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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
(Mark One)
|X| QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 2002
OR
|_| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______ to _________
Commission Registrant, State of Incorporation, I.R.S. Employer
File Number Address, and Telephone Number Identification No.
- --------------------------------------------------------------------------------
001-09120 PUBLIC SERVICE ENTERPRISE 22-2625848
GROUP INCORPORATED
(A New Jersey Corporation)
80 Park Plaza
P.O. Box 1171
Newark, New Jersey 07101-1171
973-430-7000
http://www.pseg.com
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes |X| No |_|
As of September 30, 2002, Public Service Enterprise Group Incorporated had
outstanding 207,313,548 shares of its sole class of Common Stock, without par
value.
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TABLE OF CONTENTS
PAGE
----
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements 1
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 34
Item 3. Qualitative and Quantitative Disclosures About Market Risk 54
Item 4. Controls and Procedures 56
PART II. OTHER INFORMATION
Item 1. Legal Proceedings 56
Item 5. Other Information 58
Item 6. Exhibits and Reports on Form 8-K 60
Signature 61
i
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions, except for Share Data)
(Unaudited)
For the Three Months Ended For the Nine Months Ended
September 30, September 30,
-------------------------- -------------------------
2002 2001 2002 2001
----------- ----------- ---------- -----------
OPERATING REVENUES $ 2,327 $ 1,616 $ 5,690 $ 5,317
OPERATING EXPENSES
Energy Costs 1,154 564 2,345 2,066
Operation and Maintenance 448 450 1,365 1,352
Write-off of Argentine Investments -- -- 506 --
Depreciation and Amortization 167 152 434 373
Taxes Other Than Income Taxes 31 23 97 92
--------- --------- --------- ---------
Total Operating Expenses 1,800 1,189 4,747 3,883
--------- --------- --------- ---------
OPERATING INCOME 527 427 943 1,434
Foreign Currency Transaction Loss (2) -- (71) --
Other Income 21 12 38 42
Other Deductions -- (5) (1) (9)
Interest Expense (201) (192) (588) (530)
Preferred Securities Dividend Requirements (14) (18) (42) (62)
--------- --------- --------- ---------
INCOME BEFORE INCOME TAXES, DISCONTINUED
OPERATIONS AND CUMULATIVE EFFECT OF A
CHANGE IN ACCOUNTING PRINCIPLE 331 224 279 875
Income Taxes (124) (49) (118) (291)
--------- --------- --------- ---------
INCOME BEFORE DISCONTINUED OPERATIONS
AND CUMULATIVE EFFECT OF A CHANGE IN
ACCOUNTING PRINCIPLE 207 175 161 584
DISCONTINUED OPERATIONS
Loss from Discontinued Operations, net of tax
(including Loss on Disposal net of tax) (3) (3) (41) (17)
--------- --------- --------- ---------
INCOME BEFORE CUMULATIVE EFFECT OF A
CHANGE IN ACCOUNTING PRINCIPLE 204 172 120 567
Cumulative Effect of a Change in Accounting
Principle, net of tax -- -- (120) 9
--------- --------- --------- ---------
NET INCOME $ 204 $ 172 $ -- $ 576
========= ========= ========= =========
WEIGHTED AVERAGE COMMON
SHARES OUTSTANDING (000's) 206,782 208,496 206,552 208,564
========= ========= ========= =========
EARNINGS PER SHARE (BASIC AND DILUTED):
INCOME BEFORE DISCONTINUED OPERATIONS AND
CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE $ 1.00 $ 0.84 $ 0.78 $ 2.80
Loss from Discontinued Operations, net of tax
(including Loss on Disposal, net of tax) (0.01) (0.02) (0.20) (0.08)
Cumulative Effect of a Change in Accounting
Principle, net of tax -- -- (0.58) 0.04
--------- --------- --------- ---------
NET INCOME $ 0.99 $ 0.82 $ -- $ 2.76
========= ========= ========= =========
DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 0.54 $ 0.54 $ 1.62 $ 1.62
========= ========= ========= =========
See Notes to Consolidated Financial Statements.
1
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions)
(Unaudited)
September 30, December 31,
2002 2001
------------- ------------
CURRENT ASSETS
Cash and Cash Equivalents $ 147 $ 167
Accounts Receivable:
Customer Accounts Receivable 631 686
Other Accounts Receivable 421 324
Allowance for Doubtful Accounts (31) (43)
Unbilled Electric and Gas Revenues 160 291
Fuel 471 494
Materials and Supplies, net of
valuation reserves - 2002, $2; 2001, $11 202 186
Prepayments 143 74
Energy Trading Contracts 717 419
Restricted Cash 14 12
Assets Held for Sale 22 422
Notes Receivable 108 --
Current Assets of Discontinued Operations 358 483
Other 48 25
-------- --------
Total Current Assets 3,411 3,540
-------- --------
PROPERTY, PLANT AND EQUIPMENT
Generation 5,646 4,690
Transmission and Distribution 9,409 9,500
Other 647 466
-------- --------
Total 15,702 14,656
Accumulated Depreciation and Amortization (5,107) (4,789)
-------- --------
Net Property, Plant and Equipment 10,595 9,867
-------- --------
NONCURRENT ASSETS
Regulatory Assets 5,049 5,247
Long-Term Investments, net of accumulated
amortization and Valuation
allowances -- 2002, $19; 2001, $30 4,926 4,811
Nuclear Decommissioning Trust Fund 768 817
Other Special Funds 403 222
Goodwill 464 569
Energy Trading Contracts 46 46
Other 292 311
-------- --------
Total Noncurrent Assets 11,948 12,023
-------- --------
TOTAL ASSETS $ 25,954 $ 25,430
======== ========
See Notes to Consolidated Financial Statements.
2
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND CAPITALIZATION
(Millions)
(Unaudited)
September 30, December 31,
2002 2001
------------- ------------
CURRENT LIABILITIES
Long-Term Debt Due Within One Year $ 742 $ 1,185
Commercial Paper and Loans 1,657 1,338
Accounts Payable 731 691
Energy Trading Contracts 665 561
Accrued Taxes 92 243
Current Liabilities of Discontinued
Operations 280 251
Other 727 535
-------- --------
Total Current Liabilities 4,894 4,804
-------- --------
NONCURRENT LIABILITIES
Deferred Income Taxes and
Investment Tax Credit (ITC) 3,089 3,205
Nuclear Decommissioning 768 817
Other Postemployment Benefit
(OPEB) Costs 493 476
Regulatory Liabilities 363 373
Cost of Removal 142 146
Environmental 140 140
Energy Trading Contracts 42 54
Other 489 327
-------- --------
Total Noncurrent Liabilities 5,526 5,538
-------- --------
COMMITMENTS AND CONTINGENT
LIABILITIES (See Note 6)
CAPITALIZATION
Long-Term Debt 6,902 6,437
Securitization Debt 2,259 2,351
Project Level, Non-Recourse Debt 1,481 1,403
-------- --------
Total Long-Term Debt 10,642 10,191
-------- --------
SUBSIDIARIES' PREFERRED SECURITIES
Preferred Stock Without
Mandatory Redemption 80 80
Participating Equity Preference
Securities 460 --
Guaranteed Preferred Beneficial
Interest in Subordinated Debentures 680 680
-------- --------
Total Subsidiaries' Preferred
Securities 1,220 760
-------- --------
COMMON STOCKHOLDERS' EQUITY
Common Stock, issued: 2002-233,432,138
shares, 2001-231,957,608
Shares; authorized: 2002 and
2001-500,000,000; outstanding: 3,590 3,599
2002-207,313,548, 2001-205,839,018
Treasury Stock, at cost: 2002 and
2001-26,118,590 shares (981) (981)
Retained Earnings 1,477 1,809
Accumulated Other Comprehensive Loss (414) (290)
-------- --------
Total Common Stockholders' Equity 3,672 4,137
-------- --------
Total Capitalization 15,534 15,088
-------- --------
TOTAL LIABILITIES AND CAPITALIZATION $ 25,954 $ 25,430
======== ========
See Notes to Consolidated Financial Statements.
3
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
(Unaudited)
For the Nine Months Ended
September 30,
-------------------------
2002 2001
---------- ----------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ -- $ 576
Adjustments to reconcile net income
to net cash flows from operating
activities:
Write-off of Argentine Investments 506 --
Loss on Disposal of Discontinued
Operations, net of tax 34 --
Cumulative Effect of a Change in
Accounting Principle, net of tax 120 (9)
Depreciation and Amortization 434 373
Amortization of Nuclear Fuel 68 76
Provision for Deferred Income Taxes
(Other than Leases) and ITC (197) (43)
Non-Cash Benefit Plan Charges 143 139
Leveraged Lease Income, Adjusted
for Rents Received 72 56
Undistributed Earnings from Affiliates (43) (60)
Foreign Currency Transaction
Loss (Gain) 71 --
Unrealized (Gains) Losses on Energy
Contracts and Other Derivatives (65) 5
Over Recovery of Electric Energy Costs
(BGS and NTC) and MTC 64 47
Under Recovery of Gas Costs (66) (145)
Other Non-Cash Charges (Credits) 46 (13)
Net Change in Certain Current Assets
and Liabilities (6) (62)
Benefit Plan Funding and
Related Payments (296) (155)
Proceeds from the Withdrawal of
Partnership Interests and
Investment Distributions 52 142
Other (79) 23
-------- --------
Net Cash Provided By Operating Activities 858 950
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and
Equipment (1,310) (1,678)
Investments in Joint Ventures, Partnerships
and Capital Leases (272) (567)
Proceeds from the Sale of Investments and
Return of Capital from Partnerships 123 4
Contributions to Nuclear Decommissioning
Trust Fund (25) (22)
Acquisitions, Net of Cash Provided (16) (532)
Other 44 (94)
-------- --------
Net Cash Used in Investing Activities (1,456) (2,889)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt 310 (2,021)
Issuance of Long-Term Debt 1,228 6,161
Issuance of Participating Units 460 --
Issuance of Common Stock 57 --
Deferred Issuance Costs (21) (240)
Redemptions of Long-Term Debt (1,124) (913)
Redemption of Preferred Securities -- (448)
Cash Dividends Paid on Common Stock (334) (337)
Other 4 7
-------- --------
Net Cash Provided By Financing Activities 580 2,209
-------- --------
Effect of Exchange Rate on Cash (2) (1)
-------- --------
Net Change in Cash and Cash Equivalents (20) 269
Cash and Cash Equivalents at Beginning
of Period 167 102
-------- --------
Cash and Cash Equivalents at End of Period $ 147 $ 371
======== ========
Income Taxes Paid $ 188 $ 131
Interest Paid $ 499 $ 556
Non-Cash Investing and Financing Activities
Fair Value of Property, Plant and
Equipment Acquired $ 34 $ 628
Debt Assumed from Companies Acquired $ -- $ 221
Reduction in Equity and Increase in Debt
from Issuance of Participating Units $ 54 $ --
See Notes to Consolidated Financial Statements.
4
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Note 1. Organization and Basis of Presentation
Organization
Unless the context otherwise indicates, all references to "PSEG," "we," "us" or
"our" herein means Public Service Enterprise Group Incorporated and its
consolidated subsidiaries. We are a New Jersey corporation that is an exempt
public utility holding company which has 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 and its gas supply portfolio
in May 2002, PSE&G continues to own and operate its transmission and
distribution business.
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). We also have a finance company subsidiary, PSEG Power
Capital Investment Co. (Power Capital), which provides certain financing for its
subsidiaries.
Energy Holdings has three principal direct wholly-owned subsidiaries; PSEG
Global Inc. (Global), a developer and operator of domestic and international
electric generation stations and distribution companies, PSEG Resources Inc.
(Resources), which makes passive investments primarily in energy industry
leveraged leases and PSEG Energy Technologies Inc. (Energy Technologies). See
Note 4. Discontinued Operations for a discussion of 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 from which Energy Holdings
is conducting a controlled exit. For a discussion of the formation of PSEG
Energy Holdings L.L.C. and PSEG Resources L.L.C. as the successors to Energy
Holdings and Resources, respectively, see Note 13. Subsequent Events.
Services provides management and administrative services to us and our
subsidiaries. These include accounting, legal, communications, human resources,
information technology, treasury and financial, investor relations, stockholder
services, real estate, insurance, risk management, tax, library and information
services, security, corporate secretarial and certain planning, budgeting and
forecasting services. Services charges us and our subsidiaries for work
performed and services provided by it.
Basis of Presentation
The financial statements included herein have been prepared pursuant to the
rules and regulations of the Securities and Exchange Commission (SEC) for Form
10-Q. Certain information and note disclosures normally included in financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted pursuant to such rules and regulations. However,
in the opinion of management, the disclosures herein are adequate to make the
information presented not misleading. These consolidated financial statements
and Notes to Consolidated Financial Statements (Notes) should be read in
conjunction with and update and supplement matters discussed in our 2001 Annual
Report on Form 10-K and our Amended Quarterly Report on Form 10-Q/A for the
quarter ended March 31, 2002 and our Quarterly Report on Form 10-Q for the
quarter ended June 30, 2002.
5
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
The unaudited financial information furnished herein reflects all adjustments
which are, in the opinion of management, necessary to fairly state the results
for the interim periods presented. All such adjustments are of a normal
recurring nature. The year-end consolidated balance sheets were derived from the
audited consolidated financial statements included in our 2001 Annual Report on
Form 10-K. Certain reclassifications of prior period data have been made to
conform with the current presentation.
Several factors impacting us in the quarter ended September 30, 2002 also impact
the presentation of our financial statements presented herein. In the third
quarter, we adopted Emerging Issues Task Force Issue No. 02-3, which requires
that we report energy trading revenues and energy trading costs on a net basis.
See Note 2. Recent Accounting Pronouncements. In addition, as a result of these
and other changes in our business, we also reevaluated our segment presentation
and have determined that Power operates in one integrated business segment. See
Note 9. Financial Information By Business Segment.
Under the Basic Generation Service (BGS) contract, which terminated on July 31,
2002, Power sold energy directly to PSE&G which in turn sold this energy to its
customers. These revenues were properly recognized on each company's stand-alone
financial statements and were eliminated when preparing our consolidated
financial statements. For the new BGS contract period beginning August 1, 2002,
Power sells energy to third party suppliers and other load serving entities
(LSEs) and PSE&G purchases the energy for its customers' needs from third party
suppliers. Due to this change in the BGS model, these revenues and expenses are
no longer intercompany revenues and expenses and are no longer eliminated in
consolidation.
Note 2. Recent Accounting Pronouncements
Statement of Financial Accounting Standards (SFAS) No. 142, "Goodwill and Other
Intangible Assets" (SFAS 142)
On January 1, 2002, we adopted SFAS 142. Under this standard, we were required
to complete an impairment analysis of goodwill during 2002 and record any
required impairment retroactive to the first quarter. Under SFAS 142, goodwill
is considered a nonamortizable asset and is subject to an annual review for
impairment and an interim review when certain events or changes in circumstances
occur. The effect of no longer amortizing goodwill on an annual basis was not
material to our financial position and results of operations upon adoption.
Under SFAS 142, we had a transitional period of six months from the date of
adoption to complete our goodwill impairment testing, which was completed as of
June 30, 2002. We evaluated the recoverability of the recorded amount of
goodwill based on certain operating and financial factors. Such impairment
testing included discounted cash flow tests which require broad assumptions and
significant judgment to be exercised by management. As a result, in the second
quarter of 2002 we recorded after-tax charges to reflect the goodwill impairment
of $120 million, retroactive to January 1, 2002, and such amount has been
recognized as a Cumulative Effect of a Change in Accounting Principle in
accordance with the new standard. See Goodwill Impairment Analysis in Note 3.
Asset Impairments for further details. In future periods, any goodwill
impairments will be recorded as a component of income from continuing
operations.
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
(SFAS 144)
On January 1, 2002 we adopted SFAS 144. On adoption, SFAS 144 did not have an
effect on our financial position or results of operations. Under SFAS 144,
long-lived assets to be disposed of are measured at the lower of carrying amount
or fair value less costs to sell, whether reported in continued operations or in
discontinued operations. Also under SFAS 144, discontinued operations are no
longer measured at net realizable value or include amounts for operating losses
that have not yet occurred. Under SFAS 144, discontinued operations are measured
at fair value, less costs to sell. For additional information see Note 3. Asset
Impairments and Note 4. Discontinued Operations.
6
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
SFAS No. 143, "Accounting for Asset Retirement Obligations" (SFAS 143)
In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS 143.
Under SFAS 143, the fair value of a liability for an asset retirement obligation
(ARO) is required to be recorded in the period in which it is incurred with an
offsetting amount recorded as an asset. Upon settlement of the liability, an
entity either settles the obligation for its recorded amount or incurs a gain or
loss. SFAS 143 is effective for fiscal years beginning after June 15, 2002.
In August 2002, PSE&G filed a petition requesting clarification from the New
Jersey Board of Public Utilities (BPU) regarding the future cost responsibility
for nuclear decommissioning and whether, as a matter of law and policy: (a)
PSE&G's customers will continue to pay for such costs through the Societal
Benefits Clause (SBC); or (b) such customer responsibility will terminate at the
end of the four-year transition period on July 31, 2003. The outcome of this
petition will affect the treatment of the liability recorded for Power's nuclear
decommissioning obligation. We cannot predict the outcome of this matter.
Upon adoption of the standard, we will be required to adjust our Nuclear
Decommissioning Liability ($768 million, pre-tax as of September 30, 2002) to
reflect the present value of our expected asset retirement obligation which we
believe is substantially lower than the recorded amount of our liability. If the
BPU determines that PSE&G's customers continue to pay for these costs, then the
difference between the recorded amount of the liability and the liability
calculated under the new ARO standard will be deferred on the balance sheet. If
the BPU determines that such customer responsibility terminates at the end of
the transition period, then the difference between the recorded amount of our
liability and the liability calculated under the new ARO standard will be
recorded as a one-time benefit as a Cumulative Effect of a Change in Accounting
Principle. The impact of adopting SFAS 143 is still being determined, and is
likely to be a material benefit to our results of operations and our financial
position by reducing our liability and increasing shareholders' equity.
In conjunction with the implementation of SFAS 143, we may change our method of
accounting for Cost of Removal for our Fossil Stations, which would
substantially reduce the Cost of Removal Liability that we have recorded for our
Fossil stations, $142 million, pre-tax as of September 30, 2002. We currently
believe that we will have no material legal retirement obligation under the new
standard for our Fossil stations, therefore the amount of that liability at the
time we adopt SFAS 143 will reverse into income.
Although the impact of this standard on future expenses is still being
determined, our present analyses indicate that ongoing depreciation and
operating expense (to accrete from the ARO liability, which is recorded at its
present value, to the ultimate liability) will approximate our current expected
expense levels over our five year planning horizon, and therefore would have a
minimal impact on earnings. However, under current GAAP we could experience
significant volatility in earnings since the Nuclear Decommissioning Trust
Fund's assets would be required to be marked to market with unrealized gains and
losses recognized in Other Comprehensive Income (OCI) and realized gains and
losses recognized through earnings. Previously, these gains and losses were
offset by changes in the Nuclear Decommissioning Liability with no effect on
earnings. We are currently considering various methods to mitigate this
volatility, including multiple financial products, although no assurances can be
given.
SFAS No. 145, "Rescission of FASB Statements Nos. 4, 44 and 64, Amendment of
FASB Statement No. 13, and Technical Corrections" (SFAS 145)
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 recorded pre-tax gains of
$4 million ($3 million after-tax) from the early retirement of debt as a
component of Other Income for the quarter and nine months ended September
7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
30, 2002. Also, 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 the nine months ended September 30, 2001 in accordance with SFAS 145.
SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal Activities"
(SFAS 146)
In June 2002, the FASB issued SFAS 146 which addresses the financial accounting
and reporting for costs associated with exit or disposal activities. SFAS 146
states that a liability for a cost associated with an exit or disposal activity
shall be recognized and measured initially at its fair value in the period when
the liability is incurred. A liability is established only when present
obligations to others are determined. SFAS 146 does not apply to costs
associated with the retirement of long-lived assets covered in SFAS 143. It
applies to costs associated with an exit activity that does not involve an
entity newly acquired in a business combination or with a disposal activity
covered by SFAS 144. We will apply SFAS 146 for exit or disposal activities
initiated after December 31, 2002 in accordance with the effective date of the
standard.
Emerging Issues Task Force (EITF) Issue No. 02-3, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities" (EITF 02-3)
In June 2002, the EITF addressed certain issues related to energy trading
activities, including gross versus net presentation in the statement of
operations and additional disclosure requirements for energy trading activities.
The EITF determined that gains and losses on energy trading contracts should be
shown net in the statement of operations. This change is applicable to financial
statements for periods ending after July 15, 2002 and requires that prior
periods be restated for comparability.
Pursuant to EITF Issue No. 99-19, "Reporting Revenue Gross as a Principal versus
Net as an Agent" (EITF 99-19), we had been recording our trading revenues and
trading related costs on a gross basis for physical energy and capacity sales
and purchases. In accordance with 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 $748 million and $636 million for the quarters ended September
30, 2002 and 2001, respectively and $1.5 billion and $1.7 billion for the nine
month periods ended September 30, 2002 and 2001, respectively. This change in
presentation did not have an effect on trading margins, net income or cash
flows.
In October 2002, the EITF reached a final consensus regarding the accounting for
contracts involved in energy trading and risk management activities. Management
does not yet know the impact of adopting this consensus on January 1, 2003.
Note 3. Asset Impairments
As of December 31, 2001, Energy Holdings' aggregate investment exposure in
Argentina was $632 million, including certain loss contingencies. These
investments included a 90% owned distribution company, Empresa Distribuidora de
Electricidad de Entre Rios S.A. (EDEERSA); minority interests in three
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); and two generating companies, Central Termica San Nicolas
(CTSN), and Parana which are under contract for sale to certain subsidiaries of
The AES Corporation (AES). In June 2002, Energy Holdings determined that the
carrying value of its Argentine investments was impaired. The combination of the
year-to-date operating losses, goodwill impairment at EDEERSA, write-down of
$506 million for all Argentine assets, and certain loss contingencies resulted
in a pre-tax charge to earnings of $632 million ($410 million after-tax) for the
nine months ended September 30, 2002. In connection with the write-down of
Energy Holding's Argentine assets, we recorded a deferred tax asset of $222
million. We believe that we will have sufficient future capital gains to realize
8
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
this deferred tax asset. For a discussion of certain contingencies related to
our Argentine investments, see Note 6. Commitments and Contingent Liabilities.
The tables below provide pre-tax and after-tax impacts of the various impairment
charges, results of operations and accruals of loss contingencies recorded with
respect to Energy Holdings' investments in Argentina for the three and nine
month periods ended September 30, 2002 and September 30, 2001.
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2002 2001 2002 2001
------- ------- ------- -------
(Millions)
(Pre-Tax)
(Losses) Earnings Before
Local Taxes-EDEERSA ................ $ -- $ 6 $ (59) $ 11
Write-down of EDEERSA ................ -- -- (94) --
Write-down of Assets Held for
Sale to AES ........................ -- -- (412) --
Loss Contingencies and Other ......... -- -- (11) --
Goodwill Impairment-EDEERSA .......... -- -- (56) --
---- ----- ----- -----
Total ........................... $ -- $ 6 $(632) $ 11
---- ----- ----- -----
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2002 2001 2002 2001
------- ------- ------- -------
(Millions)
(After-Tax)
(Losses) Earnings-EDEERSA ............ $ -- $ 3 $ (40) $ 6
Write-down of EDEERSA ................ -- -- (61) --
Write-down of Assets Held
for Sale to AES .................... -- -- (268) --
Loss Contingencies and Other ......... -- -- (5) --
Goodwill Impairment-EDEERSA .......... -- -- (36) --
---- ----- ----- ------
Total ........................... $ -- $ 3 $(410) $ 6
---- ----- ----- ------
EDEERSA
Given the year-to-date and projected operating losses at EDEERSA and the
continued economic uncertainty in Argentina, Energy Holdings determined that it
was necessary to test these assets for impairment. Such impairment analysis was
completed as of June 30, 2002. As a result of this analysis, Energy Holdings
determined that these assets were completely impaired under SFAS 144. Energy
Holdings recorded total charges and losses of $213 million, pre-tax, related to
this investment for the nine months ended September 30, 2002. These pre-tax
charges consisted of goodwill impairment charges of $56 million, nine month
operating losses of $59 million, of which $45 million was recorded in the first
quarter of 2002, a complete asset impairment of $94 million pursuant to our SFAS
144 impairment analysis and loss contingencies and other items of $4 million.
The total after-tax charges and losses related to this investment were $139
million for the nine months ended September 30, 2002.
In addition, Energy Holdings has developed an exit strategy to dispose of its
equity interest in EDEERSA. This exit is expected to be complete by June 30,
2003 and Energy Holdings intends to operate EDEERSA while carrying out its exit
plans. However, due to uncertainties related to the timing and method of
disposal of the investment in EDEERSA, the impairment charges and results of
EDEERSA's operations will not be reported as a discontinued operation until
EDEERSA has been disposed of or a sale is probable. Global is currently in
discussions with potential acquirers of EDEERSA. During the second quarter of
2002, EDEERSA defaulted on its debt, which is nonrecourse to Global, Energy
Holdings and us.
9
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
As of January 1, 2002, goodwill related to Energy Holdings' investment in
EDEERSA was approximately $56 million and was included in Energy Holdings'
previously disclosed investment exposure. As part of the adoption of SFAS 142,
Energy Holdings has determined that this goodwill was impaired and all of the
goodwill has been written-down as a cumulative effect of a change in accounting
principle as of January 1, 2002 and is reflected in our Consolidated Statement
of Operations for the nine months ended September 30, 2002. See below, Goodwill
Impairment Analysis, for a further discussion of our goodwill analysis.
Energy Holdings' share of the (Losses) Earnings for EDEERSA are included in our
Consolidated Statement of Operations as indicated in the following table:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2002 2001 2002 2001*
--------------------------------------
(Millions)
Operating Revenues ..................... $ 10 $ 23 $ 29 $ 28
Operating Expenses ..................... 8 21 22 21
---- ---- ---- ----
Operating Income ....................... 2 2 7 7
Other Losses - Foreign Currency
Transaction Loss -- -- (68) --
Minority Interest and Other ............ (2) 4 2 4
---- ---- ---- ----
(Loss) Earnings before Taxes ......... $ -- $ 6 $(59) $ 11
==== ==== ==== ====
* Operating results for EDEERSA included $5 million of revenues
recorded in accordance with the equity method of accounting for the
six months ended June 30, 2001.
Stock Purchase Agreement
On August 24, 2001, Global entered into a Stock Purchase Agreement with AES to
sell its minority interests in EDEN, EDES, EDELAP, CTSN and Parana, to certain
subsidiaries of AES. In connection with the terms of the Stock Purchase
Agreement, Global has accrued interest and other receivables of $17 million
through February 6, 2002, which are direct obligations of AES and represent the
total remaining exposure associated with these investments on our Consolidated
Balance Sheets. On February 6, 2002, AES notified Global that it was terminating
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 the Stock Purchase Agreement. Global filed
suit in New York State Supreme Court for New York County against AES to enforce
its rights under the Stock Purchase Agreement. A settlement was reached in
October 2002 between the parties under which Global will transfer its shares of
EDEN, EDES, EDELAP, Parana and CTSN to AES. AES has paid Global $15 million,
plus interest under the settlement and has issued notes that would yield an
additional $15 million when the notes mature on various dates ending July 2003.
The litigation is stayed pending AES performance of settlement obligations.
Since AES disputed its obligation to close and Global could not predict the
outcome of the litigation, Global determined it was necessary to test these
assets for impairment. As a result of this analysis, it was determined that
these assets were fully impaired and we recorded a write-down in the amount of
$412 million (pre-tax) ($268 million after-tax) and loss contingencies and other
items of $7 million (pre-tax) ($4 million after-tax) for the nine months ended
September 30, 2002.
10
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
Goodwill Impairment Analysis
In the second quarter of 2002, we finalized our evaluation of the effect of SFAS
142 on the recorded amount of goodwill. The total amount of goodwill impairments
is $120 million, net of tax of $66 million and was comprised of $36 million
(after-tax) at EDEERSA, $34 million (after-tax) at Rio Grande Energia (RGE), a
Brazilian distribution company of which Global owns 32%, $32 million (after-tax)
at Energy Technologies and $18 million (after-tax) at Tanir Bavi Power Company
Private Ltd. (Tanir Bavi), a generating facility in India 74% owned by Global.
All of the goodwill related to these companies, other than RGE, was fully
impaired. As noted above, this impairment charge has been recorded as of January
1, 2002 as a Cumulative Effect of a Change in Accounting Principle and is
reflected in Consolidated Statement of Operations for the nine months ended
September 30, 2002. The $53 million of goodwill at Energy Technologies and the
$27 million of goodwill at Tanir Bavi, as of December 31, 2001 have been
reclassified into Current Assets of Discontinued Operations on our Consolidated
Balance Sheets. For further detail regarding the goodwill impairments at Energy
Technologies and Tanir Bavi, see Note 4. Discontinued Operations.
As of September 30, 2002, the remaining carrying value of goodwill was $464
million, of which $434 million was recorded in connection with Global's
acquisitions of Sociedad Austral de Electricidad S.A. (SAESA) and Empresa de
Electricidad de los Andes S.A. (Electroandes) in Chile and Peru in August and
December of 2001, respectively. For the year ended December 31, 2001, the
amortization expense related to goodwill was $3 million.
As of September 30, 2002, our pro-rata share of the remaining goodwill included
in equity method investees totaled $271 million. In accordance with generally
accepted accounting principles, such goodwill is not consolidated on our balance
sheet. Our share of the amortization expense related to such goodwill was $8
million for the year-ended December 31, 2001.
As of September 30, 2002 and December 31, 2001, our goodwill and pro-rata share
of goodwill in consolidated equity method projects was as follows:
As of
September 30, December 31,
2002 2001
---------------------------
Global (Millions)
SAESA(1) ........................................ $ 289 $ 315
EDEERSA(2) ...................................... -- 63
Electroandes(3) ................................. 145 164
Elektrocieplownia Chorzow Sp
Z o.o. (ELCHO) ................................ 6 6
Skawina CHP Plant (Skawina) ..................... 3 --
----- -----
Total Global .............................. 443 548
Power - Albany Steam Station ....................... 21 21
----- -----
Total Consolidated Goodwill ............... 464 569
----- -----
Global
RGE (4) ......................................... 56 142
Chilquinta Energia Finance Co. L.L.C
(Chilquinta) (5) .............................. 156 174
Luz del Sur S.A.A ............................... 34 34
Kalaeloa ........................................ 25 25
----- -----
Pro-Rata Share of Equity
Investment Goodwill ......................... 271 375
----- -----
Total Goodwill ............................ $ 735 $ 944
===== =====
(1) The decrease at SAESA relates to final purchase price adjustments that
resulted in higher value allocated to deferred tax assets.
(2) The decrease at EDEERSA relates to an impairment of $56 million under SFAS
142 and to purchase price adjustments of $7 million made subsequent to
December 31, 2001.
11
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
(3) The decrease at Electroandes relates to purchase price adjustments
made subsequent to December 31, 2001 which resulted in higher value
allocated to Property, Plant and Equipment.
(4) The decrease at RGE relates to an impairment under SFAS 142 totaling
$50 million and the devaluation of the Brazilian Real amounting to
$36 million.
(5) The decrease at Chilquinta relates to the devaluation of the Chilean
Peso.
Note 4. 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.
During the second quarter of 2002, Energy Holdings completed its impairment
testing of all recorded goodwill in accordance with guidance set forth in SFAS
142 including the goodwill associated with the 11 HVAC/mechanical operating
companies acquired by Energy Technologies. Such analysis indicated that the
entire $53 million of goodwill associated with the HVAC/mechanical companies was
impaired, which resulted in a $32 million (after-tax) charge (net of $21 million
in taxes). In accordance with SFAS 142, this charge was recorded as of January
1, 2002 as a Cumulative Effect of a Change in Accounting Principle and reflected
in our results of operations for the nine months ended September 30, 2002.
In June 2002, Energy Holdings adopted a plan to sell its interests in the
HVAC/mechanical operating companies. The sale of these companies is expected to
be completed by June 30, 2003. We have retained the services of an
investment-banking firm to market these companies to interested parties. The
HVAC/mechanical operating companies meet the criteria for classification as
components of discontinued operations and all prior periods have been
reclassified to conform to the current year's presentation.
In the second quarter of 2002, Energy Holdings initiated a process for the sale
of Energy Technologies' DSM investments, which we had expected to sell by June
30, 2003. Based on our assessments, we believe the fair market value of these
assets approximates their carrying value as of September 30, 2002 and no
reduction in the carrying amount is indicated. For the period ended June 30,
2002, Energy Technologies' DSM investments were classified as a component of
discontinued operations. In the third quarter of 2002, Energy Holdings decided
to continue to own the DSM investments. For the period ended September 30, 2002,
all DSM investments were reclassified from discontinued operations to continuing
operations and the consolidated statements for all periods presented have been
restated to reflect this reclassification.
In addition to the goodwill impairment, Energy Holdings has further reduced the
carrying value of the investments in the 11 HVAC/mechanical operating companies
to their fair value less costs to sell, and recorded a loss on disposal for the
six months ended June 30, 2002 of $20 million, net of $11 million in taxes. As
of September 30, 2002, the carrying value of the HVAC/mechanical operating
companies approximates the fair value and accordingly no additional reduction in
the carrying value was required for the three months ended September 30, 2002.
Energy Holdings' remaining investment position in Energy Technologies is
approximately $110 million, of which approximately $32 million relates to
deferred tax assets from discontinued operations, for which no valuation
allowance is deemed necessary. Excluding the deferred tax assets from
discontinued operations, approximately $40 million of our remaining investment
balance relates to the asset management group. Although we believe that we will
be able to sell the HVAC/mechanical companies, we can give no assurances that we
will be able to realize their total carrying values.
12
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
Operating results of Energy Technologies' HVAC/mechanical operating companies,
less certain allocated costs from Energy Holdings, have been reclassified into
discontinued operations in our Consolidated Statements of Operations. The
results of operations of these discontinued operations for the quarter and nine
months ended September 30, 2002, yielded additional losses of $3 million
(after-tax) and $12 million (after-tax), respectively, and are disclosed below:
Quarter Ended Nine Months Ended
September 30, September 30,
--------------- -------------------
2002 2001 2002 2001
------ ------ ------ ------
(Millions)
Operating Revenues .......... $ 107 $ 127 $ 292 $ 328
Pre-Tax Operating Loss ...... (5) (5) (18) (25)
Loss Before Income Taxes .... (5) (6) (19) (29)
The carrying amounts of the assets and liabilities of Energy Technologies'
HVAC/mechanical operating companies, as of September 30, 2002 and December 31,
2001, have been reclassified into Current Assets of Discontinued Operations and
Current Liabilities of Discontinued Operations, respectively, on our
Consolidated Balance Sheets and are summarized in the following table:
September 30, December 31,
2002 2001
------------- ------------
(Millions)
Current Assets ..................................... $ 94 $ 152
Net Property, Plant and Equipment .................. 16 8
Noncurrent Assets .................................. 14 70
----- -----
Total Assets ..................................... $ 124 $ 230
===== =====
Current Liabilities ................................ $ 84 $ 76
Noncurrent Liabilities ............................. 3 2
Long-Term Debt ..................................... 5 1
----- -----
Total Liabilities ................................ $ 92 $ 79
===== =====
Tanir Bavi
At 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 June 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 prior periods have been
reclassified to conform to the current year's presentation. 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 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).
For information regarding goodwill impairment associated with Tanir Bavi, see
Note 2. Recent Accounting Pronouncements and Note 3. Asset Impairments.
13
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
The carrying amounts of the assets and liabilities of Tanir Bavi, as of
September 30, 2002 and 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
September 30, 2002 and December 31, 2001, are summarized in the following
tables:
September 30, December 31,
2002 2001
------------- ------------
(Millions)
Current Assets ..................................... $ 34 $ 36
Net Property, Plant and Equipment .................. 183 190
Noncurrent Assets .................................. 17 27
----- -----
TOTAL ASSETS ................................... $ 234 $ 253
===== =====
Current Liabilities ................................ 52 45
Noncurrent Liabilities ............................. 19 19
Long-Term Debt ..................................... 117 108
----- -----
TOTAL LIABILITIES .............................. $ 188 $ 172
===== =====
Note 5. Regulatory Assets and Liabilities
At September 30, 2002 and December 31, 2001, respectively, PSE&G had deferred
the following regulatory assets and liabilities on the Consolidated Balance
Sheets:
----------------------------
September 30, December 31,
2002 2001
------------- ------------
(Millions)
Regulatory Assets
Stranded Costs To Be Recovered .................... $ 3,936 $ 4,105
SFAS 109 Income Taxes ............................. 318 302
Other Postretirement Benefit
Plan (OPEB) Costs ............................... 198 212
Societal Benefits Charges (SBC) ................... -- 4
Manufactured Gas Plant
Remediation Costs ............................... 87 87
Unamortized Loss on Reacquired
Debt and Debt Expense ........................... 88 92
Under Recovered Gas Costs ......................... 182 120
Unrealized Losses on Gas Contracts ................ -- 137
Unrealized Losses on Interest Rate Swap ........... 65 18
Repair Allowance Taxes ............................ 93 84
Decontamination and Decommissioning Costs ......... 25 25
Plant and Regulatory Study Costs .................. 27 31
Regulatory Restructuring Costs .................... 27 27
Other ............................................. 3 3
------- -------
Total Regulatory Assets ..................... $ 5,049 $ 5,247
======= =======
Regulatory Liabilities
Excess Depreciation Reserve ....................... $ 208 $ 319
Over Recovered Electric Energy
Costs (BGS and NTC) ............................. 96 48
SBC ............................................... 47 --
Other ............................................. 12 6
------- -------
Total Regulatory Liabilities ................ $ 363 $ 373
======= =======
14
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
Note 6. Commitments and Contingent Liabilities
We, our consolidated subsidiaries and our equity method investees are involved
in various legal actions arising in the normal course of business. We do not
expect that there will be a material adverse effect on our financial condition,
results of operations and net cash flows as a result of these proceedings,
although no assurances can be given.
Guaranteed Obligations
Power
Power has guaranteed payment of obligations incurred under energy trading
contracts of its subsidiary, ER&T, with various counterparties up to established
dollar limits. The established dollar limits of those guarantees on behalf of
counterparties totaled approximately $1 billion at September 30, 2002. In
addition, Power has guaranteed payment of all amounts owed to PJM by ER&T
without a stated dollar limit. The outstanding amount of exposure under those
guarantees totaled $166 million as of September 30, 2002 representing the amount
payable under these contracts and the net amount by which open contracts are
below market.
As of September 30, 2002, letters of credit issued by Power were outstanding in
the amount of approximately $73 million in support of various contractual
obligations of its subsidiaries.
In addition, certain International Swap Dealer Agreements (ISDA) and other
supply contracts contain margin requirements that, as of September 30, 2002,
could require Power to post collateral of approximately $270 million if our
credit ratings are downgraded below investment grade.
Energy Holdings
Energy Holdings and/or Global have guaranteed certain obligations of Global's
subsidiaries or affiliates, including the successful completion, performance or
other obligations related to certain projects in an aggregate amount of
approximately $244 million as of September 30, 2002. The guarantees consist of a
$61 million equity commitment for ELCHO in Poland, $55 million of support for
Skawina in Poland, $56 million of various guarantees for Dhofar Power Company in
Oman, a $25 million guarantee related to bond payment obligations of Chilquinta
Energia Finance Co. LLC in connection with electric distribution companies in
Chile and Peru and various other guarantees comprising the remaining $47
million. A substantial portion of such guarantees is cancelled upon successful
completion, performance and/or refinancing of construction debt with
non-recourse project debt. Any downward revision in the current ratings of
Energy Holdings' Senior Notes would require the issuance of letters of credit to
replace the existing guarantee of $61 million for ELCHO and $25 million for
Chilquinta.
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. Tangible equity is defined as net equity less goodwill. As of September
30, 2002, Energy Technologies' tangible equity was $105 million. Energy Holdings
is in the process of negotiating alternate support arrangements with bond
issuers, including an indemnification agreement, which is likely to be executed
in the near future. As of September 30, 2002, Energy Technologies had $220
million of such bonds outstanding, of which $46 million was at risk in ongoing
construction projects. Energy Holdings expects to reduce this amount over time
as part of its exit from this business. The performance bonds are not included
in the $244 million of guaranteed obligations, discussed above. No assurances
can be given that Energy Holdings will be successful in extinguishing these
obligations.
SAESA has guaranteed its share of a $35 million debt obligation for a 50% owned
affiliate in Argentina, Edersa. This obligation was recorded on our Consolidated
Balance Sheets as it was considered in the valuation of SAESA at the date of
purchase in August 2001. Global may be required to make a $35 million equity
contribution to SAESA to repay the obligation. Since this obligation has been
previously recorded, there will be no impact to our Consolidated Statement of
Operations if the transaction is funded. For further discussion of this loan,
see Energy Holdings - Global - Chile.
15
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
Defaults in non-recourse project finance debt agreements do not cross-default to
any of our or Energy Holdings' other credit agreements. In June 2002, the
Administrative Agent for the EDELAP project loan notified Global that the loan
was in default and Global paid $2 million in sponsor guarantees that were due.
This amount is included in the $632 million of Argentine investment exposure
that was impaired and recorded in the Consolidated Statement of Operations. The
Parana project loan is in default. Although a waiver has been negotiated, it
expired in May 2002 and lenders have taken no further action. See Note 3. Asset
Impairments.
Environmental
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 the
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, Power and predecessor companies own or owned and/or operate 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 our financial position, results of operations or net cash flows.
PSE&G Manufactured Gas Plant Remediation Program
PSE&G is currently working with the NJDEP under a program (Remediation Program)
to assess, investigate and, if necessary, remediate environmental conditions at
PSE&G's former manufactured gas plant (MGP) 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.
At September 30, 2002 and 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 United States Environmental Protection Agency (EPA) has determined that a
stretch of the Passaic River in the area of Newark, New Jersey is a "facility"
within the meaning of that term under the Federal Comprehensive Environmental
Response, Compensation and Liability Act of 1980 and that, to date, at least
thirteen corporations, including us, may be potentially liable for performing
required remedial actions to address potential environmental pollution in the
Passaic River "facility."
In a separate matter, we and certain of our predecessors conducted industrial
operations at properties within the Passaic River facility. The operations
included one operating electric generating station, one former generating
station, and four former MGPs. Our costs to clean up former MGPs are recoverable
from utility customers under the SBC. We have contracted to sell the site of the
former generating site, contingent upon approval by state regulatory agencies,
to a third party that would release and indemnify us for claims arising out of
the site. We cannot predict what action, if any, the EPA or any third party may
take against us with respect to this matter, or in such event, what costs we may
incur to address any such claims. However, such costs may be material.
16
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
Prevention of Significant Deterioration (PSD)/New Source Review (NSR)
In January 2002, Power reached an agreement with the state and the federal
government to resolve allegations of noncompliance with federal and state NSR
regulations. Under that agreement, Power will install advanced air pollution
controls over 12 years that are expected to significantly reduce emissions of
nitrogen oxides (NOx), sulfur dioxide (SO2) particulate matter, and mercury from
its Hudson and Mercer coal burning units. The estimated cost of the program is
$355 million and such costs, when incurred, will be capitalized as plant
additions.
Power
New Generation and Development
Power has revised its schedules for completion of several of its projects under
development to provide better sequencing of its construction program with
anticipated market demand. This delay will allow Power to conserve capital in
2003 and allow it to take advantage of the expected recovery of the electric
markets and their need for capacity in 2005.
PSEG Power New York Inc., an indirect, wholly-owned subsidiary of Power, is
developing the Bethlehem Energy Center, a 763 MW combined-cycle power plant that
will replace the 380 MW Albany, NY Steam Station. Total costs for this project
are expected to be approximately $465 million with expenditures to date of
approximately $114 million. Construction began in 2002 with the expected
completion date in 2005, at which time the existing station will be retired.
Power is constructing a 1,218 MW combined cycle generation plant at Linden, New
Jersey with costs estimated at approximately $694 million and expenditures to
date of approximately $520 million. Completion is expected in 2005, at which
time 451 MW of existing generating capacity will be retired.
Power is constructing through indirect, wholly-owned subsidiaries, two natural
gas-fired combined cycle electric generation plants in Waterford, Ohio (821 MW)
and Lawrenceburg, Indiana (1,096 MW) at an estimated aggregate total cost of
$1.2 billion. Total expenditures to date on these projects have been
approximately $1.1 billion. The required estimated equity investment in these
projects is approximately $400 million, with the remainder being financed with
non-recourse bank financing. As of September 30, 2002, approximately $247
million of equity has been invested in these projects. 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. The agreement may
expire if the current financing is repaid within five years. Additional equity
contributions may be required by Power to the project company if the purchase
price of electricity under this contract, which will be determined prior to
commercial operations, results in revenues that are less than the required
payments under the bank financing. Based on current market prices, it is
anticipated that additional equity contributions will be required. The Waterford
facility is currently scheduled to achieve commercial operation in June 2003.
The Lawrenceburg facility is currently scheduled to achieve commercial operation
in December 2003.
Power has entered into an agreement to purchase Wisvest-Connecticut LLC, which
holds two electric generating stations in Connecticut, at a cost of $220
million. The agreement also calls for purchase price adjustments of up to $20
million for various expenditures made prior to closing, as well as closing
adjustments for fuel and inventory. The coal, oil, and gas-fired plants have a
total capacity of 1,019 MW. The transaction is subject to various Federal
approvals. The transfer of the two stations triggered the Connecticut Transfer
Act, which requires the commencement of any necessary remedial activities within
three years of the transfer of the property. While the cost to comply with the
Transfer Act to clean up former petroleum coke operations at one of the stations
is still unknown, estimated costs are between $10 million and $20 million. No
assurances can be given as to the ultimate remediation costs at these
facilities, however they could be material. Power expects to close on this
acquisition in the fourth quarter of 2002, subsequent to Federal Energy
Regulatory Commission (FERC) approval and Power's performance based testing of
the units.
17
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
Power also has contracts with outside parties to purchase upgraded turbines for
the Salem Nuclear Generating Station Units 1 and 2 and to purchase upgraded
turbines and to purchase a power uprate for Hope Creek Generating Station to
increase its generating capacity. The contracts are subject to nuclear
regulatory approval and are currently scheduled to be completed by 2004 for
Salem Unit 1 and Hope Creek and 2006 for Salem Unit 2. Power's aggregate
estimated costs for these projects are $210 million.
Power has commitments to purchase gas turbines and/or other services to meet its
current plans to develop additional generating capacity. The aggregate amount
due under these commitments is approximately $480 million, approximately $370
million of which is included in estimated costs for the projects discussed
above. The approximate $110 million remaining relates to obligations to purchase
hardware and services that have not been designated to any specific projects. If
Power does not contract to satisfy its commitment relating to the $110 million
in obligations by July 2003, it will be subject to penalties of up to $24
million.
Minimum Fuel Purchase Requirements
Power has several long-term purchase contracts with uranium suppliers,
converters, enrichers and fabricators to meet the currently projected fuel
requirements for Salem and Hope Creek. Power's remaining minimum purchase
requirement for 2002 under these contracts is approximately $20 million. On
average, Power has various multi-year requirements-based purchase commitments
that total approximately $100 million per year to meet Salem-Hope Creek fuel
needs. Power has been advised by Exelon that it has similar purchase contracts
to satisfy the fuel requirements of Peach Bottom.
Power uses coal for its fossil fueled electric generation stations. Power
purchases coal through various contracts and in the spot market. The total
minimum purchase requirements included in these contracts amount to
approximately $72 million through 2003.
Nuclear Fuel Disposal
Under the Nuclear Waste Policy Act of 1982 (NWPA), as amended, the Federal
government has entered into contracts with the operators of nuclear power plants
for transportation and ultimate disposal of the spent fuel. To pay for this
service, the nuclear plant owners were required to contribute to a Nuclear Waste
Fund at a rate of one mil per kWh of nuclear generation, subject to such
escalation as may be required to assure full cost recovery by the Federal
government. These costs were being recovered through the BGS contract through
July 2002. Payments made to the United States Department of Energy (DOE) for
disposal costs are based on nuclear generation and are included in Energy Costs
in the Consolidated Statements of Operations.
Under the NWPA, the DOE was required to begin taking possession of the spent
nuclear fuel by no later than 1998. The DOE has announced that it does not
expect a facility to be available earlier than 2010. Exelon has advised us that
it had signed an agreement with the DOE applicable to Peach Bottom under which
Exelon would be reimbursed for costs resulting from the DOE's delay in accepting
spent nuclear fuel. The agreement allows Exelon to reduce the charges paid to
the Nuclear Waste Fund to reflect costs reasonably incurred due to the DOE's
delay. Past and future expenditures associated with Peach Bottom's recently
completed on-site dry storage facility would be eligible for this reduction in
future DOE fees. Under this agreement, our portion of Peach Bottom's Nuclear
Waste Fund fees have been reduced by approximately $18 million through August
2002 at which point the credits were fully utilized and covered the cost of
Exelon's storage facility. For additional information, see Note 2. Recent
Accounting Pronouncements.
In 2000, a group of eight utilities filed a petition against DOE in the U.S.
Court of Appeals for the Eleventh Circuit, seeking to set aside the receipt of
credits by Exelon out of the Nuclear Waste Fund as stipulated in the Peach
Bottom agreement. On September 24, 2002 the U.S. Court of Appeals for the
Eleventh Circuit, issued an opinion upholding the challenge by the petitioners
regarding the settlement agreement's compensation provisions. Under the terms of
18
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
the agreement, DOE and Exelon Generation are required to meet and discuss
alternative funding sources for the settlement credits. The agreement provides
that if such negotiations are unsuccessful, the agreement will be null and void.
Any payments required by Power resulting from a disallowance of the previously
reduced fees would be included in Energy Costs in the Consolidated Statements of
Operations.
In February 2002, President Bush announced that Yucca Mountain in Nevada would
be the permanent disposal facility for nuclear wastes. On April 8, 2002, the
Governor of Nevada submitted his veto to the sitting decision. On July 9, 2002,
Congress affirmed the President's decision. The DOE must still license and
construct the facility. No assurances can be given as to the final outcome of
this matter.
Energy Holdings
Global
Argentina
Global has certain obligations that are likely to occur if certain projects in
Argentina continue to default on their debt and performance obligations. The
estimated amount to cover this exposure is $7 million and has been recorded as a
component of general and administrative operating expenses.
Under certain circumstances, Global could be obligated to settle its share
(approximately $26 million) of a project loan for EDELAP should it or the
majority owner of the project, take certain actions including forcing or
permitting certain loan parties to declare bankruptcy. In addition, the
guarantee can be triggered by transferring the shares of certain loan parties
without lender consent. Breach of this transfer covenant can be cured by
delivering certain pledge agreements relating to the ownership of loan parties
to the lenders. Global could also be liable for any incremental direct damages
arising from the breach of these covenants. Given the likely cure of any breach
by the project sponsors, such a contingent obligation has a low probability of
being triggered, and therefore no provision has been made in our Consolidated
Financial Statements.
California
In May 2001, GWF Energy LLC (GWF Energy), a joint venture between Global and
Harbinger GWF LLC entered into a 10-year power purchase agreement (PPA) with the
California Department of Water Resources (CDWR) to provide approximately 340 MW
of electric capacity to California from three new natural gas-fired peaking
plants, the Hanford, Henrietta and Tracy Peaker Plants.
On August 22, 2002, negotiations between GWF Energy and the Public Utilities
Commission of the State of California (CPUC) and the State of California
Electricity Oversight Board (collectively the California Parties) relating to
complaints filed with FERC under Section 206 of the Federal Power Act resulted
in the execution of (i) an amended and restated PPA that has been affirmed by
the CPUC as "just and reasonable" and (ii) a settlement agreement with the
California Parties, the Governor of the State of California and the People of
California by and through the Attorney General. In addition, the California
Parties withdrew with prejudice their FERC complaints against GWF Energy.
The Hanford and Henrietta Peaker Plants were completed in August 2001 and in
June 2002, respectively, and the Tracy Peaker Plant, a 166 MW facility, is now
under construction. The commercial operations date deadline of the Tracy Peaker
Plant has been extended to July 1, 2003 under the amended and restated PPA
discussed above. Total project cost for these plants is estimated at
19
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
approximately $345 million. Global's permanent equity investment in these
plants, including contingencies, is not expected to exceed $150 million after
completion of project financing, which is currently expected to occur in the
first quarter of 2003. In the event financing does not occur, our ownership
interest in these plants could increase to approximately 85% of the total
project costs, noted above. Our current ownership interest in this project was
74% as of September 30, 2002. For a description of turbine loans and working
capital loans from Global to GWF Energy pending completion of project financing,
see Note 12. Related-Party Transactions.
Chile
Global owns SAESA, a group of companies that consists of four distribution
companies and one transmission company that provide electric service to
customers in southern Chile. SAESA has a $150 million loan facility in place
that had an original maturity date of October 18, 2002 and is recorded as a
component of Commercial Paper and Loans on our Consolidated Balance Sheets as of
September 30, 2002. The principal payment was not made as scheduled and the
lending group has agreed not to declare any payment defaults or exercise any
remedies with regard to that loan before November 8, 2002. A term sheet for an
extension of the loan to April 2003 has been agreed to and is expected to be
finalized by November 8, 2002. We expect to refinance this loan facility during
this extended period. No assurances can be given that the extension will be
granted and that other refinancing options will be available in a timely manner.
Peru
In December 2001, Global acquired an interest in Electroandes, a 183 MW
hydroelectric facility in Peru. Part of the purchase price was financed with a
$100 million one year bridge loan maturing in December 2002. The loan facility
provides that the maturity date may be extended for six months if certain
conditions are met. No assurances can be given that the loan will be extended.
India
Energy Holdings has a 20% interest in a 330 MW Naphtha/natural gas fired plant
(PPN) in the Indian state of Tamil Nadu. Energy Holdings' investment exposure in
this facility is approximately $44 million. Power from the facility is sold
under a long-term power purchase agreement with the Tamil Nadu Electricity Board
(TNEB) which sells the power to retail end user customers. The TNEB has not been
able to make full payment to the plant for the purchase of energy under contract
due to its overall poor liquidity situation. The current past due receivable at
the project company is approximately $55 million, our share of which is
approximately $11 million.
Poland
In June 2002, Global completed its acquisition of a 35% interest in the 590 MW
(electric) and 618 MW (thermal) coal-fired Skawina CHP Plant (Skawina), located
in Poland and in June 2002 increased its ownership interest to approximately
50%. The transaction includes the obligation to purchase additional shares in
2004 that will bring Global's aggregate interest in Skawina to approximately
75%. Skawina supplies electricity to three local distribution companies and heat
mainly to the city of Krakow, under annual one-year contracts. The sale is part
of the Polish Government's energy privatization program. Global has expended $31
million during 2002 for its approximately 50% ownership interest and the total
equity investment is expected to be approximately $44 million.
Tunisia
Global owns a 60% interest in Carthage Power Company (CPC), a 471 MW gas-fired
combined-cycle electric generation facility located in Rades, Tunisia. CPC has
entered into a 20-year power purchase contract for the sale of 100% of the
20
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
output to Societe Tunisienne de l' Electricite et du Gaz (STEG). The contract
called for the plant to be operational by November 24, 2001, however, due to
delays in construction, this deadline was not met. STEG has declared that it is
entitled to liquidated damages at the rate of $67 thousand a day since November
24, 2001 in accordance with the terms of the power purchase contract. CPC is
contesting STEG's claim and the two parties are currently under negotiation to
settle this dispute. The facility was built by Alstom Centrales Energetiques SA,
(Alstom) an independent contractor, who was also obligated to complete
construction by September 3, 2001. CPC believes it is entitled to liquidated
damages from Alstom in amounts greater than the claims by STEG. Such liquidated
damages are secured by letters of credit totaling $30 million.
21
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
Note 7. 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 our results of operations and financial condition. 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 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.
Energy Trading Contracts
Power maintains a strategy of entering into trading positions to optimize the
value of its portfolio of generation assets and its electric and gas supply
obligations. Power does not engage in the practice of simultaneous trading for
the purpose of increasing trading volume or revenue. Power engages in physical
and financial transactions in the electricity wholesale markets and executes an
overall risk management strategy to mitigate the effects of adverse movements in
the fuel and electricity markets. Power actively trades energy and
energy-related products, including electricity, natural gas, electric capacity,
fixed transmission rights, coal and emission allowances, in the spot, forward
and futures markets, primarily in Pennsylvania-New Jersey-Maryland Power Pool
(PJM), and electricity in the Super Region, which extends from Maine to the
Carolinas and the Atlantic Coast to Indiana and natural gas in the producing
region, the Henry Hub Basin, as well as the Super Region. These contracts also
involve financial transactions including swaps, options and futures.
These contracts are recorded under Emerging Issues Task Force (EITF) 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" (EITF 98-10) which requires these contracts to be marked-to-market
with the resulting realized and unrealized gains and losses included in current
earnings. In prior periods Power disclosed gains and losses related to certain
activities within its trading segment. Commencing with Power's change in segment
reporting discussed in Note 9. Financial Information by Business Segments, we
have excluded certain transactions, such as firm transmission rights and Basic
Gas Supply Service (BGSS) results, from this table and solely report those gains
and losses on transactions accounted for pursuant to EITF 98-10. There was no
change in Power's margins, net income or cash flows as a result of this change
in presentation. Prior periods have been reclassified to conform to this
presentation.
For the three months and nine months ended September 30, 2002, Power recorded
net margins of $9 million and $36 million, respectively, as shown below:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- -------------------
2002 2001 2002 2001
-------- -------- -------- --------
(Millions)
Realized Gains ................ $ 17 $ 38 $ 16 $ 109
Unrealized Gains .............. (5) (4) 27 10
----- ----- ----- -----
Gross Margin ................ 12 34 43 119
----- ----- ----- -----
Broker Fees and Other
Trading-Related Expense ..... (3) (2) (7) (4)
----- ----- ----- -----
Net Margin .................. $ 9 $ 32 $ 36 $ 115
===== ===== ===== =====
22
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
As of September 30, 2002 and December 31, 2001, substantially all of these
contracts had terms of two years or less and were valued through market
exchanges and, where necessary, broker quotes. The fair values of the financial
instruments related to these contracts are summarized in the following table:
September 30, 2002 December 31, 2001
-------------------------- ----------------------------
Notional Notional Fair Notional Notional Fair
(mWh) (MMBTU) Value (mWh) (MMBTU) Value
-------- -------- ----- -------- -------- -----
(Millions)
Listed Futures and Options .. -- 12 $ 2 -- 14 $ (1)
Physical forwards ........... 48 -- 4 35 -- (3)
Options-- OTC ............... 14 286 5 7 713 (19)
Swaps ....................... 5 2,152 9 6 970 19
Emission Allowances ......... -- -- 15 -- -- 8
-- ----- ---- -- ----- ----
Totals ................. 67 2,450 $ 35 48 1,697 $ 4
== ===== ==== == ===== ====
Power routinely enters into exchange-traded futures and options transactions for
electricity and natural gas as part of its operations. Generally,
exchange-traded futures contracts require deposit of margin cash, the amount of
which is subject to change based on market movement and in accordance with
exchange rules. The amount of the margin deposits as of September 30, 2002 was
approximately $9 million.
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, Power enters into forwards, futures, swaps
and options with approved counterparties to hedge its anticipated demand. These
contracts, in conjunction with owned electric generation capacity, are designed
to cover estimated wholesale electric customer commitments.
In February 2002, New Jersey conducted an auction to identify energy suppliers
for the BGS of the State's regulated distribution utilities for the one-year
period beginning on August 1, 2002. Power did not participate directly in the
auction but agreed to supply power to several of the direct bidders.
Subsequently, a portion of the contracts with those bidders was reassigned to
Power. Therefore, for a limited portion of the New Jersey retail load, Power
will be a direct supplier to one non-affiliated utility.
In order to hedge a portion of Power's forecasted energy purchases to meet its
electric supply requirements, Power entered into forward purchase contracts,
futures, options and swaps. Power has also forecasted the energy delivery from
its generating stations based on the forward price curve movement of energy and,
as a result, entered into swaps, options and futures transactions to hedge the
price of gas to meet its gas purchases requirements for generation. These
transactions qualified for hedge accounting treatment under SFAS No. 133
"Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). As of
September 30, 2002, the fair value of these hedges were $17 million with
offsetting charges to Other Comprehensive Income (OCI) of $10 million
(after-tax). These hedges will mature through 2003.
Also, prior to May 2002, PSE&G had entered into gas forwards, futures, options
and swaps to hedge its forecasted requirements for natural gas, which was
required under an agreement with the BPU in 2001. Effective with the transfer of
PSE&G's gas contracts to Power on May 1, 2002, Power also acquired all of the
derivatives entered into by PSE&G. Power accounts for these derivative
instruments pertaining to residential customers in a similar manner to PSE&G.
Gains or losses from these derivatives will be recovered from customers as part
of the monthly billing to PSE&G. Derivatives relating to commercial and
industrial customers will be accounted for in accordance with SFAS 133 where
appropriate. Gains or losses on these derivatives are deferred and reported as a
component of OCI. There were no ineffective hedges. The accumulated OCI will be
reclassified to earnings in the period in which the hedged transaction affects
earnings. As of September 30, 2002, Power had approximately 328 MMBTU of gas
forwards, futures, options and swaps to hedge forecasted requirements with a
fair value of approximately $7 million. As of December 31, 2001, PSE&G had
approximately 330 MMBTU of gas forwards, futures, options and swaps to hedge
forecasted requirements with a fair value of approximately $(137) million. The
maximum term of these contracts is approximately one year.
23
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
Power also enters into certain other contracts which are derivatives but do not
qualify for hedge accounting under SFAS 133, nor are they classified as energy
trading contracts under EITF 98-10. Most of these contracts are option contracts
on gas purchases for generation requirements that do not qualify for hedge
accounting. Therefore, the changes in fair market value of these derivative
contracts are recorded in the income statement at the end of each reporting
period. For the three and nine months ended September 30, 2002, Power recorded
gains (losses) on these contracts of $(6) million and $24 million, respectively,
as shown below:
For the Three Months Ended For the Nine Months Ended
September 30, September 30,
-------------------------- -------------------------
2002 2001 2002 2001
-------- -------- -------- --------
(Millions)
Realized (Losses) Gains ................... $ (7) $ 17 $ 1 $ 17
Unrealized (Losses) Gains ................. 1 (6) 23 (14)
---- ---- ---- ----
Gross Margin ............................ $ (6) $ 11 $ 24 $ 3
==== ==== ==== ====
As of September 30, 2002 and December 31, 2001, substantially all of these
contracts had terms of two years or less and were valued through market
exchanges and, where necessary, broker quotes. The fair values of the financial
instruments related to these contracts are summarized in the following table:
September 30, 2002 December 31, 2001
--------------------------------- --------------------------------
Notional Notional Fair Notional Notional Fair
(mWh) (MMBTU) Value (mWh) (MMBTU) Value
-------- -------- ----- -------- -------- -----
(Millions)
Listed Futures and Options ............ -- 32 $ 2 -- -- --
Options-- OTC ......................... -- 63 -- 1 148 $ (6)
Swaps ................................. -- 41 $ 14 -- 11 1
--- --- ---- --- --- ----
Totals ................................ -- 136 $ 16 1 159 $ (5)
=== === ==== === === ====
Interest Rates
We are subject to the risk of fluctuating interest rates in the normal course of
business. Our policy is to manage interest rate risk through the use of fixed
rate debt, floating rate debt, interest rate derivatives. As of September 30,
2002, a hypothetical 10% change in market interest rates would result in a
consolidated change of $12 million in annual interest costs related to
short-term and floating rate debt consisting of $2 million, $3 million, $3
million and $4 million at PSEG, PSE&G, Power and Energy Holdings, respectively.
We construct a hypothetical swap to mirror all the critical terms of the
underlying debt and utilize regression analysis to assess the effectiveness of
the actual swap at inception and on an ongoing basis. The assessment will be
done periodically to ensure the swaps continue to be effective. PSEG determines
the fair value of interest rate swaps through counterparty valuations, internal
valuations and the Bloomberg swap valuation function. There have been no
material changes in the techniques or models used in the valuation of interest
rate swaps during the periods presented. There is minimal impact of counterparty
credit risk on the fair value of the hedges since our policies require that our
counterparties have investment grade credit ratings.
We have entered into interest rate swaps to lock in fixed interest rates on
certain of our construction loans to hedge forecasted future interest payments.
We have elected to use the Hypothetical Derivative Method to measure
ineffectiveness of the hedges as described under Derivative Implementation Group
(DIG) Issue No. G7.
24
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
Ineffectiveness may occur if the actual draw down of the debt and the notional
amount of the swap during the construction phase are different. The amount of
ineffectiveness, if any, is recorded in earnings at the end of the reporting
period. The impact of ineffectiveness on net income should be minimal because
the interest rate swaps and the underlying debt are indexed to the same
benchmark interest rate. Therefore, interest rate fluctuations should be offset.
The amount of ineffectiveness, if any, is recorded in earnings at the end of the
reporting period.
The following table shows details of the interest rate swaps at PSEG, PSE&G,
Power and Energy Holdings and their associated values that were open at
September 30, 2002:
Accumulated
Total Other
Project Notional Fair Comprehensive
Ownership Amount Pay Receive Market Loss Maturity
Underlying Securities Percent (A) Rate Rate Value (B) Date
- -----------------------------------------------------------------------------------------------------------------------
(Millions of dollars, where applicable)
PSEG:
Enterprise Capital Trust II 100% $150.0 5.98% 3-month $(20.4) $12.1 2008
Securities LIBOR
PSE&G:
Transition Funding Bonds (Class 100% 497.0 6.29% 3-month (64.8) *** 2011
A-4)
LIBOR
Power:
Construction Loan - Waterford 100% 177.5 4.16% 3-month (8.6) 5.1 2005
LIBOR
Energy Holdings:
Construction Loan - Tunisia 60% 53.0 6.96% 6-month (7.0) 3.0 2009
(US$) LIBOR
Construction Loan - Tunisia 60% 67.0 5.19% 6-month (3.0) 2.0 2009
(EURO) EURIBOR*
Construction Loan - Poland 55% 141.0 8.40% 6-month (56.0) 19.0 2010
(US$) LIBOR
Construction Loan - Poland 55% 62.0 13.23% 6-month (34.0) 11.0 2010
(PLN) WIBOR**
Construction Loan - Oman 81% 121.0 6.27% 6-month (29.0) 15.0 2018
LIBOR
--------- ------- -----
Total Energy Holdings 444.0 (129.0) 50.0
--------- ------- -----
Total PSEG $1,268.50 $(222.8) $67.2
========= ======= =====
* EURIBOR - EURO Area Inter-Bank Offered Rate
** WIBOR - Warsaw Inter-Bank Offered Rate
*** Offsetting charges were recorded to Regulatory Asset/Liability.
(A) Represents 100% of Derivative Instrument.
(B) Net of Tax and Minority Interest.
- --------------------------------------------------------------------------------
Global holds investments in various generation facilities in the United States
that are accounted for under the equity method of accounting and, therefore, are
not consolidated in Global's financial statements. Global holds a 50% indirect
ownership in two investments located in Texas and a 50% direct ownership in one
investment in Hawaii (collectively the investees), which hold US Dollar
denominated debt with variable interest payments tied to LIBOR rates. In order
to lock in fixed interest rates on such debt, the investees each entered into
interest rate swaps to hedge the value of the cash flows of their future
interest payments. As of September 30, 2002, the aggregate notional balance of
these swaps was $307 million (Global's share was $154 million), the weighted
average fixed interest rate paid was 6.9%, and Global's share of the loss
position of these swaps was $15 million and is recorded as a reduction to
Long-Term Investments. These swaps were designated as hedges for accounting
purposes and, as a result, changes in the fair value of the hedge were recorded
in OCI.
The fair value of interest rate swaps, designated and effective as cash flow
hedges, are initially recorded in OCI. Reclassification of unrealized gains or
losses on cash flow hedges of variable-rate debt instruments from OCI into
earnings occurs as interest payments are accrued on the debt instrument and
generally offsets the change in the interest accrued on the underlying variable
25
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
rate debt. We estimate reclassifying $18 million of losses from cash flow
hedges, including our pro-rata share from our equity method investees, from OCI
to our Consolidated Statements of Operations over the next 12 months. As of
September 30, 2002, there was a $67 million balance remaining in the Accumulated
Other Comprehensive Loss account, as indicated in the table above. For the
quarter and nine months ended September 30, 2002, losses of $3 million and $9
million, respectively, were reclassified from OCI to our Consolidated Statements
of Operations. The ineffective portion of these interest rate swaps is recorded
in our Consolidated Statements of Operations. During the quarter and nine months
ended September 30, 2002, we recorded losses of less than $1 million,
respectively, after taxes and minority interests, due to the ineffectiveness of
such interest rate swaps.
Equity Securities
During the nine month period ended September 30, 2002, Resources recognized a
loss for investment where there is not a liquid market of approximately $26
million pre-tax, which is included in Operating Revenues. As of September 30,
2002, Resources had investments in leveraged buyout funds of approximately $91
million, of which $21 million was comprised of public securities with available
market prices and $70 million was comprised of non-publicly traded securities.
Comparably, as of December 31, 2001, Resources had investments in leveraged
buyout funds of approximately $130 million, of which $35 million was comprised
of public securities with available market prices and $95 million was comprised
of non-publicly traded securities.
Foreign Currencies
As of September 30, 2002, net foreign currency devaluations have reduced the
reported amount of our total Stockholder's Equity by $324 million, of which $212
million and $105 million were caused by the devaluation of the Brazilian Real
and the Chilean Peso, respectively. For the net foreign currency devaluations
for the quarter and nine months ended September 30, 2002 and 2001, see Note 10.
Comprehensive Income.
In May 2002, Energy Holdings purchased foreign currency call options in order to
hedge its average 2002 earnings denominated in Brazilian Reais and in Peruvian
Nuevo Sols for the remainder of 2002. As of September 30, 2002, there were three
call options outstanding on the Brazilian Real, one expiring in each month
through December 2002. The aggregate notional and fair values of these contracts
were approximately $4 million and $1 million, respectively, as of September 30,
2002. In addition, there were three call options outstanding on the Peruvian
Nuevo Sol, one expiring in each month through December 2002. The aggregate
notional value of these contracts was approximately $7 million as of September
30, 2002. The fair value of those options as of September 30, 2002 was
immaterial. These options are not considered hedges for accounting purposes
under SFAS 133 and, as a result, changes in their fair value are recorded
directly to earnings. Global recorded a gain of $1 million related to Brazilian
and Peruvian option contracts that expired during the third quarter of 2002.
The fair value of foreign currency derivatives, designated and effective as cash
flow hedges, are initially recorded in OCI. Reclassification of unrealized gains
or losses on cash flow hedges from OCI into earnings generally occurs when the
hedged transaction is recorded in earnings and generally offsets the change in
the value of the hedged item. We estimate reclassifying $1 million of foreign
exchange gains from foreign currency cash flow hedges, including our pro-rata
share from our equity method investees, from OCI to our Consolidated Statements
of Operations over the next 12 months. For the quarter and nine months ended
September 30, 2002, losses transferred from OCI to our Consolidated Statements
of Operations were less than $1 million.
26
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- 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 September 30, 2002 and December 31, 2001, respectively.
September 30, 2002 December 31, 2001
------------------- ----------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ----- -------- -----
(Millions)
Long-Term Debt:
PSEG ....................................................... $ -- $ -- $ 275 $ 275
Energy Holdings ............................................ 2,756 2,415 2,773 2,835
PSE&G ...................................................... 2,926 3,242 3,172 3,290
Transition Funding ......................................... 2,387 2,579 2,472 2,575
Power ...................................................... 3,315 3,387 2,685 2,836
Preferred Securities Subject to Mandatory Redemption:
Participating Equity Preference Securities ................. 460 441 -- --
Monthly Guaranteed Preferred Beneficial Interest in
PSE&G's Subordinated Debentures ......................... 60 61 60 60
Quarterly Guaranteed Preferred Beneficial Interest in
PSE&G's Subordinated Debentures ......................... 95 97 95 96
Quarterly Guaranteed Preferred Beneficial Interest in
PSEG's Subordinated Debentures .......................... 525 515 525 520
As of October 30, 2002, the fair value of the long-term debt for Power and
Energy Holdings had declined in value to an estimated fair value of $3.1 billion
and $2.1 billion, respectively. The capital markets have experienced a period of
unusual volitility, especially for the energy sector. While we cannot predict
when the markets will stabilize, we believe the current volatility yielding
discounted trading values for our debt will subside.
Participating Equity Units
In September 2002, we issued 9.2 million Participating Units with a stated
amount of $50 per unit. These securities are reflected as subsidiaries'
preferred securities on our Consolidated Balance Sheets. Each unit consists of a
6.25% trust preferred security due 2007 having a liquidation value of $50, and a
stock purchase contract obligating the purchasers to purchase shares of our
common stock in an amount equal to $50 on November 16, 2005. In exchange for the
obligations under the purchase contract, the purchasers will receive quarterly
contract adjustment payments at the annual rate of 4.00% until such date. The
number of new shares issued will depend upon the average closing price per share
of our common stock for the 20 consecutive trading days ending the third trading
day immediately preceding November 16, 2005. Based on the formula described in
the purchase contract, at that time we will issue between 11,429,139 and
13,714,967 shares of our common stock. Prior to such conversion, the securities
will be accounted for under the Treasury Stock method for purposes of
calculating fully diluted earnings per share. These securities will be dilutive
to earnings per share to the extent that the market price of our common stock
exceeds $40.248. The net proceeds from the sale of the Participating Units were
$446.2 million.
27
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
Note 8. Income Taxes
A tax expense has been recorded for the results of continuing operations. An
analysis of that provision expense is as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- --------------------
2002 2001 2002 2001
------ ------ ------- ------
(Millions)
Pre-Tax Income ................................................. $ 331 $ 224 $ 279 $ 875
Tax Computed at the Federal Statutory Rate at 35% .............. 116 78 98 306
Increases (decreases) from Federal statutory
rate attributable to:
State Income Taxes after Federal Benefit ................... 19 15 48 55
Rate Differential of Foreign Operations .................... (7) (5) (14) (26)
Plant Related Items ........................................ (3) (31) (11) (41)
Other ...................................................... (1) (8) (3) (3)
------------------------------------------------
Total Income Tax Expense ....................................... $ 124 $ 49 $ 118 $ 291
------------------------------------------------
Effective Income Tax Rate ................................ 37.5% 21.9% 42.3% 33.3%
The increase in the effective tax rate, for the quarter and nine months ended
September 30, 2002, as compared to the same periods for 2001, is primarily due
to 2001 adjustments as a result the 1994-1996 IRS audit upon filing our actual
tax return for the year 2000.
Note 9. Financial Information by Business Segment
Power's business has evolved during 2002. With the transfer of the BGSS (i.e.,
natural gas supply requirements contact) contract to Power and the commencement
of the new BGS Contracts 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, effective with this filing, 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.
28
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
Information related to the segments of our business is detailed below:
Energy
Power PSE&G Global Resources Technologies Other Consolidated
(A) (B) (C)
For the Three Months Ended --------------------------------------------------------------------------------------
September 30, 2002: (Millions)
Operating Revenues $ 1,092 $ 1,405 $ 145 $ 57 $ 10 $ (382) $ 2,327
Income Before Discontinued Operations 121 55 20 17 2 (8) 207
Loss From Discontinued Operations -- -- -- -- (3) -- (3)
Segment (Loss) Earnings $ 121 $ 55 $ 20 $ 17 $ (1) $ (8) $ 204
For the Three Months Ended
September 30, 2001:
Operating Revenues $ 685 $ 1,395 $ 101 $ 50 $ 8 $ (623) $ 1,616
Income Before Discontinued Operations 87 65 16 9 2 (4) 175
Income (Loss) From Discontinued
Operations -- -- 2 -- (5) -- (3)
Segment Earnings (Loss) $ 87 $ 65 $ 18 $ 9 $ (3) $ (4) $ 172
For the Nine Months Ended
September 30, 2002:
Operating Revenues $ 2,341 $ 4,294 $ 387 $ 135 $ 22 $ (1,489) $ 5,690
Income Before Discontinued Operations
and Cumulative Effect of a Change in
Accounting Principle 325 128 (302) 26 2 (18) 161
Loss From Discontinued Operations -- -- (9) -- (32) -- (41)
Cumulative Effect of a Change in
Accounting Principle -- -- (88) -- (32) -- (120)
Segment (Loss) Earnings $ 325 $ 128 $ (399) $ 26 $ (62) $ (18) $ --
For the Nine Months Ended
September 30, 2001:
Operating Revenues $ 1,919 $ 4,658 $ 226 $ 134 $ 20 $ (1,640) $ 5,317
Income Before Discontinued Operations
and Cumulative Effect of a Change in
Accounting Principle 292 204 66 27 4 (9) 584
Income (Loss) From Discontinued
Operations -- -- 2 -- (19) -- (17)
Cumulative Effect of a Change in
Accounting Principle -- -- 9 -- -- -- 9
Segment Earnings (Loss) $ 292 $ 204 $ 77 $ 27 $ (15) $ (9) $ 576
As of September 30, 2002:
Total Assets $ 6,977 $ 12,405 $ 3,893 $ 3,174 $ 206 $ (701) $ 25,954
As of December 31, 2001:
Total Assets $ 5,503 $ 12,963 $ 4,074 $ 3,026 $ 290 $ (426) $ 25,430
(A) For a discussion of the charge relating to Argentina, see Note 3. Asset
Impairments.
(B) For a discussion of the charges relating to Discontinued Operations at
Energy Technologies, see Note 3. Asset Impairments and Note 4.
Discontinued Operations.
29
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
(C) Our other activities include amounts applicable to PSEG (parent
corporation), Energy Holdings (parent corporation), Enterprise Group
Development Company (EGDC), and intercompany eliminations, including
transactions between Power and PSE&G relating to BGS, Market Transition
Charge (MTC) and BGSS which amounted to approximately $380 million and
$625 million for the quarters ended September 30, 2002 and 2001,
respectively and approximately $1.5 billion and $1.6 billion for the nine
months ended September 30, 2002 and 2001, respectively. The net losses
primarily relate to financing and certain administrative and general costs
at the parent corporations.
Our geographic information is disclosed below. The foreign assets and operations
noted below are solely related to Energy Holdings.
Revenues (1)
---------------------------------------------------------
Quarter Ended Nine Months Ended Identifiable Assets (2)
September 30, September 30, ------------------------------
------------------------ ----------------------- September 30, December 31,
2002 2001 2002 2001 2002 2001
------- ------- ------- ------- ------- -------
(Millions)
United States ................ $ 2,171 $ 1,517 $ 5,296 $ 5,119 $ 21,473 $ 20,666
Foreign Countries ............ 156 99 394 198 4,481 4,764
------- ------- ------- ------- -------- --------
Total ................... $ 2,327 $ 1,616 $ 5,690 $ 5,317 $ 25,954 $ 25,430
======= ======= ======= ======= ======== ========
Identifiable assets in foreign countries include:
Chile......................................... $ 878 $ 880
Netherlands................................... 961 911
Argentina..................................... -- 737
Peru ......................................... 566 520
Tunisia ...................................... 337 245
India (3)..................................... 306 288
Poland........................................ 329 166
Brazil........................................ 204 282
Other......................................... 900 735
------- -------
Total..................................... $ 4,481 $ 4,764
======= =======
(1) Revenues are attributed to countries based on the locations of the
investments.
(2) Assets are comprised of investment in corporate joint ventures and
partnerships that are accounted for under the equity method and companies
in which we have a controlling interest for which the assets are
consolidated on our financial statements. Amount is net of tax and foreign
currency translation adjustment of $360 million and $283 million as of
September 30, 2002 and December 31, 2001, respectively.
(3) Approximately $234 million and $253 million relates to Tanir Bavi, which
was discontinued as of September 30, 2002 and was sold in October 2002.
30
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
The table below reflects our investment exposure in Latin American countries,
through Global:
Investment Exposure Equity Exposure
---------------------------- -----------------------------
September 30, December 31, September 30, December 31,
2002 2001 2002 2001
------------- ------------ ------------- ------------
(Millions)
Argentina....... $ -- $ 632 $ -- $ 632
Brazil.......... 433 467 221 298
Chile........... 562 542 466 465
Peru............ 443 387 435 388
Venezuela....... 52 53 52 53
The investment exposure consists of our invested equity plus equity commitment
guarantees. Equity exposure is equal to our investment exposure net of foreign
currency translation adjustments, reflected in other comprehensive income.
Note 10. Comprehensive Income (Loss)
Comprehensive Income, Net of Tax:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2002 2001 2002 2001
------ ------ ------- ------
(Millions)
Net income ......................... $ 204 $ 172 $ -- $ 576
Foreign currency translation ....... (49) (37) (135) (75)
Reclassification adjustment
for foreign currency ............. -- -- 69 --
Cumulative effect of a change
in accounting principle .......... -- -- -- (15)
Net unrealized losses on
cash flow hedges ................. (27) (8) (63) (26)
Reclassification adjustments
into earnings .................... 3 -- 9 --
Other .............................. (1) -- (4) --
----- ----- ----- -----
Comprehensive income (Loss) ........ $ 130 $ 127 $(124) $ 460
===== ===== ===== =====
For further discussion of Other Comprehensive Income (Loss), See Note 7.
Financial Instruments, Energy Trading and Risk Management.
31
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Continued
Note 11. Other Income
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- -------------------
2002 2001 2002 2001
------ ------- ------ ------
(Millions)
Other Income
Interest Income................................. $ 4 $ 9 $ 13 $ 37
Gain on Disposition of Property................. -- 1 1 4
Change in Derivative Fair Value................. 13 -- 15 --
Income from Minority Interests.................. -- -- 2 --
Gain (Loss) on Early Retirement of Debt......... 4 -- 4 --
Other........................................... -- 2 3 1
---- --- ---- ----
Total Other Income.................................. $ 21 $ 12 $ 38 $ 42
==== ==== ==== ====
Note 12. Related Party Transactions
Loans to TIE
Global and its partner, Panda Energy International, Inc., through Texas
Independent Energy, L.P. (TIE), a 50/50 joint venture, owns and operates two
electric generation facilities in Texas. As of September 30, 2002 and December
31, 2001, Global's investments in the TIE partnership include $74 million and
$165 million, respectively, of loans that earn interest at an annual rate of 12%
that are expected to be repaid over the next 10 years. Cash payments are
currently being received from the projects for the full amount of interest on
such loans to TIE. However, only 50% of the interest income is recognized in
earnings, representative of the portion of the project not owned by Global.
Loans to GWF Energy
GWF Energy, a joint venture between Global and Harbinger GWF LLC is constructing
three new peaking plants. Global's permanent equity investment in GWF Energy's
plants, including contingencies, is not expected to exceed $150 million after
completion of project financing, which is currently expected to occur in the
first quarter of 2003. Pending completion of project financing, Global provided
GWF Energy approximately $98 million of secured loans to finance the purchase of
turbines. The turbine loans bear interest at rates ranging from 12% to 15% per
annum and are payable in installments beginning May 31, 2002, with final
maturity no later than December 31, 2002. As of September 30, 2002, the secured
loans to finance the purchase of turbines was $87 million. Global has also
provided GWF Energy up to $74 million of working capital loans to fund
construction costs pending completion of project financing. Such loans earn
interest at 20% per annum and are convertible into equity at Global's option.
During the third quarter of 2002, Global converted $55 million of such working
capital loans to equity, which increased Global's ownership of GWF Energy to
74%, and reduced the working capital loan balance to $19 million as of September
30, 2002. Since the partnership agreement stipulates that the condition for
control is ownership of 75% of the voting stock, our investment in GWF Energy is
recorded in accordance with the equity method. Harbinger GWF LLC has the right
to buy back from Global up to one-half of the reduction of its equity ownership
in GWF Energy from the 50% ownership level. Such right terminates at the earlier
of project financing or June 30, 2003. The loan structures were put in place to
provide Global with a preferential cash and earnings distribution from the
project similar to our subordinated loans for our Texas facility. For a
discussion of the commercial dates of operation and issues of the construction
process matters with respect to these three plants, see Note 6. Commitments and
Contingent Liabilities.
32
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED) -- Concluded
Note 13. Subsequent Events
PSEG Energy Holdings L.L.C.
PSEG Energy Holdings L.L.C., a New Jersey limited liability company, is the
successor to PSEG Energy Holdings Inc. pursuant to a merger which was
consummated in October 2002. The merger was consummated to change the form of
the business from a corporation to a limited liability company. PSEG Energy
Holdings L.L.C. succeeded to all the assets and liabilities of PSEG Energy
Holdings Inc. in accordance with the New Jersey Limited Liability Company Act.
PSEG Energy Holdings L.L.C. has succeeded to PSEG Energy Holdings' Inc.
reporting obligations under the Securities Exchange Act of 1934, as amended.
In connection with the PSEG Energy Holdings L.L.C. reorganization, PSEG
Resources Inc. became a wholly owned subsidiary of PSEG Resources L.L.C., a
newly formed New Jersey limited liability company. PSEG Resources L.L.C. is
wholly owned by PSEG Energy Holdings L.L.C. This reorganization is expected to
have a positive impact on earnings in future periods.
Private Placement
In October 2002, we closed on a $245 million private placement debt transaction
with a five-year average life, with the proceeds being used to reduce short-term
debt.
33
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Following are the significant changes in or additions to information reported in
our Annual Report on Form 10-K for the year ended December 31, 2001. Amended
Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2002 and
Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 affecting our
consolidated financial condition and the results of operations. This discussion
refers to our Consolidated Financial Statements (Statements) and related Notes
to Consolidated Financial Statements (Notes) and should be read in conjunction
with such Statements and Notes.
Corporate Structure
Unless the context otherwise indicates, all references to "PSEG," "we," "us" or
"our" herein means Public Service Enterprise Group Incorporated and its
consolidated subsidiaries. We are a New Jersey corporation that is an exempt
public utility holding company which has four principal direct wholly-owned
subsidiaries: Public Service Electric and Gas Company (PSE&G), PSEG Power LLC
(Power), PSEG Energy Holdings LLC (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 and its gas supply portfolio
in May 2002, PSE&G continues to own and operate its transmission and
distribution business.
Power is an independent, wholesale energy supply company that has three
principal direct wholly-owned subsidiaries: PSEG Nuclear LLC (Nuclear), PSEG
Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC (ER&T). Power also has
a finance company subsidiary, PSEG Power Capital Investment Co. (Power Capital),
which provides certain financing for Power's subsidiaries.
Energy Holdings has three principal direct wholly-owned subsidiaries; PSEG
Global Inc. (Global), PSEG Resources LLC (Resources) and PSEG Energy
Technologies Inc. (Energy Technologies). See Note 4. Discontinued Operations for
a discussion of 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. For a discussion of the formation of PSEG Energy Holdings L.L.C. and
PSEG Resources L.L.C. as the successors to Energy Holdings and Resources,
respectively, see Note 13. Subsequent Events.
Services provides management and administrative services to us and our
subsidiaries. These include accounting, legal, communications, human resources,
information technology, treasury and financial, investor relations, stockholder
services, real estate, insurance, risk management, tax, library and information
services, security, corporate secretarial and certain planning, budgeting and
forecasting services. Services charges us and our subsidiaries for work
performed and services provided by it.
Overview
Net income for the three months ended September 30, 2002 was $204 million or
$0.99 per share of common stock, based on 207 million average shares
outstanding. Net income was less than $1 million for the nine months ended
September 30, 2002. These results include after-tax charges of $3 million or
$0.01 per share and $535 million or $2.59 per share for the three and nine month
periods ended September 30, 2002, respectively, related to the asset impairment
of investments in Argentina and losses from operations of those impaired assets,
discontinued operations of Energy Technologies and a generating facility in
India and goodwill impairment charges. The after-tax charges relating to the
items discussed above are summarized in the following table:
34
Three Months Ended Nine Months Ended
September 30, 2002 September 30, 2002
-------------------- --------------------
(Millions) EPS (Millions) EPS
-------------------- --------------------
Global
Argentina - EDEERSA and Assets Held
for Sale to AES
Write-down of Investment .. $ -- $ -- $ 374 $ 1.81
Goodwill impairment ....... -- -- 36 0.18
------ ------ ------ ------
Total Argentina .................... -- -- 410 1.99
------ ------ ------ ------
India - Tanir Bavi
Discontinued Operations ... -- -- 9 0.04
Goodwill impairment ....... -- -- 18 0.09
------ ------ ------ ------
Total Tanir Bavi ................... -- -- 27 0.13
------ ------ ------ ------
Brazil - RGE
Goodwill impairment ....... -- -- 34 0.16
------ ------ ------ -----
Subtotal for Global .................. -- -- 471 2.28
------ ------ ------ ------
Energy Technologies
Discontinued Operations ... 3 0.01 32 0.16
Goodwill impairment ....... -- -- 32 0.15
------ ------ ------ ------
Subtotal Energy Technologies ......... 3 0.01 64 0.31
------ ------ ------ ------
Total .............................. $ 3 $ 0.01 $ 535 $ 2.59
====== ====== ====== ======
For the three and nine month periods ended September 30, 2002, excluding these
charges, earnings were $207 million or $1.00 per share and $535 million or $2.59
per share, respectively. Comparable earnings for the three and nine month
periods ended September 30, 2001 were $175 million or $0.84 per share and $584
million or $2.80 per share, respectively.
The increase in earnings, excluding the charges discussed above, for the three
month period ended September 30, 2002 as compared to the same period in the
prior year is primarily due to higher BGS margins at Power due to its successful
participation as an indirect supplier of energy to New Jersey's utilities,
including PSE&G, involved in New Jersey's recent basic generation service (BGS)
auction. The BGS auction had a meaningful effect on our earnings, particularly
since August 1, 2002, when the new BGS contracts went into effect. Also
contributing to the increase were lower Operations and Maintenance expenses at
PSE&G, increased earnings from Global, primarily due to the acquisitions late in
2001, increased earnings at RGE, a Brazilian electric distribution company, as
well as the commencement of operations at the generation facility in Rades,
Tunisia (Rades) and higher Net Investment Gains (Losses) in Resources' leveraged
buyout funds.
35
The decrease in earnings, excluding the charges discussed above, for the
nine-month period ended September 30, 2002 as compared to the same period in
2001 resulted primarily from lower margins at PSE&G and higher Operation and
Maintenance expense at Power. These decreases were partially offset by higher
BGS margins at Power.
Earnings (Losses)
---------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2002 2001 2002 2001
------ ------ ------ ------
(Millions)
Power .............................. $ 121 $ 87 $ 325 $ 292
PSE&G .............................. 55 65 128 204
Resources .......................... 17 9 26 27
Global (A) ......................... 20 16 (302) 66
Energy Technologies ................ 2 2 2 4
Other (B) .......................... (8) (4) (18) (9)
----- ----- ----- -----
Income from Continuing
Operations ....................... 207 175 161 584
Loss from Discontinued
Operations, including
Loss on Disposal ................. (3) (3) (41) (17)
Cumulative Effect of a Change in
Accounting Principle (C) ....... -- -- (120) 9
----- ----- ----- -----
Total PSEG ......................... 204 172 -- 576
----- ----- ----- -----
Total PSEG Excluding Charges (D) ... $ 207 $ 175 $ 535 $ 584
===== ===== ===== =====
Contribution to Earnings
Per Share (Basic and Diluted)
---------------------------------------
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2002 2001 2002 2001
------ ------ ------ ------
Power .............................. $ 0.59 $ 0.42 $ 1.57 $ 1.40
PSE&G .............................. 0.26 0.31 0.62 0.98
Resources .......................... 0.08 0.04 0.12 0.13
Global (A) ......................... 0.09 0.08 (1.46) 0.32
Energy Technologies ................ 0.01 0.01 0.01 0.02
Other (B) .......................... (0.03) (0.02) (0.08) (0.05)
------ ------ ------ ------
Income from Continuing
Operations ....................... 1.00 0.84 0.78 2.80
Loss from Discontinued
Operations, including Loss
on Disposal ...................... (0.01) (0.02) (0.20) (0.08)
Cumulative Effect of
a Change in Accounting
Principle (C) .................... -- -- (0.58) 0.04
------ ------ ------ ------
Total PSEG ......................... 0.99 0.82 -- 2.76
------ ------ ------ ------
Total PSEG Excluding
Charges (D) ...................... $ 1.00 $ 0.84 $ 2.59 $ 2.80
====== ====== ====== ======
(A) Includes after-tax impairments and losses on operations of impaired assets
of $374 million or $1.81 per share for the nine months ended September 30,
2002, respectively.
(B) Other activities include amounts applicable to PSEG (parent corporation),
Energy Holdings 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.
(C) Relates to the adoption of Statement of Financial Accounting Standards
(SFAS) No. 142, "Goodwill and Other Intangible Assets" (SFAS 142) in 2002
36
and the adoption of SFAS No. 133 "Accounting for Derivative Instruments
and Hedging Activities" (SFAS 133) in 2001.
(D) Excludes after-tax charges previously presented the summary table of $3
million or $0.01 per share and $535 million or $2.59 per share for the
three and nine month periods ended September 30, 2002, respectively.
Future Outlook
We expect to meet our revised earnings-per-share targets for 2002 of $3.70 to
$3.90, excluding the charges described above. For 2002, Power is expected to
earn $460 million to $500 million, PSE&G is expected to earn $175 million to
$185 million and Energy Holdings is expected to earn $145 million to $155
million, excluding the previously discussed charges. Power's successful
participation as an indirect supplier of energy to New Jersey's utilities,
including PSE&G, in New Jersey's recent BGS auction is expected to have a
meaningful effect on our earnings for the remainder of the year and should help
to partially offset the lack of earnings contributions from Energy Holdings'
investments in Argentina. The fourth quarter is expected to be strong, as Power
benefits from its fixed price BGS contracts while it is able to source energy at
economically attractive prices during this period of low demand.
While Global realized substantial growth in 2001, significant challenges which
began developing during the fourth quarter of 2001 have continued into 2002.
These challenges include the Argentine economic, political and social crisis,
the soft power market in Texas, recent developments in India and the worldwide
economic downturn. The financial effects of several of these challenges were
recorded in the second quarter of 2002. Also, we have recently reached a
settlement with AES related to our investments held for sale in Argentina,
receiving $15 million in October 2002 and receiving $15 million in notes which
mature on various dates ending in July 2003. Similarly, we have completed the
sale of our investment in Tanir Bavi at its reduced carrying value, receiving
proceeds of approximately $45 million in October 2002. Going forward, Global
will limit its spending to contractual commitments and refocuse its strategy
from one of accelerated growth to one that places emphasis on increasing the
efficiency and returns of its existing assets.
We have taken significant steps to address the pressures in the volatile
financial marketplace. We issued $460 million of participating equity preference
units, a mandatorily convertible preferred security, in September 2002 and we
continue to issue approximately $80 million of equity on an annual basis through
our dividend reinvestment program. In addition to these equity issuances, we
have further trimmed our capital expenditure program by recently revising the
timeline for the completion of three generating station construction projects,
which is in addition to previous reductions at Global and Resources. After this
year, which is an end of a peak period of capital expenditures, our internal
cash generation will significantly exceed our capital and dividend requirements.
In addition, we would also consider an additional equity issuance to accelerate
the further strengthening of our balance sheet.
Looking ahead, our business fundamentals remain strong and we continue to
produce solid cash flows. However, several of the assumptions in our 2003
planning process have changed in this evolving economic environment.
Specifically, two factors, increased pension expense due to the erosion of the
value of the investments in our pension plans, and the need to improve capital
structures in this volatile marketplace, are currently being considered as we
develop our 2003 business plan. As a result of these factors, we will likely
reduce our previous 2003 earnings target of $4.00 to $4.20. However, even if we
issued equity, we expect our 2003 earnings per share to be comparable to this
year's results due to our strong business fundamentals.
Other assumptions in our 2003 business plan are that: Power will continue to
benefit from its performance as a wholesale BGS provider with the new one year
BGS contract that began August 1, 2002 and a reasonable outcome to next year's
contract beginning August 1, 2003; PSE&G will have a successful outcome to its
recently filed electric rate case seeking an approximately $250 million increase
in electric rates beginning in August 2003, and benefit from more normal
weather; Global, with its major risks in Argentina and India behind it,
significant cost-cutting measures in place and limited spending planned over the
five year planning horizon, expects improvements in earnings through its focus
on increasing the return on its existing assets; and Resources, with recent
investments and less exposure to its investment in the KKR leveraged buyout
funds, expects to continue to be a steady contributor to earnings and cash
flows.
Factors Affecting Future Outlook
As a result of more than 70% of our earnings, excluding the changes discussed
above, coming from unregulated businesses, the continued changes in political,
legislative, regulatory and economic conditions in the many countries in which
we do business, the inherent price volatility of the commodities in our
businesses, and many other factors, it is much more difficult to accurately
forecast our future earnings. Some of the key sensitivities and risks of our
businesses are discussed below.
Power's success as a BGS provider will depend, in part, on its ability to meet
its obligations under its full requirements contracts with the BGS suppliers in
a profitable manner. Power expects to accomplish this by producing energy from
its own generation and/or energy purchases in the market. Power also enters into
trading positions related to its generation assets and supply obligations. To
the extent it does not hedge its obligations, whether long or short, Power will
be subject to the risk of price fluctuations that could affect its future
results, such as increases in the price of energy purchased to meet its supply
obligations, the cost of fuel to generate electricity,
37
the cost of congestion credits that Power needs to transmit electricity and
other factors. In addition, Power is subject to the risk of subpar operating
performance of its fossil and nuclear generating units. To the extent there are
unexpected outages at Power's generating facilities, changes in environmental or
nuclear regulations or other factors which impact the production by such units
or the ability to generate and transmit electricity in a cost-effective manner,
it may cost us more to produce electricity or we may be required to purchase
higher cost energy to replace the energy we anticipated producing. These risks
can be exacerbated by, among other things, changes in demand in electricity
usage, such as those due to extreme weather and economic conditions.
Power's future revenue stream is also uncertain. Due to the timing of the New
Jersey BGS auction process, the majority of Power's revenues for August 1, 2003
and thereafter cannot be accurately predicted. Also, certain of Power's new
projects, such as our investments in the Lawrenceburg and Waterford projects in
the Midwest, the plants we are acquiring from Wisvest in Connecticut, and our
development of the Bethlehem Energy Center in New York are also subject to the
risk of changes in future energy prices as Power has not entered into forward
sale contracts for the majority of their expected generation capacity. Also,
since the majority of our generation facilities are concentrated in the
Northeast region, changes in future energy supply and demand and energy-related
prices in this region could materially affect our results. Also, changes in the
rules and regulation of these markets by FERC, particularly changes in the
ability to maintain market based rates, could have an adverse impact on our
results. As a result of these variables and risks, we cannot predict the impact
of these potential future changes on our forecasted results of operations,
financial position, or net cash flows, however such impact could be material.
In addition, our earnings projections assume that we will continue to optimize
the value of our portfolio of generating assets and supply obligations through
our energy trading operations. This will depend, in part, on our, as well as our
counterparties', ability to maintain sufficient creditworthiness and to display
a willingness to participate in energy trading activities at anticipated
volumes. Potential changes in the mechanisms of conducting trading activity,
such as the continued availability of energy trading exchanges, could positively
or negatively affect trading volumes and liquidity in these energy trading
markets compared to the assumptions of these factors embedded in our business
plans. As a result of these variables, we cannot predict the impact of these
potential future changes on our forecasted results of operations, financial
position, or net cash flows, however such impact could be material.
PSE&G's success will be dependent, in part, on its ability to obtain a
reasonable outcome, which cannot be assured, to its recently filed electric rate
case as well as its ability to continue to recover the regulatory assets it has
deferred and the investments it plans to make in its electric and gas
transmission and distribution systems. Mitigating this rate increase to
customers are overrecoveries of the SBC and NTC and the potential securitization
of the expected BGS underrecovery. As of September 30, 2002, PSE&G has
implemented BPU mandated rate reductions totaling 13.9% since August 1, 1999,
including a 4.9% rate reduction effective August 1, 2002, which will be in
effect until July 31, 2003. This rate reduction reduces the Market Transition
Charge (MTC) rate paid to Power and therefore reduces Power's revenues.
Energy Holdings' success will be dependent, in part, on its ability to mitigate
risks presented by its international strategy. The economic and political
conditions in certain countries where Global has investments present risks that
may be different than those found in the United States including: renegotiation
or nullification of existing contracts, changes in law or tax policy,
interruption of business, risks of nationalization, expropriation, war, and
other factors. Operations in foreign countries also present risks associated
with currency exchange and convertibility, inflation and repatriation of
earnings. In some countries in which Global has interests, economic and monetary
conditions and other factors could affect Global's ability to convert its cash
distributions to US Dollars or other freely convertible currencies and move
funds. Furthermore, the central bank of any such country may have the authority
to suspend, restrict or otherwise impose conditions on foreign exchange
transactions or to approve distributions to foreign investors. Although Global
generally seeks to structure power purchase contracts and other project revenue
agreements to provide for payments to be made in, or indexed to, US Dollars or a
currency freely convertible into US Dollars, its ability to do so in all cases
may be limited.
The international risks discussed above can potentially be magnified due to the
volatility of foreign currencies. The foreign exchange rates of the Brazilian
Real, Chilean Peso and Peruvian Sol have recently weakened due to various
political and economic factors. This could result in comparatively lower
contributions from our distribution investments in US Dollar terms. While we
still expect certain of Energy Holdings' investments in Latin America to
38
contribute significantly to our earnings in the future, the political and
economic risks associated with this region could have a material adverse impact
on our remaining investments in the region.
Certain of Global's projects are also subject to the risk of changing future
energy prices, including its investment in two 1,000 MW facilities in Texas
which have performed below expectations due to lower energy prices than we had
anticipated, primarily resulting from the over-supply of energy in the Texas
power market. 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 and has included these assumptions within
its business plans. However, no assurances can be given as to the accuracy of
these estimates and changes in these estimates could have a material impact on
its forecasted results of operations, financial position, or net cash flows.
Energy Holdings, through Resources, also faces risks with regard to the
creditworthiness of its counterparties, as well as the risk of a change in the
current tax treatment of its investments in leveraged leases. The manifestation
of either of these risks could cause a materially adverse effect on its strategy
and its forecasted results of operations, financial position, or net cash flows.
For discussion of certain counterparties to these leases who have been
downgraded to below investment grade by at least one of the rating agencies, see
Item 3. Qualitative and Quantitative Disclosures about Market Risk.
In addition, we have exposure to the equity and debt markets through our
substantial use of short-term financing, lower pension fund balances, the effect
of lower assumed rate of investment returns on our pension expense, the effect
of a lower discount rate on our pension plan liabilities and costs, the
potential impact to Resources' investment in the KKR leveraged buyout funds, and
other equity and debt investments held by us. Also, increases in the cost of
capital, which could result from market and lender concerns regarding us, our
industry, United States and international economic conditions and other factors,
could make it more difficult for us to enter into profitable investments. Recent
market trends could also affect our ability to access capital, potentially
impacting both our business plans and opportunities as well as our liquidity.
Also, changes in our credit ratings by rating agencies could significantly
impact our access to capital, cost of capital, ability to meet earnings
expectations and future business plans. Also, as a result of market price
volatility, the fair value of the debt of certain of our subsidiaries has
experienced significant volatility. We are also subject to credit risk. See Item
3. Qualitative and Quantitative Disclosures about Market Risk for further
discussion.
Results of Operations
Operating Revenues
For the three months ended September 30, 2002, Operating Revenues increased by
$711 million or 44%, due primarily to a $407 million increase in revenues from
Power. Also contributing to the increase for the three months ended September
30, 2002 as compared to the same period in 2001 were increases of $44 million,
$10 million and $7 million at Global, PSE&G and Resources, respectively.
Included in Power's increase were increases of $172 million of gas revenues
relating to its BGSS contract and off-system sales resulting from the Gas
Contract transfer from PSE&G in May 2002. Also contributing to Power's increase
was a $268 million increase in electric revenues, primarily due to the new BGS
contracts with third party wholesale electric suppliers which went into effect
August 1, 2002 and comparably warmer weather which were partially offset by
lower MTC revenues primarily due to a 4.9% rate reduction in August 2002 and a
2% rate reduction in August 2001. These rate reductions reduce the MTC revenues
that PSE&G remits to Power as part of its BGS contract. Also offsetting the
increases were lower net trading revenues of approximately $23 million due to
lower trading volumes and prices during the three months ended September 30,
2002 as compared to the same period in 2001.
39
The increase in Operating Revenues at Global was due primarily to $31 million of
increases related to the acquisition late in the third quarter of 2001 of SAESA,
a Chilean distribution company and $10 million of increases related to the
acquisition in the fourth quarter of 2001 of Electroandes, a Peruvian generation
company. Global's Operating Revenues also increased $32 million due to the
generation facility located in Rades, Tunisia commencing operation via a
retroactive commercial operating date in the second quarter of 2002. Also
contributing $16 million to the increase in revenues was Skawina in Poland in
which we purchased a majority ownership late in the second quarter of 2002.
Revenues further increased by $8 million due to improved earnings from RGE as
new regulatory changes allow RGE to recover from customers prior tariff charges
previously expensed. Partially offsetting these increases was a decrease at
EDEERSA of $18 million, which reflects the ongoing economic crisis in Argentina.
There were also decreased earnings totaling $9 million at our GWF generation
facilities due to a reversal of an accounts receivable reserve in 2001 related
to California Power exchange pricing in 2001 and lower prices in 2002 as
compared to 2001; and decreased earnings of $8 million at our TIE generation
facilities due to lower energy prices in 2002 as compared to 2001.
The increase in Operating Revenues from PSE&G related to $41 million of higher
electric transmission and distribution revenues offset by $31 million of lower
gas distribution revenues.
The $7 million increase at Resources was primarily related to higher Net Gains
(Losses) on Investments resulting from no net change in the carrying value of
publicly traded and private securities held within the KKR leveraged buyout
funds in the third quarter of 2002, as compared to a $8 million loss in the same
period of 2001.
The remaining $243 million increase is due primarily to Power's BGS or commodity
revenues in August and September of 2002 not being eliminated in consolidation
by PSEG. Under the BGS contract which terminated on July 31, 2002, Power sold
energy directly to PSE&G which in turn sold this energy to its customers. These
revenues were properly recognized on each company's stand-alone financial
statements and were eliminated when preparing our consolidated financial
statements. For the new BGS contract period beginning August 1, 2002, Power
sells to third party suppliers and other load serving entities (LSEs) and PSE&G
purchases the energy for its customers' needs from third party suppliers. Due to
this change in the BGS model, these revenues are no longer intercompany revenues
and therefore are not eliminated in consolidation. This amount would have been
approximately $366 million for August and September 2002, representing the
amount which PSE&G's cost to supply electricity to its customers, and is
partially offset by $118 million of intercompany eliminations relating to the
BGSS contract between Power and PSE&G which began in May 2002.
For the nine months ended September 30, 2002, Operating Revenues increased by
$373 million or 7%, due primarily to a $422 million increase in revenues from
Power and $161 million from Global. These increases were partially offset by a
$364 million decrease in revenues from PSE&G.
For the nine months ended September 30, 2002, Power's increased Operating
Revenues included $273 million of gas revenues relating to its BGSS contract and
off-system sales resulting from the Gas Contract transfer from PSE&G in May
2002. Also contributing to the increase was a $228 million increase in electric
revenues, primarily due to the new BGS contracts with third party wholesale
electric suppliers which went into effect August 1, 2002 and comparably warmer
weather which were partially offset by lower MTC revenues primarily due to a
4.9% rate reduction in August 2002 and two 2% rate reductions in August 2001 and
February 2001. Also offsetting the increases were lower net trading revenues of
approximately $79 million due to lower trading volumes and prices during the
nine months ended September 30, 2002 as compared to the same period in 2001.
The increase at Global was due primarily to $142 million related to the
acquisitions of SAESA and Electroandes and $32 million due to the inception of
operations at Rades, as discussed previously. Also contributing $16 million to
the increase in revenues was Skawina, in which we purchased a majority ownership
late in the second quarter of 2002 as discussed above. Revenues further
increased at Global by $21 million due to improved earnings from RGE as a result
of the new regulatory changes described above. Partially offsetting these
increases were decreases in earnings of $18 million at GWF Energy and $17
million at TIE as a result of lower energy prices.
The decrease in PSE&G's Operating Revenues primarily related to a $344 million
decrease in gas distribution revenues primarily due to decreased commodity
rates, approximately $176 million, lower sales to interruptible
40
customers, approximately $111 million, lower sales volumes primarily from the
warmer winter in 2002, approximately $90 million and lower off-system sales
revenues, approximately $14 million. In addition, electric transmission and
distribution revenues decreased $20 million. These decreases were partially
offset by increased gas base rates, approximately $43 million and higher other
operating revenues (approximately $7 million).
The remaining $154 million increase is due primarily to Power's BGS or commodity
revenues in August and September of 2002 not being eliminated in consolidation
by PSEG as discussed previously. This amount would have been approximately $366
million for August and September 2002, representing the amount which PSE&G's
cost to supply electricity to its customers, and is partially offset by $217
million of intercompany eliminations relating to the BGSS contract between Power
and PSE&G which began in May 2002.
Operating Expenses
Energy Costs
For the three months ended September 30, 2002, Energy Costs increased $590
million or 104% due primarily to increases of $332 million and $34 million at
Power and Global, respectively, partially offset by a $17 million decrease at
PSE&G. The remaining increase in Energy Costs is due primarily to a net
difference in intercompany eliminations of approximately $248 million, discussed
above in Operating Revenues.
Power's increases were primarily due to increased energy purchases for the BGS
and third party wholesale electric supplier contracts of approximately $122
million due to higher volumes and $197 million of increased gas purchases to
satisfy Power's BGSS contract and its fuel needs for generation. Also
contributing to the increase were approximately $43 million of increased network
transmission expenses in the Pennsylvania-New Jersey-Maryland Power Pool (PJM).
These increases were offset by $22 million of gains on fuel hedges, $5 million
of reduced congestion charges due to more efficient unit scheduling by PJM and a
$3 million decrease in nuclear fuel usage.
The increases at Global for the three months ended September 30, 2002 were
primarily due to operating expenses incurred at SAESA and Electroandes. The
operating expenses for the comparable periods in 2001 did not include expenses
for Electroandes as it was purchased in the fourth quarter of 2001, and included
only a portion of expenses for SAESA as it was purchased late in the third
quarter of 2001.
The decrease at PSE&G primarily related to a decrease in gas costs primarily due
to lower commodity rates, approximately $16 million, which became effective
January 9, 2002, lower revenues from interruptible customers, approximately $12
million, due to lower volumes at lower rates and lower off-system sales
revenues, approximately $5 million, due to lower volumes. These decreases were
partially offset by increased electric energy costs primarily due to higher
commodity sales volumes under the BGS contract, approximately $43 million,
increases in the amortization of the excess electric distribution depreciation
reserve, approximately $6 million (discussed below in Depreciation and
Amortization), increases in MTC charges from Power, other than rate reductions,
approximately $6 million and increases in Non-Utility Generation Transition
Charge (NTC) costs due to higher sales volumes, approximately $3 million.
Partially offsetting the increases is the impact of the rate reductions,
approximately $42 million, discussed above in Operating Revenues.
Under the BGSS, our gas costs in excess of (or below) the amount included in
current commodity rates, are probable of being recovered from (returned to) to
customers through future commodity rates. Under SFAS 71, we defer (record) costs
in excess of (or below) the amount included in current commodity rates.
Therefore any increase or decrease in our gas commodity revenue is offset by a
corresponding increase or decrease in gas costs on the income statement.
For the nine months ended September 30, 2002, Energy Costs increased $279
million or 14% due primarily to increases of $377 million and $92 million at
Power and Global, respectively, partially offset by a $341 million
41
decrease at PSE&G. The remaining increase in Energy Costs is due primarily to a
net difference in intercompany eliminations of approximately $149 million,
discussed above in Operating Revenues.
Power's increases were primarily due to increased energy purchases for the BGS
and third party wholesale electric supplier contacts of approximately $144
million due to higher volumes and $276 million of increased gas purchases to
satisfy Power's BGSS contract and its fuel needs for generation. Also
contributing to the increase was higher network transmission expenses of $35
million for PJM and $11 million of increased coal purchases. These higher
expenses were partially offset by a $13 million decrease in nuclear fuel usage
and a $36 million decrease in oil consumption. Further expense reductions can be
attributed to $14 million of decreases in fuel hedges, $13 million decrease in
Non-Utility Generation (NUG) purchases and $13 million in lower congestion
charges due to less constraint in the system.
The increases at Global for the nine months ended September 30, 2002 were
primarily due to operating expenses incurred at SAESA and Electroandes,
discussed above.
PSE&G's decreases were due primarily to a decrease in gas costs of approximately
$350 million primarily due to lower commodity costs, approximately $176 million,
lower revenues from interruptible customers, approximately $111 million, due to
lower volumes at lower rates, lower sales volumes as a result of the warmer
weather in 2002, approximately $52 million and lower off-system sales revenues,
approximately $9 million. These decreases were partially offset by increased
electric energy costs of $9 million primarily due to higher commodity sales
volumes under the BGS contract, approximately $90 million and higher amounts
paid to Power relating to the amortization of the excess electric distribution
depreciation reserve, approximately $22 million. Partially offsetting the
increases is the impact of the rate reductions, approximately $85 million,
discussed above in Operating Revenues, lower NUG energy sales, approximately $13
million and lower market rates and lower MTC charges from Power, other than rate
reductions, approximately $4 million.
Operation and Maintenance
For the three months ended September 30, 2002, Operations and Maintenance
expense decreased $2 million as compared to same period in 2001 due primarily to
a decrease at PSE&G resulting from a management initiative to lower PSE&G's
Operation and Maintenance costs. This decrease was partially offset by increases
at Power, primarily from scheduled outage work at its electric generating
stations, and increases at Global, relating to the operations of SAESA and
Electroandes, discussed previously.
For the nine months ended September 30, 2002, Operations and Maintenance expense
increased $13 million or 1% as compared to the same period in 2001 due primarily
to increases at Power and Global, partially offset by the decreases at PSE&G,
discussed above.
Depreciation and Amortization
For the three and nine-month periods ended September 30, 2002, Depreciation and
Amortization increased $15 million or 10% and $61 million or 16%, respectively,
as compared to the same periods in 2001, primarily due to increases at PSE&G,
resulting from an increase in depreciable fixed assets, higher depreciation
expense recorded in accordance with increased gas base rates and amortization
related to securitization. The increases were partially offset by higher
amortization of the excess electric distribution depreciation reserve.
Interest Expense
Interest Expense increased $9 million or 5% and $58 million or 11% for the three
and nine-month periods ended September 30, 2002, respectively, as compared to
the same periods in 2001 primarily due to additional long-term debt at Power and
Energy Holdings issued to finance recent acquisitions and development.
42
Income Taxes
Income taxes increased $75 million for the three months ended September 30, 2002
as compared to the same period in 2001 due partially to higher income in the
current quarter. Prior period tax adjustments recorded in 2001 reflecting the
conclusion of the 1994-96 IRS audit settlement and the actual filing of the 2000
tax return also contributed to the increase.
Income taxes decreased $173 million for the nine months ended September 30, 2002
as compared to the same period in 2001 primarily due to lower income in the
current year, offset by the prior period adjustments discussed above.
Losses From Discontinued Operations
Energy Technologies
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.
During the second quarter of 2002, Energy Holdings completed its impairment
testing of all recorded goodwill in accordance with guidance set forth in SFAS
142 including the goodwill associated with the 11 HVAC/mechanical operating
companies acquired by Energy Technologies. Such analysis indicated that the
entire $53 million of goodwill associated with the HVAC/mechanical companies was
impaired, which resulted in a $32 million (after-tax) charge (net of $21 million
in taxes). In accordance with SFAS 142, this charge was recorded as of January
1, 2002 as a Cumulative Effect of a Change in Accounting Principle and reflected
in our results of operations for the nine months ended September 30, 2002.
In June 2002, Energy Holdings adopted a plan to sell its interests in the
HVAC/mechanical operating companies. The sale of these companies is expected to
be completed by June 30, 2003. We have retained the services of an
investment-banking firm to market these companies to interested parties. The
HVAC/mechanical operating companies meet the criteria for classification as
components of discontinued operations and all prior periods have been
reclassified to conform to the current year's presentation.
In the second quarter of 2002, Energy Holdings initiated a process for the sale
of Energy Technologies' DSM investments, which we had expected to sell by June
30, 2003. Based on our assessments, we believe the fair market value of these
assets approximates their carrying value as of September 30, 2002 and no
reduction in the carrying amount is indicated. For the period ended June 30,
2002, Energy Technologies' DSM investments were classified as a component of
discontinued operations. In the third quarter of 2002, Energy Holdings decided
to continue to own the DSM investments. For the period ended September 30, 2002,
all DSM investments were reclassified from discontinued operations to continuing
operations and the consolidated statements for all periods presented have been
restated to reflect this reclassification.
In addition to the goodwill impairment, Energy Holdings has further reduced the
carrying value of the investments in the 11 HVAC/mechanical operating companies
to their fair value less costs to sell, and recorded a loss on disposal for the
six months ended June 30, 2002 of $20 million, net of $11 million in taxes. As
of September 30, 2002, the carrying value of the HVAC/mechanical operating
companies approximates the fair value and accordingly no additional reduction in
the carrying value was required for the three months ended September 30, 2002.
Energy Holdings' remaining investment position in Energy Technologies is
approximately $110 million, of which approximately $32 million relates to
deferred tax assets from discontinued operations, for which no valuation
allowance is deemed
43
necessary. Excluding the deferred tax assets from discontinued operations,
approximately $40 million of our remaining investment balance relates to the
asset management group. Although we believe that we will be able to sell the
HVAC/mechanical companies, we can give no assurances that we will be able to
realize their total carrying values.
Operating results of Energy Technologies' HVAC/mechanical operating companies,
less certain allocated costs from Energy Holdings, have been reclassified into
discontinued operations in our Consolidated Statements of Operations. The
results of operations of these discontinued operations for the quarter and nine
months ended September 30, 2002, yielded additional losses of $3 million
(after-tax) and $12 million (after-tax), respectively, and are disclosed below:
Quarter Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2002 2001 2002 2001
------ ------ ------ ------
(Millions) (Millions)
Operating Revenues ............... $ 107 $ 127 $ 292 $ 328
Pre-Tax Operating Loss ........... (5) (5) (18) (25)
Loss Before Income Taxes ......... (5) (6) (19) (29)
Tanir Bavi
At 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 June 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 prior periods have been
reclassified to conform to the current year's presentation. 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 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).
See Note 4. Discontinued Operations for further discussion.
Cumulative Effect of Change in Accounting Principle
In the second quarter of 2002 we finalized our evaluation of the effect of
adopting SFAS 142 on the recorded amount of goodwill. Under this standard, we
were required to complete an impairment analysis of our recorded goodwill and
record any resulting impairment. The total amount of goodwill impairments was
$120 million, net of tax of $66 million and was comprised of $36 million
(after-tax) at EDEERSA, $34 million (after-tax) at Rio Grande Energia (RGE), $32
million (after-tax) at Energy Technologies and $18 million (after-tax) at Tanir
Bavi. All of the goodwill on these companies, other than RGE, was fully
impaired. In accordance with SFAS 142, this impairment charge was recorded as of
January 1, 2002 as a component of the Cumulative Effect of a Change in
Accounting Principle and is reflected in Consolidated Statement of Operations
for the nine months ended September 30, 2002.
44
Operations in Argentina
We, through our Energy Holdings subsidiary, have significant operations in
Argentina. Over the past year, the business and economic conditions in that
region have deteriorated. As of December 31, 2001, Energy Holdings' aggregate
investment exposure in Argentina was $632 million. These investments included a
90% owned distribution company, Empresa Distribuidora de Electricidad de Entre
Rios S.A. (EDEERSA); minority interests in three 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); and two
generating companies, Central Termica San Nicolas (CTSN), and Parana which are
under contract for sale to certain subsidiaries of The AES Corporation (AES).
Net operating losses relating to these investments of $59 million have been
incurred year-to-date and are mainly attributable to the falling value of the
Argentine peso. Additionally, certain loss contingencies have been accrued of
$11 million during the nine month period ended September 30, 2002. In June 2002,
Energy Holdings determined that the carrying value of its Argentine investments
was impaired. Energy Holdings recorded charges in connection with the impairment
of $506 million ($329 million after-tax) during the second quarter of 2002. No
such impairment charges were incurred during the third quarter ended September
30, 2002. For the three and nine periods ended September 30, 2001, operating
expenses of $6 million and $11 million were incurred, respectively. See Note 3.
Asset Impairments for further discussion.
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, PSE&G, Power and Energy Holdings.
Financing Methodology
Our capital requirements are met through liquidity provided by internally
generated cash flow and external financings. PSEG, Power and Energy Holdings
from time to time make equity contributions or otherwise provide credit support
to their respective direct and indirect subsidiaries to provide for part of
their capital and cash requirements, generally relating to long-term
investments. As of September 30, 2002, PSEG does not have any guaranteed equity
contribution commitments. As of September 30, 2002, Power had guaranteed equity
contribution commitments with respect to its subsidiaries of $153 million and
has other guarantees and commitments of $73 million and Energy Holdings has
guaranteed equity commitment guarantees of $153 million and other guarantees of
$91 million and $1 million relating to Global and Energy Technologies,
respectively. At times, we utilize intercompany dividends and intercompany loans
(except that PSE&G may not make loans to us or our subsidiaries and affiliates)
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.
As discussed below, depending on the particular company, external financing may
consist of public and private capital market debt and equity transactions, bank
revolving credit and term loans, commercial paper and/or project financings.
Some of these transactions involve special purpose entities (SPEs), formed in
accordance with applicable tax and legal requirements in order to achieve
specified beneficial financial advantages, such as favorable tax and legal
liability treatment. Substantially all SPEs are consolidated, where we have
controlling interest.
45
Global has certain investments that are accounted for under the equity method in
accordance with generally accepted accounting principles. Accordingly, an amount
is recorded on our balance sheet that is primarily Global's equity investment
and is increased for Global's pro-rata share of earnings less any dividend
distribution from such investments. The companies in which Global invests that
are accounted for under the equity method have an aggregate $1.89 billion of
debt on their combined, consolidated financial statements. Global's pro-rata
share of such debt is $697 million and is non-recourse to Energy Holdings,
Global and us. Energy Holdings is generally not required to support the debt
service obligations of these companies.
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
separation between us and our subsidiaries 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 SPE assets and/or
cash flows. Two of Power's projects currently under construction have similar
financing. Non-recourse transactions generally impose no material 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 for their respective subsidiaries. The
consequences of permitting a project-level default include loss of any invested
equity by the parent. PSEG has not currently provided any guarantees or credit
support to PSE&G, Power or Energy Holdings, except for the minimum net worth
maintenance support agreement to PSEG Capital Corporation, a subsidiary of
Energy Holdings, which we plan to eliminate upon maturity of PSEG Capital
Corporation's debt in May 2003.
Over the next several years, PSEG and its subsidiaries will be required to
refinance maturing debt and expect to 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 adversely affect
our financial condition, results of operations and net cash flows.
During the third quarter of 2002, Energy Holdings purchased approximately $19
million of Senior Notes at prices below par value. In October 2002, Energy
Holdings purchased an additional $20 million of Senior Notes at prices below par
value. From time to time, PSEG and its subsidiaries may repurchase additional
debt securities using funds from operations, asset sales, commercial paper, debt
issuances, equity issuances and other sources of funding, and may make exchanges
of new securities, including common stock, for outstanding securities. Such
repurchases may be at variable prices below, at or above prevailing market
prices and may be conducted by way of privately negotiated transactions,
open-market purchases, tender or exchange offers or other means. We may utilize
brokers or dealers or effect such repurchases directly. Any such repurchases may
be commenced or discontinued at any time without notice.
Debt Covenants, Cross Default Provisions, Material Adverse Clause Changes, and
Ratings Triggers
The PSEG credit agreements contain default provisions under which a default by
it or its major subsidiaries (PSE&G, Power, Energy Holdings) in an aggregate
amount of $50 million would result in a default and the potential acceleration
of payment under the agreements.
The Energy Holdings credit agreements contain default provision under which a
default by it or its major subsidiaries (Resources, Global) in an aggregate
amount of $5 million, or a default by PSEG in an aggregate amount of $75 million
would result in an event of default and the potential acceleration of payment
under the agreements. The Energy Holdings Senior Note Indenture contains
cross-default provisions under which a default by it or its major subsidiaries
(Resources, Global) in an aggregate amount of $25 million would result in a
default and the potential acceleration of payment under the indenture.
The Power Senior Debt Indenture contains a default provision under which a
default by it or its subsidiaries (Nuclear, Fossil, ER&T) in an aggregate amount
of $50 million would result in a default and the potential acceleration of
payment under the indenture. There are no cross-defaults within Power's
indenture from PSEG, Energy Holdings or PSE&G.
The PSE&G First and Refunding Mortgage (Mortgage) and credit agreements have no
cross-
46
defaults. The PSE&G Medium Term Note Indenture has a cross-default to the PSE&G
Mortgage. The credit agreements have cross-defaults under which a default by
PSE&G in the aggregate of $50 million would result in a default and the
potential acceleration of payment under the credit agreements.
A failure to make principal and/or interest payments, when due, would be a
default under the respective credit agreements and indentures of PSEG, PSE&G,
Power and Energy Holdings. Any inability to satisfy required covenants and/or
borrowing conditions would have a similar impact. If a default were to occur,
the respective lenders and debt holders, after giving effect to any applicable
grace and/or cure periods, could determine that debt payment obligations may be
accelerated. In the event of any likely default or failure to satisfy covenants
or conditions, we, or the relevant subsidiary, would seek to renegotiate terms
of the agreements with the lenders. No assurances can be given as to whether
these efforts would be successful. A declaration of cross-default could severely
limit PSEG's and the applicable subsidiaries' liquidity and restrict the ability
to meet respective debt, capital and, in extreme cases, operational cash
requirements which could have a material adverse effect on our financial
condition, results of operations and net cash flows, and those of our
subsidiaries.
The credit agreements generally contain provisions under which the lenders could
refuse to advance loans in the event of a material adverse change in the
borrower's business or financial condition. In that event, loan funds may not be
advanced.
As explained in detail below, 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.
The debt indentures and credit agreements do not contain any material "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 cost of the energy trading business. These same
contracts provide reciprocal benefits to Power. Providing this credit support
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 that may include cash
payments. Global and Energy Holdings may have to provide collateral for certain
of their equity commitments if Energy Holdings' ratings should fall below
investment grade. Similarly, Power may also have to provide credit support for
certain of its equity commitments if Power loses its investment grade rating.
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',
Power's and PSE&G's securities and serve to increase those companies' cost of
capital, and access to capital.
47
Moody's(1) Standard & Poor's(2) Fitch(3)
---------- -------------------- --------
PSEG:
Preferred Securities Baa3 BB+ BBB
Commercial Paper P2 A2 Not Rated
PSE&G:
Mortgage Bonds A3 A- A
Preferred Securities Baa1 BB+ 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
(1) On October 11, 2002 Moody's reaffirmed these credit ratings but changed
the outlook from stable to negative for PSEG, Power and Energy Holdings.
(2) Affirmed in the second quarter of 2002 and noted an outlook of Stable.
Standard and Poor's has established an overall corporate credit rating of
BBB for us and each of our subsidiaries listed above.
(3) Affirmed in the second quarter of 2002 and noted an outlook of Stable,
except for PSE&G Mortgage Bonds, which was noted as negative.
Short-Term Liquidity
We and our subsidiaries have revolving credit facilities to provide liquidity
for our $1 billion commercial paper program and PSE&G's $400 million commercial
paper program and for various funding purposes. The following table summarizes
the various revolving credit facilities of PSEG, PSE&G and Energy Holdings as of
September 30, 2002. Power relies on PSEG for its short-term financing needs and
has a $50 million Letter of Credit Facility expiring in August 2005.
Expiration Total Primary
Company Date Facility Purpose
- --------------------------- -------------- ---------- ------------
(Millions of Dollars)
PSEG:
364-day Credit Facility March 2003 $620 CP Support
364-day Bilateral Facility March 2003 100 CP Support
5-year Credit Facility March 2005 280 CP Support
5-year Credit Facility December 2002 150 Funding
Uncommitted Bilateral
Agreement N/A * Funding
PSE&G:
364-day Credit Facility June 2003 200 CP Support
3-year Credit Facility June 2005 200 CP Support
Uncommitted Bilateral
Agreement N/A * Funding
Energy Holdings:
364-day Credit Facility May 2003 200 Funding
5-year Credit Facility May 2004 495 Funding
Uncommitted Bilateral
Agreement N/A * Funding
* Availability varies based on market conditions.
As of September 30, 2002, our consolidated total short-term debt outstanding was
$1.657 billion, including $673 million and $94 million of commercial paper at
PSEG and PSE&G, respectively, $271 million of non-recourse short-term financing
at Global and $329 million, $37 million and $253 million outstanding under
credit facilities and through the uncommitted bilateral agreements at PSEG,
PSE&G and Energy Holdings, respectively. In addition, we have a total of $742
million of long-term debt due within one year, comprised of $300 million at
PSE&G, $128 million at Transition Funding and $314 million at Energy Holdings
including $32 million of non-recourse debt.
48
PSEG
In 2002, we began issuing new shares under our Dividend Reinvestment and
Employee Stock Purchase Plan (DRASPP), rather than purchasing them on the open
market. For the nine months ended September 30, 2002 we issued approximately 1.5
million shares for approximately $57 million.
Dividend payments on Common Stock for the quarter and nine months ended
September 30, 2002 were $0.54 and $1.62 per share and totaled approximately $111
million and $334 million, 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 uncertain as our business continues to
change from one that was 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.
Financial covenants contained in our credit facilities include a ratio of debt
(excluding non-recourse project financings and securitization debt and including
commercial paper and loans, certain letters of credit and similar instruments)
to total capitalization covenant. This covenant requires that at the end of any
quarterly financial period, such ratio not be more than 0.70 to 1. As of
September 30, 2002, our ratio of debt to capitalization was 0.65 to 1.
Recent downturns in the stock markets could affect the value of our pension
plans that may result in a charge to our stockholders' equity at year-end. If
required, this would result in an increase to our debt to capitalization ratio.
See Accounting Matters for further information.
As part of our financial planning forecast, we perform stress tests on our
financial covenants that include a consideration of the impacts of potential
asset impairments, foreign currency fluctuations, adjustments relating to our
pension plans and other items. Our current forecasts do not indicate that we
will exceed the required ratio of debt to total capitalization, however, no
assurances can be given and, if an event of default were to occur, it could
materially impact our results of operations, cash flow and financial position.
On May 21, 2002, $275 million of Floating Rate Notes matured.
In September 2002, we issued 9.2 million Participating Units with a stated
amount of $50 per unit. Each unit consists of a 6.25% trust preferred security
due 2007 having a liquidation value of $50, and a stock purchase contract
obligating the purchasers to purchase shares of our common stock in an amount
equal to $50 on November 16, 2005. In exchange for the obligations under the
purchase contract, the purchasers will receive quarterly contract adjustment
payments at the annual rate of 4.00% until such date. The number of new shares
issued will depend upon the average closing price per share of our common stock
for the 20 consecutive trading days ending the third trading day immediately
preceding November 16, 2005. Based on the formula described in the purchase
contract, at that time we will issue between 11,429,139 and 13,714,967 shares of
its common stock. The net proceeds from the sale of the Participating Units was
$446.2 million.
In October 2002, we closed on a $245 million private placement debt transaction
with a five-year average life, with the proceeds being used to reduce short-term
debt.
In the third quarter of 2002, we contributed $100 million of equity to Energy
Holdings and we expect to contribute an additional $100 million in the fourth
quarter of 2002.
49
PSE&G
Under its Mortgage, PSE&G may issue new First and Refunding Mortgage Bonds
against previous additions and improvements, provided that its ratio of earnings
to fixed charges calculated in accordance with its Mortgage is at least 2:1,
and/or against retired Mortgage Bonds. At September 30, 2002, PSE&G's Mortgage
coverage ratio was 3:1. As of September 30, 2002, 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 is required to
obtain BPU authorization to issue any financing necessary for its capital
program, including refunding of maturing debt and opportunistic refinancing.
PSE&G has authorization from the BPU to issue up to an aggregate of $1 billion
of long-term debt through December 31, 2003 for the refunding of maturing debt
and opportunistic refinancing of debt. We currently have authorization from the
BPU to issue up to $2 billion in short-term debt through December 31, 2002. In
October 2002, we filed a petition with the BPU requesting authority to issue up
to $750 million of short-term debt through January 4, 2005. In addition, PSE&G
expects to securitize approximately $250 million of deferred BGS costs, the
proceeds of which will be used to reduce short-term debt.
Financial covenants contained in PSE&G's credit facilities include a ratio of
Long-Term Debt (excluding Long-Term Debt Maturing within 1 Year) to Total
Capitalization covenant. This covenant requires that at the end of any quarterly
financial period, such ratio will not be more than 0.65 to 1. As of September
30, 2002, our ratio of Long-Term Debt to Total Capitalization was 0.508 to 1.
In August 2002, $257 million of 6.125% Series RR Mortgage Bonds matured.
In September 2002, PSE&G issued $300 million of 5.125% Medium-Term Notes due
2012, the proceeds of which were used to repay $290 million of 7.19% Medium-Term
Notes that matured.
During 2002, PSE&G Transition Funding LLC, a wholly-owned subsidiary of PSE&G,
has repaid $85 million of securitization bonds.
Since 1986, PSE&G has made regular cash payments to us in the form of dividends
on outstanding shares of its common stock. PSE&G paid common stock dividends of
$150 million and $112 million to us for the nine months ended September 30, 2002
and 2001, respectively.
Power
Power's short-term financing needs will be met using PSEG's commercial paper
program or lines of credit discussed above.
In June 2002, Power issued $600 million of 6.95% Senior Unsecured Notes due
2012. The proceeds were used to repay short-term funding from us, including
amounts related to the Gas Contract Transfer from PSE&G in May 2002.
Energy Holdings
As of September 30, 2002, Energy Holdings had two separate 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 $12 million were outstanding as of September 30, 2002.
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
50
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 September 30, 2002, the latest 12 months CFADS coverage ratio was
6.3 and the ratio of recourse indebtedness to recourse capitalization was 0.47
to 1.00.
PSEG Capital has a $650 million Medium-Term Note program which provides for the
private placement of Medium-Term Notes. This Medium-Term Note 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 will eliminate our
support of PSEG Capital debt by the second quarter of 2003.
In July 2002, an additional $100 million of PSEG Capital MTNs with an average
borrowing rate of 6.95% matured. These MTNs were refunded with proceeds from
borrowings under Energy Holdings' bank facilities with current interest costs of
approximately 2.7%.
As of September 30, 2002, remaining maturities under the PSEG Capital
Corporation program were $282 million, $30 million of which matured in October
2002, and $252 million of which matures in May 2003. These issues will be
refunded with proceeds of borrowings at Energy Holdings and cash from
operations.
Capital Requirements
We have substantially reduced our capital expenditure forecast in response to
tightening market conditions resulting from market and lender concerns regarding
the overall economy and our industry in particular, including an investor and
rating agency focus on leverage ratios. These conditions have made it more
difficult for us to access capital, impacting our business plans and
opportunities to enter into profitable investments.
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 has
revised its schedule for completion of several projects under development to
provide better sequencing of its construction program with anticipated market
demand. This will allow Power to conserve capital in 2003 and allow Power to
take advantage of the expected recovery of the electric markets and their need
for capacity in 2005. Power's subsidiaries have substantial commitments as part
of their growth strategies and ongoing construction programs. Power will
continue to evaluate its development and construction requirements in relation
to the energy and financial markets.
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, excluding nuclear fuel purchases for Power, for our subsidiaries
for the next five years are as follows:
2002 2003 2004 2005 2006
------ ------ ------ ------ ------
(Millions)
Power ........... $1,100 $ 500 $ 675 $ 250 $ 80
Energy Holdings . 600 100 50 50 50
PSE&G ........... 485 440 440 450 465
------ ------ ------ ------ ------
Total ....... $2,185 $1,040 $1,165 $ 750 $ 595
====== ====== ====== ====== ======
51
All of the forecasted expenditures in 2004 through 2006 related to Energy
Holdings are discretionary.
For the nine months ended September 30, 2002, we made net plant additions of
$1,310 million. The majority of these additions, $792 million, primarily related
to Power for developing the Lawrenceburg, Indiana, Waterford, Ohio and
Bethlehem, NY (Albany) sites and adding capacity to the Bergen and Linden
stations in New Jersey. In addition, PSE&G had net plant additions of $322
million related to improvements in its transmission and distribution system, gas
system and common facilities. Also, Energy Holdings' subsidiaries made
investments totaling approximately $390 million for the nine months ended
September 30, 2002, respectively. These investments include an approximate 50%
interest of a coal-fired generation facility, currently under construction in
Poland, and additional investments in existing generation and distribution
facilities and projects by Global and investment in capital leases by Resources.
Partially offsetting these investments was an $88 million loan repayment from
TIE. For a discussion of the loans to TIE, see Note 12. Related Party
Transactions. The $1,310 million of net plant additions and $390 million of
investments were included in our forecasted expenditures for the year.
Long-Term Debt Maturities
The following table summarizes recourse and non-recourse expected debt payments
for the fourth quarter of 2002 and subsequent years. Payments for PSE&G
Transition Funding LLC are based on expected payment dates rather than final
maturity dates.
2002 2003 2004 2005 Thereafter
------ ------ ------ ------ ----------
(Millions)
Power ................... $ -- $ -- $ -- $ -- $2,515
Energy Holdings* ........ 30 252 289 -- 1,472
PSE&G ................... -- 300 286 125 2,214
PSE&G Transition
Funding LLC ........... 35 129 138 146 1,940
Non-recourse project
financing ............. 32 45 30 835 571
------ ------ ------ ------ ------
Total ............... $ 97 $ 726 $ 743 $1,106 $8,712
====== ====== ====== ====== ======
* The $282 million of maturities in 2002 and 2003 at Energy Holdings
represents the total remaining maturities under the PSEG Capital
Corporation program, $30 million of which matured in October 2002, and
$252 million of which matures in May 2003.
ACCOUNTING MATTERS
For a discussion of SFAS 142, SFAS 143, SFAS 144, SFAS 145, SFAS 146 and EITF
02-03, see Note 2. Recent Accounting Pronouncements.
SFAS 87 - "Employers' Accounting for Pensions"
SFAS 87 requires a pension plan sponsor to recognize an additional minimum
pension liability to the extent that its accumulated benefit obligation under
any of its pension plans exceeds the fair market value of its plan assets as of
its annual measurement date. This additional minimum pension liability
represents the amount by which its unfunded accumulated benefit obligation
exceeds the fair market value of the plan's assets, and is partially offset by
an intangible asset no larger than the unrecognized net transition obligation
and prior service cost, with no impact to earnings. At this time, we are
monitoring the fair market value of our investments and our accumulated benefit
obligation and are evaluating options available to us with respect to this
issue. Since our measurement date is December 31, 2002 we are unable to predict
what the impact could be, however the impact could be material to our financial
position and, more specifically, could result in a decrease in equity.
52
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", "forecast", "projections" 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 if our operating performance or cash flow from minority interests
falls below projected levels, we may not be able to service our
debt;
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;
o power transmission facilities may impact our ability to deliver our
output to customers;
o regulatory issues significantly impact 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;
o changes in technology may make our power generation assets less
competitive; and
o recession, acts of war or terrorism could have an adverse impact.
Consequently, all of the forward-looking statements made in this report are
qualified by these cautionary statements and we cannot assure you that the
results or developments anticipated by us will be realized, or even if realized,
will have the expected consequences to, or effects on us or our business
prospects, financial condition or results of operations. You should not place
undue reliance on these forward-looking statements in making any investment
decision. We expressly disclaim any obligation or undertaking to release
publicly any updates or revisions to these forward-looking statements to reflect
events or circumstances that occur or arise or are anticipated to occur or arise
after the date hereof. In making any investment decision regarding our
securities, we are not making, and you should not infer, any representation
about the likely existence of any particular future set of facts or
circumstances. The forward-looking statements contained in this report are
intended to qualify for the safe harbor provisions of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange
Act of 1934, as amended.
53
ITEM 3. 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.
Commodity Contracts
The measured VAR using a variance/co-variance model with a 95% confidence level
and assuming a one-week time horizon as of September 30, 2002 was approximately
$19 million, compared to the December 31, 2001 level of $18 million.
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.
Power
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. As of September 30, 2002 over 97% of
the credit exposure (mark to market plus net receivables and payables) for
Power's trading operations was with investment grade counterparties. As of
September 30, 2002, Power's trading operations had over 145 active
counterparties.
As a result of the New Jersey BGS auction, Power has contracted to provide
energy to the direct suppliers of New Jersey electric utilities, including
PSE&G, commencing August 1, 2002. Subsequently, a portion of the contracts with
those bidders was reassigned to Power. Therefore, for a limited portion of the
New Jersey retail load, Power will be a direct supplier to one utility, although
this utility is not PSE&G. These bilateral contracts are subject to credit risk.
This risk is substantially higher than the risk that was associated with
potential nonpayment by PSE&G under the BGS contract which expired on July 31,
2002, since PSE&G is a rate-regulated entity. This credit risk relates to the
ability of counterparties to meet their payment obligations for the power
delivered under each BGS contract. Power sells electricity to approximately nine
supplier-counterparties that serve the load of the utilities, and one utility
directly. Four of these supplier-counterparties pay Power directly, and one of
the four prepays its purchases. The revenue from the remaining five
counterparties is paid directly from the utilities that those suppliers serve,
and the related margin due to the counterparties is recorded as a liability and
will be remitted to those counterparties separately. Any failure to collect
these payments under the new BGS contracts could have a material impact on
Power's results of operations, cash flows and financial position.
Energy Holdings
Resources also has credit risk related to its investments in leveraged leases,
totaling $1.6 billion, which is net of deferred taxes of $1.4 billion, as of
September 30, 2002. These investments are significantly concentrated in the
54
energy related industry and have some exposure to the airline industry.
Resources is the lessor of domestic generating facilities in several US energy
markets. As a result of recent actions of the rating agencies due to concerns
over forward energy prices, the credit of some of the transaction lessees, or
ultimate guarantors of the lease obligations, was downgraded. As of September
30, 2002, 75% of the lease portfolio were with counterparties that were
investment grade as rated by both S&P and Moody's, as compared to 86% at June
30, 2002. Specifically, the lessees in the following transactions were
downgraded over the quarter by the rating agencies. Resources' investment in
such transactions was approximately $451 million, net of deferred taxes of $266
million as of September 30, 2002.
Resources leases 1,173 MW of coal-fired generation to Reliant Energy Mid
Atlantic Power Holdings LLC (REMA), an indirect wholly-owned subsidiary of
Reliant Resources Incorporated (RRI). The leased assets are the Keystone,
Conemaugh and Shawville generating facilities located in the Pennsylvania New
Jersey Maryland Power Pool (PJM) West market in Pennsylvania. In addition to the
leased assets, REMA also owns and operates another 2,830 MW located within PJM.
REMA is capitalized with over $1 billion of equity from RRI and has no debt
obligations senior to the lease obligations. REMA is currently rated BB+ by S&P,
and Baa3 by Moody's. As the lessor/equity participant in the lease, Resources is
protected with significant lease covenants that restrict the flow of dividends
from REMA to its parent, and by over-collateralization of REMA with an
additional 2,830 MWs of non-leased assets, transfer of which is restricted by
the financing documents. Restrictive covenants include historical and forward
cash flow coverage tests that prohibit discretionary capital expenditures and
dividend payments to the parent/lessee if stated minimum coverages are not met,
and similar cash flow restrictions if ratings are not maintained at stated
levels. The covenants are designed to maintain cash reserves in the transaction
entity for the benefit of the non-recourse lenders and the lessor/equity
participants in the event of a market downturn, or degradation in operating
performance of the leased assets. Resources' investment in the REMA transaction
was $125 million, net of deferred taxes of $88 million at September 30, 2002.
Resources is the lessor of the Collins facility to Midwest Generation LLC
(Midwest), an indirect subsidiary of Edison Mission Energy (EME). Collins is
comprised of 2,698 MWs of oil and natural gas fired assets located in the MAIN
power market located in the mid-western region of the United States. Midwest has
a contract with Exelon to supply capacity and energy for 1,078 MWs for Collins
through December 2003 with an option to extend. Both Midwest and EME are rated
BBB- by S&P and Ba3 by Moody's. In addition to the leased assets, Midwest owns
and operates an additional 4,459 MWs of generation assets. The restrictive
covenants protecting us are similar to those noted above in the REMA
transaction. Resources' investment in the Collins facility was $108 million, net
of deferred taxes of $69 million at September 30, 2002.
Resources also leases the Powerton and Joliet generating stations located in the
Mid-American Interconnected Network (MAIN) market to Midwest. Both Powerton and
Joliet are coal fired stations comprising 2,896 MWs of generating capacity. The
lease obligations are guaranteed by EME. The guarantee contains certain
restrictive covenants including, but not limited to, additional investment,
liens, and sales of non-leased collateral. In addition, EME is required to
maintain a minimum net worth equal to $400 million plus cumulative, consolidated
net income earned by it and its subsidiaries since 1992 (without subtracting
losses). Resources' investment in the Powerton and Joliet transaction was $87
million, net of deferred taxes of $74 million at September 30, 2002.
Resources is the lessor of the 370 MW coal fired Danskammer plant to Dynegy
Danskammer LLC (Danskammer), and the 1,200 MW natural gas/oil fired Roseton
plant to Dynegy Roseton LLC (Roseton). Both Danskammer and Roseton are indirect
subsidiaries of Dynegy Holdings Inc (DHI). The lease obligations are guaranteed
by DHI which is currently rated B+ by S&P and B3 by Moody's. Resources'
investment in the Danskammer and Roseton transaction was $131 million, net of
deferred taxes of $34 million as of September 30, 2002.
In the domestic lease transactions described above, Resources has protected its
equity investment by providing for the right to assume the debt obligation at
its discretion in the event of default by the lessee with the condition that the
debt is investment grade. If we were pursuing a debt assumption, we would first
seek to renegotiate all relevant terms of the agreement with the lenders. Debt
assumption normally only would occur if an appraisal of the leased property
yielded a value that
55
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. As of September 30, 2002, Resources determined
that the collectibility of the minimum lease payments under its leveraged lease
investments is still reasonably predictable and therefore continues to account
for these investments as leveraged leases.
Resources has leasehold interests in the 340 MW natural gas fired Kings Lynn
generating facility and the 360 MW natural gas fired Peterborough generating
facility located in the United Kingdom. The counter-party is an indirect
subsidiary of TXU Europe, which is wholly owned by the TXU Corporation. The TXU
Corporation recently announced their decision to reduce their financial
commitment to TXU Europe further noting their intention to sell the subsidiary.
Moody's recently reduced their ratings to Ca citing that the entity is not
meeting its financial commitments to suppliers or creditors when due. Our lease
transactions are secured, and we believe that in any event of default, we will
be able to recover our lease investment which totals $65 million, net of
deferred taxes of $109 million as of September 30, 2002, although no assurances
can be given.
Foreign Operations
As of September 30, 2002, Global and Resources had approximately $2.870 billion
and $1.425 billion, respectively, of international assets. As of September 30,
2002, foreign assets represented 17% of our consolidated assets and the revenues
related to those foreign assets contributed 6% to consolidated revenues for the
quarter and nine months ended September 30, 2002. For discussion of foreign
currency risk and asset impairments related to our investments in Argentina, see
Note 3. Asset Impairments, Note 6. Commitments and Contingent Liabilities and
Note 7. Financial Instruments, Energy Trading and Risk Management.
ITEM 4. DISCLOSURE CONTROLS AND PROCEDURES
We have has established and maintained disclosure controls and procedures which
are designed to provide reasonable assurance that material information relating
to us, including our consolidated subsidiaries, is made known to us by others
within those entities, particularly during the period in which this quarterly
report is being prepared. We have 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
quarterly report (the "Evaluation Date"). Based on this evaluation, we have
concluded that our disclosure controls and procedures were effective in
providing reasonable assurance during the period covered in this quarterly
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.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Certain information reported under Item 3 of Part I of our 2001 Annual Report on
Form 10-K, Amended Quarterly Report on Form 10-Q/A for the quarter ended March
31, 2002 and Form 10-Q for the quarter ended June 30, 2002 is updated below.
March 31, 2002 Form 10-Q/A, Page 44 and June 30, 2002 Form 10-Q, Page 55. On
November 15, 2001, Consolidated Edison, Inc. (Con Edison) filed a complaint
against PSE&G at FERC pursuant to Section 206 of the Federal Power Act asserting
that PSE&G had breached agreements covering 1,000 MW of transmission by
curtailing service and failing to maintain sufficient system capacity to satisfy
all of its service obligations. PSE&G denied the allegations set forth in the
complaint. While finding that Con Edison's presentation of evidence failed to
demonstrate several of the allegations in April 2002, FERC found sufficient
reason to set the complaint for hearing. An initial decision issued by an
administrative law judge in April 2002 upheld PSE&G's claim that the contracts
do not require the provision of "firm" transmission service to Con Edison but
also accepted Con Edison's contentions that PSE&G was obligated to provide
service to Con Edison utilizing all the facilities comprising its electrical
system including generation facilities and that PSE&G was financially
responsible for above-market generation costs needed to effectuate the desired
power flows. Under FERC procedures, an administrative law judge initial decision
is not binding unless and until its findings have been approved by FERC. PSE&G
filed a brief taking exception to the adverse findings of the April 25, 2002
order. A FERC decision concerning the findings of the April 25, 2002 order was
expected on July 31, 2002. Settlement discussions between the companies with
respect to this matter have been on-going and, on July 17, 2002, representatives
of the companies met for settlement discussions mediated by a FERC
administrative law judge. Based on progress made at these and subsequent
discussions, Con Edison has twice sought to extend the date for the issuance of
the FERC decision addressing the April 25, 2002 initial decision and to extend
the date for the commencement of a hearing with respect to issues in the case
not addressed by the April 25,
56
2002 initial decision. At present, in the event the dispute is not settled, the
FERC decision is expected in mid-November, 2002 and the hearing before the
administrative law judge will commence in early December 2002. The findings in
the April 25, 2002 initial decision notwithstanding, PSE&G believes it has
complied with the terms of the Agreements and will vigorously defend its
position. The nature and cost of any remedy, which is expected to be prospective
only, cannot be predicted. Further, even in the event settlement is reached with
Con Edison, PSE&G could still be required to bear substantial levels of
additional costs. Docket No. EL02-23-000.
June 30, 2002 Form 10-Q, Page 56. On July 12, 2002, the United States Court of
Appeals, D.C. Circuit, issued an opinion in favor of PSE&G and the other utility
petitioners, reversing an order of the FERC relating to the restructuring of PJM
into an Independent System Operator. The Court agreed with PSE&G's position and
ruled that FERC lacks authority to require the utility owners to give up their
statutory rights under Section 205 of the Federal Power Act. Hence, FERC was
wrong to require a modification to the PJM ISO Agreement eliminating their
rights to file changes to rate design. The court further noted that FERC lacks
authority under Section 203 of the Federal Power Act to require the utility
owners to obtain approval of their withdrawal from the PJM ISO. Hence, FERC had
no right under Section 203 to eliminate the withdrawal rights to which the
utilities had agreed. Further, in ruling on a specific argument raised by PSE&G,
the Court held that FERC had not justified its decision to generically abrogate
wholesale power requirements contracts; FERC was required to make a
particularized finding with respect to the public interest, which was not done
here. This matter is now pending on remand before the FERC.
In addition, see information on the following proceedings at the pages
indicated:
(1) March 31, 2002 Form 10-Q/A, Pages 11-13 and June 30, 2002 Form 10-Q,
Page 9-10. See Page 10. AES termination of the Stock Purchase
Agreement, relating to the sale of certain Argentine assets. New
York State Supreme Court for New York County. PSEG Global, et al vs.
The AES Corporation, et al. Docket No. 60155/2002.
(2) Form 10-K, Page 100, March 31, 2002 Form 10-Q/A, Page 8 and June 30,
2002 Form 10-Q, Page 18. See Page 16. PSE&G's MGP Remediation
Program.
(3) Form 10-K, Page 100, March 31, 2002 Form 10-Q/A, Page 8-9 and June
30, 2002 Form 10-Q, Page 19. See Page 16. Investigation and
additional investigation by the EPA regarding the Passaic River
site. Docket No. EX93060255.
(4) Form 10-K, Page 102, March 31, 2002 Form 10-Q/A, Page 10-11 and June
30, 2002 Form 10-Q, Page 22. See Page 19. Complaint filed with the
FERC addressing contract terms of certain Sellers of Energy and
Capacity under Long-Term Contracts with the California Department of
Water Resources. Public Utilities Commission of the State of
California v. Sellers of Long Term Contracts to the California
Department of Water Resources FERC Docket No. EL02-60-000.
California Electricity Oversight Board v. Sellers of Energy and
Capacity Under Long-Term Contracts with the California Department of
Water Resources FERC Docket No. EL02-62-000.
(5) Form 10-K, Pages 26 and 27 and June 30, 2002 Form 10-Q, Page 55. See
Page 18. DOE not taking possession of spent nuclear fuel, Docket No.
01-551C.
(6) Form 10-K, Pages 26 and 27 and June 30, 2002 Form 10-Q, Page 56. See
Page 18 DOE Overcharges, Docket No. 01-592C.
(7) June 30, 2002 Form 10-Q, Page 59. See Page 58. PSE&G electric rate
case filed with the BPU.
57
ITEM 5. OTHER INFORMATION
Certain information reported under our 2001 Annual Report on Form 10-K, Amended
Quarterly Report on Form 10-Q/A for the quarter ended March 31, 2002 and
Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 is updated
below. References are to the related pages on the Form 10-K, Form 10-Q/A and
Form 10-Q as printed and distributed.
Nuclear Regulatory Commission (NRC)
Form 10-K, page 18 and March 31, 2002 Form 10-Q/A, Page 46. A pressurized water
reactor nuclear unit (PWR) not owned by us was recently identified with a
degradation of the reactor vessel head, which forms part of the pressure
boundary for the reactor coolant system. In August 2002, the NRC issued bulletin
2002-02, requiring that all operators of PWR units submit information
concerning: (i) a summary discussion of the supplemental inspections to be
implemented, and (ii) if no changes are to be implemented, justification for
reliance on visual examinations as the primary method to detect degradation. In
September 2002 we provided the requested information for Salem Nuclear
Generating Station (Salem). The response stated that a bare metal visual
examination will be performed on the Salem reactor vessel heads during each
unit's next refueling outage, in compliance with the bulletin. If repairs are
determined to be necessary, it is estimated that the repair would extend the
outage by approximately four weeks. Our Hope Creek nuclear unit and our
interests in the Peach Bottom units 2 and 3 are unaffected as they are Boiling
Water Reactor nuclear units. We cannot predict what other actions the NRC may
take on this issue.
Electric Base Rate Case
June 30, 2002 Form 10-Q, Page 56. On May 24, 2002, PSE&G filed an electric rate
case with the BPU. In this filing, PSE&G requested an annual $250 million rate
increase for its electric distribution business. The proposed rate increase
includes $187 million of increased revenues relating to a $1.7 billion increase
in PSE&G's rate base, which is primarily due to the investment that PSE&G has
made in its electric distribution facilities since the last rate case in 1992;
$18 million in higher depreciation rates and $45 million to recover various
other expenses, such as wages, fringe benefits, and the need to enhance the
security and reliability of the electric distribution system. The requested
increase proposes a return on equity of 11.75% for PSE&G's electric distribution
business.
Assuming current cost levels and a normal business environment, the proposed
rate increase would significantly impact our earnings and operating cash flows.
The non-depreciation portion of the rate increase ($232 million) would have a
positive effect on our earnings and operating cash flows. The depreciation
portion of the rate increase ($18 million) would have no impact on our earnings,
as the increased operating cash flows would be offset by higher depreciation
charges.
In accordance with BPU's Final Order, which implemented parts of New Jersey's
Electric Discount and Competition Act, PSE&G was required to reduce electric
rates in four steps totaling 13.9% during the four year transition period. The
last step, a 4.9% decrease, took effect on August 1, 2002. If approved, the
proposed rate increase would be effective August 1, 2003, the end of the
transition period. While the proposed rate increase would increase electric
distribution rates by 12.8% from the July 31, 2003 level, rates would remain
2.6% lower than the levels in April 1999, when the BPU issued its Final Order.
We cannot predict the outcome of these rate proceedings at the current time.
As directed by the BPU in its July 22, 2002 Order, on August 28, 2002, PSE&G
filed supplemental testimony to address the use of securitization proceeds and
proceeds from the sale of generation assets. The issue of electronic meters must
also be addressed in a separate filing in an expedited timeframe. We are also
working to resolve the open Service Company filing and its Street Lighting
Tariff. If not resolved, these issues may be consolidated into the rate case.
The electric base rate case is scheduled to be transferred from the Office of
Administrative Law back to the BPU by May 1, 2003. The Ratepayer Advocate and
other parties filed testimony in this case in October 2002 and the case is on
schedule.
58
Standard Market Design Notice of Proposed Rulemaking (NOPR)
Form 10-K, Page 17. On July 31, 2002 the FERC issued a NOPR to create a Standard
Market Design for the wholesale electricity markets in the United States. The
NOPR seeks to improve the consistency of market rules throughout the country,
including issues related to reliability, market power concerns, transmission,
pricing, congestion, governance and other issues. We cannot predict the outcome
of this matter or its impact upon us if adopted, which could significantly
affect transmission and generation in the various markets in which we operate.
Deferral Proceeding
New Matter. In August 2002, PSE&G filed a petition proposing changes to the SBC
and NTC. The proposed result, if adopted, will result in a reduction of revenues
of about $122 million or approximately a 3.4% reduction in amounts paid by
customers effective on August 1, 2003. The case has been transferred to the
Office of Administrative Law.
Deferral Audit
New Matter. In September 2002, the BPU retained the services of two audit firms
to conduct a review of the State's electric utility's deferred costs for
compliance with BPU orders. PSE&G has estimated an overrecovery balance of
approximately $30 million by the end of July 2003.
BGSS Filing
New Matter. In September 2002, PSE&G filed with the BPU to increase its
Residential BGSS Commodity Charge by November 1, 2002 to recover approximately
$89 million in additional revenues ($83 million of which is associated with an
underrecovered balance) or a 7.4% rate increase for the typical residential gas
heating customer.
59
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) A listing of exhibits being filed with this document is as follows:
Exhibit Number Document
- -------------- --------
10 Public Service Enterprise Group Incorporated 1989 Long
Term Inceptive Plan Amended as of October 22, 2002.
12 Computation of Ratios of Earnings to Fixed Charges
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 of Public Service Enterprise Group Incorporated
Pursuant to Section 1350 of Chapter 63 of Title 18 of
the United States Code
(B) Reports on Form 8-K :
Date Form Items
---- ---- -----
October 11, 2002 8-K 5 & 7
September 10, 2002 8-K 5 & 7
July 30, 2002 8-K 5 & 7
July 29, 2002 8-K/A 5 & 7
July 18, 2002 8-K 5 & 7
60
SIGNATURE
Pursuant to the requirements 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
(Registrant)
By: Patricia A. Rado
------------------------
Patricia A. Rado
Vice President and Controller
(Principal Accounting Officer)
Date: November 1, 2002
61
Certification Pursuant to Rules 13a-14 and 15d-14
of the 1934 Securities Exchange Act
I certify that:
1. I have reviewed this quarterly report on Form 10-Q of Public Service
Enterprise Group Incorporated (the registrant);
2. Based on my knowledge, this quarterly 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 quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly 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
quarterly 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
quarterly 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 quarterly report (the "Evaluation Date"); and
c) presented in this quarterly 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
quarterly 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 1, 2002 /s/ E. James Ferland
------------------------- ----------------------------
E. James Ferland
Chief Executive Officer
62
Certification Pursuant to Rules 13a-14 and 15d-14
of the 1934 Securities Exchange Act
I certify that:
1. I have reviewed this quarterly report on Form 10-Q of Public Service
Enterprise Group Incorporated (the registrant);
2. Based on my knowledge, this quarterly 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 quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly 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
quarterly 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
quarterly 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 quarterly report (the "Evaluation Date"); and
c) presented in this quarterly 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
quarterly 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 1, 2002 /s/ Thomas M. O'Flynn
------------------------- ----------------------------
Thomas M. O'Flynn
Chief Financial Officer
63