporated
By /s/ Thomas M. O'Flynn
--------------------------------------------
Thomas M. O'Flynn
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
Date: November 22, 2002
87
Certification Pursuant to Rules 13a-14 and 15d-14
of the 1934 Securities Exchange Act
I certify that:
1. I have reviewed this current report on Form 8-K dated November 22,
2002, of Public Service Enterprise Group Incorporated (the
registrant), which report is being filed solely to reflect the
following; a reclassification of certain businesses as discontinued
operations, a change in the reporting of trading revenues and costs, a
change in business segment reporting and a reclassification of certain
costs related to the early extinguishment of debt.
2. Based on my knowledge, this report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows
of the registrant as of, and for, the periods presented in this
report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this report (the "Evaluation Date"); and
c) presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of the registrant's board of directors:
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified any material weaknesses in internal controls;
and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officer and I have indicated in this
report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: November 22, 2002 /s/ E. JAMES FERLAND
----------------------------
E. James Ferland
Chief Executive Officer
88
Certification Pursuant to Rules 13a-14 and 15d-14
of the 1934 Securities Exchange Act
I certify that:
1. I have reviewed this current report on Form 8-K dated November 22,
2002, of Public Service Enterprise Group Incorporated (the
registrant), which report is being filed solely to reflect the
following; a reclassification of certain businesses as discontinued
operations, a change in the reporting of trading revenues and costs, a
change in business segment reporting and a reclassification of certain
costs related to the early extinguishment of debt.
2. Based on my knowledge, this report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows
of the registrant as of, and for, the periods presented in this
report;
4. The registrant's other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this report (the "Evaluation Date"); and
c) presented in this report our conclusions about the effectiveness
of the disclosure controls and procedures based on our evaluation
as of the Evaluation Date;
5. The registrant's other certifying officer and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the
audit committee of the registrant's board of directors:
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified any material weaknesses in internal controls;
and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officer and I have indicated in this
report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.
Date: November 22, 2002 /s/ THOMAS M. O'FLYNN
--------------------------
Thomas M. O'Flynn
Chief Financial Officer
89