UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
S QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2006
OR
£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
|
|
|||||||||
|
Commission |
Registrants, State of Incorporation, Address, and Telephone Number |
I.R.S. Employer Identification No. |
|||||||
|
001-09120 |
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
|
22-2625848 | |||||||
|
001-00973 |
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
|
22-1212800 | |||||||
|
000-49614 |
PSEG POWER LLC
|
22-3663480 | |||||||
|
000-32503 |
PSEG ENERGY HOLDINGS L.L.C. (A New Jersey Limited Liability Company) 80 Park Plaza—T20 Newark, New Jersey 07102-4194 973 430-7000 http://www.pseg.com |
42-1544079 | |||||||
Indicate by check mark whether the registrants (1) have 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 registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes S No £
Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the
Exchange Act.
(Check one):
|
Public Service Enterprise Group Incorporated |
Large accelerated filer S | Accelerated filer £ | Non-accelerated filer £ | |||
|
Public Service Electric and Gas Company |
Large accelerated filer £ | Accelerated filer £ | Non-accelerated filer S | |||
|
PSEG Power LLC |
Large accelerated filer £ | Accelerated filer £ | Non-accelerated filer S | |||
|
PSEG Energy Holdings L.L.C. |
Large accelerated filer £ | Accelerated filer £ | Non-accelerated filer S |
Indicate by check mark whether any of the registrants is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £ No S
As of October 31, 2006, Public Service Enterprise Group Incorporated had outstanding 252,203,353 shares of its sole class of Common Stock, without par value.
As of October 31, 2006, Public Service Electric and Gas Company had issued and outstanding 132,450,344 shares of Common Stock, without nominal or par value, all of which were privately held, beneficially and of record by Public Service Enterprise Group Incorporated.
PSEG Power LLC and PSEG Energy Holdings L.L.C. are wholly owned subsidiaries of Public Service Enterprise Group Incorporated and meet the conditions set forth in General Instruction H(1) (a) and (b) of Form 10-Q and are filing their respective Quarterly Reports on Form 10-Q with the reduced disclosure format authorized by General Instruction H.
TABLE OF CONTENTS Financial
Statements
Note 3.
Discontinued Operations, Dispositions and Acquisitions Management’s
Discussion and Analysis of Financial Condition and Results of Operations
(MD&A) Qualitative
and Quantitative Disclosures About Market Risk Controls
and Procedures Legal
Proceedings Other
Information Exhibits i
Page
ii
1
5
9
13
17
19
22
24
25
39
42
43
44
46
47
48
52
55
57
58
58
58
63
72
78
78
78
79
83
84
85
94
95
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 “anticipate,” “intend,” “estimate,” “believe,” “expect,” “plan,” “hypothetical,” “potential,” “forecast,” “project,” variations of
such words and similar expressions are intended to identify forward-looking statements. Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG
Power LLC (Power) and PSEG Energy Holdings L.L.C. (Energy Holdings) 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 should not be construed as a complete list of factors that could affect forward-looking statements. In addition to any assumptions and other factors referred
to specifically in connection with such forward-looking statements discussed above, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements
include, among others, the following: • ability to attain satisfactory regulatory results; • operating performance or cash flow from investments falling below projected levels; • credit, commodity, interest rate, counterparty and other financial market risks; • liquidity and the ability to access capital and maintain adequate credit ratings; • adverse or unanticipated weather conditions that significantly impact costs and/or operations, including generation; • ability to implement successful succession planning, attract and retain management and other key employees; • changes in the electric industry, including changes to power pools; • changes in energy policies and regulation; • changes in demand; • changes in the number of market participants and the risk profiles of such participants; • availability of power transmission facilities that impact the ability to deliver output to customers; • growth in costs and expenses; • environmental regulations that significantly impact operations; • changes in rates of return on overall debt and equity markets that could adversely impact the value of pension and other postretirement benefits assets and liabilities and the Nuclear
Decommissioning Trust Funds; • changes in political conditions, recession, acts of war or terrorism; • changes in technology that make generation, transmission and/or distribution assets less competitive; • continued availability of insurance coverage at commercially reasonable rates; • involvement in lawsuits, including liability claims and commercial disputes; • acquisitions, divestitures, mergers, restructurings or strategic initiatives that change PSEG’s, PSE&G’s, Power’s and Energy Holdings’ strategy or structure; • business combinations among competitors and major customers; • general economic conditions, including inflation or deflation; • changes in tax laws and regulations; • changes to accounting standards or accounting principles generally accepted in the U.S., which may require adjustments to financial statements; ii
•
regulatory issues that significantly impact operations;
• ability to recover investments or service debt as a result of any of the risks or uncertainties mentioned herein; PSEG, PSE&G and Energy Holdings PSEG, Power and Energy Holdings • inability to meet generation operating performance expectations; • energy transmission constraints or lack thereof; • adverse changes in the market for energy, capacity, natural gas, emissions credits, congestion credits and other commodity prices, especially during significant price movements for natural gas
and power; • adverse market developments or changes in market rules, including delays or impediments to implementation of reasonable capacity markets; • surplus of energy capacity and excess supply; • substantial competition in the domestic and worldwide energy markets; • margin posting requirements, especially during significant price movements for natural gas and power; • availability of fuel and timely transportation at reasonable prices; • effects on competitive position of actions involving competitors or major customers; • changes in product or sourcing mix; • delays, cost escalations or unsuccessful construction and development; • delay in market rules; PSEG and Power • ability to maintain nuclear operating performance at projected levels; PSEG and Energy Holdings • deterioration in the credit of lessees and their ability to adequately service lease rentals; • ability to realize tax benefits; • changes in political regimes in foreign countries; and • international developments negatively impacting business. Consequently, all of the forward-looking statements made in this report are qualified by these cautionary statements and PSEG, PSE&G, Power and Energy Holdings cannot assure you that the results or
developments anticipated by management will be realized, or even if realized, will have the expected consequences to, or effects on, PSEG, PSE&G, Power and Energy Holdings or their respective business
prospects, financial condition or results of operations. Undue reliance should not be placed on these forward-looking statements in making any investment decision. Each of PSEG, PSE&G, Power and
Energy Holdings expressly disclaims 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 PSEG’s, PSE&G’s, Power’s and Energy Holdings’ securities, PSEG, PSE&G, Power and Energy Holdings
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. iii
•
ability to obtain adequate and timely rate relief;
•
inability to effectively manage portfolios of electric generation assets, gas supply contracts and electric and gas supply obligations;
•
changes in regulation and safety and security measures at nuclear facilities;
•
changes in foreign currency exchange rates;
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED OPERATING REVENUES OPERATING EXPENSES Energy Costs Operation and Maintenance Write-down of Project Investments Depreciation and Amortization Taxes Other Than Income Taxes Total Operating Expenses Income from Equity Method Investments OPERATING INCOME Other Income Other Deductions Interest Expense Preferred Stock Dividends INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES Income Tax Expense INCOME FROM CONTINUING OPERATIONS (Loss) Income from Discontinued Operations, including Gain (Loss) on Disposal, net of tax expense (benefit) of $0, $0, $142, and ($138) for the
quarter and nine months ended 2006 and 2005, respectively NET INCOME WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS): BASIC DILUTED EARNINGS PER SHARE: BASIC INCOME FROM CONTINUING OPERATIONS NET INCOME DILUTED INCOME FROM CONTINUING OPERATIONS NET INCOME DIVIDENDS PAID PER SHARE OF COMMON STOCK See Notes to Condensed Consolidated Financial Statements. 1
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For the Quarters Ended
September 30,
For the Nine Months Ended
September 30,
2006
2005
2006
2005
(Millions)
(Unaudited)
$
3,392
$
3,324
$
9,516
$
8,940
1,809
1,979
5,400
5,144
541
537
1,705
1,661
—
—
263
—
234
204
645
562
32
34
100
105
2,616
2,754
8,113
7,472
30
30
93
90
806
600
1,496
1,558
51
92
153
169
(44
)
(31
)
(91
)
(66
)
(209
)
(208
)
(617
)
(606
)
(1
)
(1
)
(3
)
(3
)
603
452
938
1,052
(229
)
(183
)
(379
)
(412
)
374
269
559
640
—
(16
)
227
(184
)
$
374
$
253
$
786
$
456
251,747
239,034
251,471
238,696
252,329
244,286
252,161
243,212
$
1.48
$
1.12
$
2.22
$
2.68
$
1.48
$
1.06
$
3.12
$
1.91
$
1.48
$
1.10
$
2.22
$
2.63
$
1.48
$
1.03
$
3.12
$
1.87
$
0.57
$
0.56
$
1.71
$
1.68
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED ASSETS CURRENT ASSETS Cash and Cash Equivalents Accounts Receivable, net of allowances of $45 and $44 in 2006 and 2005, respectively Unbilled Revenues Fuel Materials and Supplies Energy Trading Contracts Prepayments Restricted Funds Derivative Contracts Assets of Discontinued Operations Assets Held for Sale Other Total Current Assets PROPERTY, PLANT AND EQUIPMENT Less: Accumulated Depreciation and Amortization Net Property, Plant and Equipment NONCURRENT ASSETS Regulatory Assets Long-Term Investments Nuclear Decommissioning Trust (NDT) Funds Other Special Funds Goodwill and Other Intangibles Energy Trading Contracts Derivative Contracts Other Total Noncurrent Assets TOTAL ASSETS See Notes to Condensed Consolidated Financial Statements. 2
CONDENSED CONSOLIDATED BALANCE SHEETS
September 30,
2006
December 31,
2005
(Millions)
(Unaudited)
$
292
$
288
1,337
1,936
222
394
853
812
311
277
62
327
224
129
98
76
37
50
—
498
21
—
37
41
3,494
4,828
19,634
18,896
(5,950
)
(5,560
)
13,684
13,336
5,028
5,053
3,890
4,077
1,191
1,133
569
559
597
608
19
42
59
—
183
177
11,536
11,649
$
28,714
$
29,813
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year Commercial Paper and Loans Accounts Payable Derivative Contracts Energy Trading Contracts Accrued Interest Accrued Taxes Clean Energy Program Liabilities of Discontinued Operations Other Total Current Liabilities NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC) Regulatory Liabilities Asset Retirement Obligations Other Postretirement Benefit (OPEB) Costs Clean Energy Program Environmental Costs Derivative Contracts Energy Trading Contracts Other Total Noncurrent Liabilities COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) CAPITALIZATION LONG-TERM DEBT Long-Term Debt Securitization Debt Project Level, Non-Recourse Debt Debt Supporting Trust Preferred Securities Total Long-Term Debt SUBSIDIARIES’ PREFERRED SECURITIES Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2006 and 2005—795,234 shares COMMON STOCKHOLDERS’ EQUITY Common Stock, no par, authorized 500,000,000 shares; issued; 2006—266,123,571 shares; 2005—265,332,746 shares Treasury Stock, at cost; 2006—14,024,505 shares; 2005—14,169,560 shares Retained Earnings Accumulated Other Comprehensive Loss Total Common Stockholders’ Equity Total Capitalization TOTAL LIABILITIES AND CAPITALIZATION See Notes to Condensed Consolidated Financial Statements. 3
CONDENSED CONSOLIDATED BALANCE SHEETS
September 30,
2006
December 31,
2005
(Millions)
(Unaudited)
$
672
$
1,536
555
100
806
1,154
186
425
237
200
191
152
112
141
114
96
—
436
430
515
3,303
4,755
4,646
4,248
668
720
618
585
632
597
160
233
396
420
214
637
40
19
263
218
7,637
7,677
7,436
7,849
1,758
1,879
855
891
660
660
10,709
11,279
80
80
4,644
4,618
(527
)
(532
)
2,901
2,545
(33
)
(609
)
6,985
6,022
17,774
17,381
$
28,714
$
29,813
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CASH FLOWS FROM OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: (Gain) Loss on Disposal of Discontinued Operations, net of tax Gain on Disposition of Property, Plant and Equipment Write-Down of Project Investments Depreciation and Amortization Amortization of Nuclear Fuel Provision for Deferred Income Taxes (Other than Leases) and ITC Non-Cash Employee Benefit Plan Costs Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes Loss (Gain) on Sale of Investments Undistributed Earnings from Affiliates Foreign Currency Transaction Loss (Gain) Unrealized (Gains) Losses on Energy Contracts and Other Derivatives Over Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs Under Recovery of Societal Benefits Charge (SBC) Net Realized Gains and Income from NDT Funds Other Non-Cash Charges Net Change in Certain Current Assets and Liabilities Employee Benefit Plan Funding and Related Payments Proceeds from the Withdrawal of Partnership Interests and Other Distributions Other Net Cash Provided By Operating Activities CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment Proceeds from Collection of Notes Receivable Proceeds from Sale of Discontinued Operations Proceeds from Sale of Property, Plant and Equipment Proceeds from the Sale of Investments and Return of Capital from Partnerships Proceeds from NDT Funds Sales Investment in NDT Funds Restricted Funds NDT Funds Interest and Dividends Other Net Cash Used In Investing Activities CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Commercial Paper and Loans Issuance of Long-Term Debt Issuance of Non-Recourse Debt Issuance of Common Stock Redemptions of Long-Term Debt Repayment of Non-Recourse Debt Redemption of Debt Underlying Trust Securities Cash Dividends Paid on Common Stock Other Net Cash Used In Financing Activities Effect of Exchange Rate Change Net Increase in Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period Supplemental Disclosure of Cash Flow Information: Income Taxes Paid Interest Paid, Net of Amounts Capitalized See Notes to Condensed Consolidated Financial Statements. 4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For The Nine Months
Ended
September 30,
2006
2005
(Millions)
(Unaudited)
$
786
$
456
(228
)
178
(1
)
(5
)
—
22
645
572
73
69
(5
)
155
178
175
32
9
255
(50
)
(45
)
(40
)
4
(1
)
(47
)
4
112
75
(89
)
(94
)
(54
)
(94
)
25
26
73
(439
)
(127
)
(159
)
7
63
(150
)
(19
)
1,444
903
(748
)
(751
)
—
132
494
220
3
6
186
26
1,056
2,751
(1,069
)
(2,769
)
(22
)
(47
)
29
25
18
13
(53
)
(394
)
452
(267
)
—
728
—
4
56
55
(1,246
)
(230
)
(37
)
(20
)
(154
)
—
(430
)
(401
)
(26
)
(42
)
(1,385
)
(173
)
(2
)
1
4
337
288
263
$
292
$
600
$
312
$
102
$
510
$
618
PUBLIC SERVICE ELECTRIC AND GAS COMPANY OPERATING REVENUES OPERATING EXPENSES Energy Costs Operation and Maintenance Depreciation and Amortization Taxes Other Than Income Taxes Total Operating Expenses OPERATING INCOME Other Income Other Deductions Interest Expense INCOME BEFORE INCOME TAXES Income Tax Expense NET INCOME Preferred Stock Dividends EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED See disclosures regarding Public Service Electric and Gas Company 5
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For The Quarters Ended
September 30,
For The Nine Months Ended
September 30,
2006
2005
2006
2005
(Millions)
(Unaudited)
$
2,017
$
1,934
$
5,901
$
5,559
1,296
1,195
3,872
3,472
278
276
855
839
174
155
476
418
32
35
100
106
1,780
1,661
5,303
4,835
237
273
598
724
6
3
18
7
—
(1
)
(2
)
(2
)
(86
)
(86
)
(254
)
(256
)
157
189
360
473
(69
)
(74
)
(160
)
(191
)
88
115
200
282
(1
)
(1
)
(3
)
(3
)
$
87
$
114
$
197
$
279
included in the Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY ASSETS CURRENT ASSETS Cash and Cash Equivalents Accounts Receivable, net of allowances of $42 in 2006 and $41 in 2005 Unbilled Revenues Materials and Supplies Prepayments Restricted Funds Other Total Current Assets PROPERTY, PLANT AND EQUIPMENT Less: Accumulated Depreciation and Amortization Net Property, Plant and Equipment NONCURRENT ASSETS Regulatory Assets Long-Term Investments Other Special Funds Other Total Noncurrent Assets TOTAL ASSETS See disclosures regarding Public Service Electric and Gas Company 6
CONDENSED CONSOLIDATED BALANCE SHEETS
September 30,
2006
December 31,
2005
(Millions)
(Unaudited)
$
76
$
159
770
959
222
394
49
49
151
49
15
14
33
32
1,316
1,656
11,023
10,636
(3,827
)
(3,627
)
7,196
7,009
5,028
5,053
147
144
310
315
117
114
5,602
5,626
$
14,114
$
14,291
included in the Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year Commercial Paper and Loans Accounts Payable Accounts Payable—Affiliated Companies, net Accrued Interest Clean Energy Program Derivative Contracts Other Total Current Liabilities NONCURRENT LIABILITIES Deferred Income Taxes and ITC Other Postretirement Benefit (OPEB) Costs Regulatory Liabilities Clean Energy Program Environmental Costs Asset Retirement Obligations Derivative Contracts Other Total Noncurrent Liabilities COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) CAPITALIZATION LONG-TERM DEBT Long-Term Debt Securitization Debt Total Long-Term Debt PREFERRED SECURITIES Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2006 and 2005—795,234 shares COMMON STOCKHOLDER’S EQUITY Common Stock; 150,000,000 shares authorized, 132,450,344 shares issued and outstanding Contributed Capital Basis Adjustment Retained Earnings Accumulated Other Comprehensive Loss Total Common Stockholder’s Equity Total Capitalization TOTAL LIABILITIES AND CAPITALIZATION See disclosures regarding Public Service Electric and Gas Company 7
CONDENSED CONSOLIDATED BALANCE SHEETS
September 30,
2006
December 31,
2005
(Millions)
(Unaudited)
$
282
$
485
327
—
290
286
403
391
41
59
114
96
9
6
269
370
1,735
1,693
2,523
2,608
586
561
668
720
160
233
341
365
218
210
23
6
27
27
4,546
4,730
2,754
2,866
1,758
1,879
4,512
4,745
80
80
892
892
170
170
986
986
1,197
1,000
(4
)
(5
)
3,241
3,043
7,833
7,868
$
14,114
$
14,291
included in the Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY CASH FLOWS FROM OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization Provision for Deferred Income Taxes and ITC Non-Cash Employee Benefit Plan Costs Non-Cash Interest Expense Employee Benefit Plan Funding and Related Payments Over Recovery of Electric Energy Costs (BGS and NTC) Over (Under) Recovery of Gas Costs Under Recovery of SBC Other Non-Cash Charges Net Changes in Certain Current Assets and Liabilities: Accounts Receivable and Unbilled Revenues Materials and Supplies Prepayments Accrued Taxes Accrued Interest Accounts Payable Accounts Receivable/Payable-Affiliated Companies, net Other Current Assets and Liabilities Other Net Cash Provided By Operating Activities CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment Restricted Funds Net Cash Used In Investing Activities CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Debt Issuance of Long-Term Debt Redemption of Securitization Debt Redemption of Long-Term Debt Issuance of Securitization Debt Deferred Issuance Costs Preferred Stock Dividends Net Cash (Used In) Provided by Financing Activities Net (Decrease) Increase In Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period Supplemental Disclosure of Cash Flow Information: Income Taxes Paid Interest Paid, Net of Amounts Capitalized See disclosures regarding Public Service Electric and Gas Company 8
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For The Nine Months Ended
September 30,
2006
2005
(Millions)
(Unaudited)
$
200
$
282
476
418
(69
)
(77
)
127
124
14
13
(81
)
(104
)
39
81
73
(6
)
(89
)
(94
)
6
3
361
74
—
(7
)
(102
)
(91
)
(25
)
(21
)
(18
)
(16
)
4
70
(337
)
(207
)
(77
)
102
(79
)
(80
)
423
464
(392
)
(372
)
(1
)
(3
)
(393
)
(375
)
327
80
—
250
(115
)
(105
)
(322
)
(125
)
—
103
—
(3
)
(3
)
(3
)
(113
)
197
(83
)
286
159
6
$
76
$
292
$
187
$
249
$
251
$
250
included in the Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC OPERATING REVENUES OPERATING EXPENSES Energy Costs Operation and Maintenance Depreciation and Amortization Total Operating Expenses OPERATING INCOME Other Income Other Deductions Interest Expense INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES Income Tax Expense INCOME FROM CONTINUING OPERATIONS Loss from Discontinued Operations, net of tax benefit of $4 and $13 for the quarter and nine months ended 2005, respectively Loss on Disposal of Discontinued Operations, net of tax benefit of $0 and $123 for the quarter and nine months ended 2005, respectively EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED See disclosures regarding PSEG Power LLC 9
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For The Quarters
Ended
September 30,
For The Nine Months
Ended
September 30,
2006
2005
2006
2005
(Millions)
(Unaudited)
$
1,489
$
1,444
$
4,591
$
4,234
830
983
2,992
2,941
222
223
721
685
41
34
116
96
1,093
1,240
3,829
3,722
396
204
762
512
38
74
113
135
(27
)
(13
)
(60
)
(33
)
(47
)
(32
)
(131
)
(86
)
360
233
684
528
(155
)
(101
)
(290
)
(225
)
205
132
394
303
—
(6
)
—
(19
)
—
(1
)
—
(178
)
$
205
$
125
$
394
$
106
included in the Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC ASSETS CURRENT ASSETS Cash and Cash Equivalents Accounts Receivable Accounts Receivable—Affiliated Companies, net Fuel Materials and Supplies Energy Trading Contracts Derivative Contracts Other Total Current Assets PROPERTY, PLANT AND EQUIPMENT Less: Accumulated Depreciation and Amortization Net Property, Plant and Equipment NONCURRENT ASSETS Deferred Income Taxes and Investment Tax Credits (ITC) Nuclear Decommissioning Trust (NDT) Funds Goodwill and Other Intangibles Other Special Funds Energy Trading Contracts Derivative Contracts Other Total Noncurrent Assets TOTAL ASSETS LIABILITIES AND MEMBER’S EQUITY CURRENT LIABILITIES Long-Term Debt Due Within One Year Accounts Payable Short-Term Loan from Affiliate Energy Trading Contracts Derivative Contracts Accrued Interest Other Total Current Liabilities NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC) Asset Retirement Obligations Energy Trading Contracts Derivative Contracts Environmental Costs Other Total Noncurrent Liabilities COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) LONG-TERM DEBT Total Long-Term Debt MEMBER’S EQUITY Contributed Capital Basis Adjustment Retained Earnings Accumulated Other Comprehensive Loss Total Member’s Equity TOTAL LIABILITIES AND MEMBER’S EQUITY See disclosures regarding PSEG Power LLC 10
CONDENSED CONSOLIDATED BALANCE SHEETS
September 30,
2006
December 31,
2005
(Millions)
(Unaudited)
$
5
$
8
450
862
335
288
852
812
218
201
62
327
15
50
35
27
1,972
2,575
6,694
6,457
(1,698
)
(1,577
)
4,996
4,880
—
70
1,191
1,133
62
63
155
143
19
42
25
—
53
39
1,505
1,490
$
8,473
$
8,945
$
—
$
500
403
745
68
202
237
200
165
403
81
41
83
86
1,037
2,177
271
—
398
373
40
19
167
597
55
55
74
70
1,005
1,114
2,817
2,817
2,000
2,000
(986
)
(986
)
2,704
2,310
(104
)
(487
)
3,614
2,837
$
8,473
$
8,945
included in the Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC CASH
FLOWS FROM OPERATING ACTIVITIES Net
Income Adjustments
to Reconcile Net Income to Net Cash Flows from Operating Activities: Loss
on Disposal of Discontinued operations, net of tax Gain
on Disposition of Property, Plant and Equipment Depreciation
and Amortization Amortization
of Nuclear Fuel Interest
Accretion on Asset Retirement Obligations Provision
for Deferred Income Taxes and ITC Unrealized
Losses (Gains) on Energy Contracts and Other Derivatives Non-Cash
Employee Benefit Plan Costs Net
Realized Gains and Income from NDT Funds Net
Change in Certain Current Assets and Liabilities: Fuel,
Materials and Supplies Accounts
Receivable Accounts
Payable Accounts
Receivable/Payable—Affiliated Companies, net Accrued
Interest Payable Other
Current Assets and Liabilities Employee
Benefit Plan Funding and Related Payments Other Net
Cash Provided By Operating Activities CASH
FLOWS FROM INVESTING ACTIVITIES Additions
to Property, Plant and Equipment Sales
of Property, Plant and Equipment Proceeds
from NDT Funds Sales NDT
Funds Interest and Dividends Investment
in NDT Funds Short-Term
Loan—Affiliated Company, net Other Net
Cash Used In Investing Activities CASH
FLOWS FROM FINANCING ACTIVITIES Redemption
of Long-Term Debt Short-Term
Loan—Affiliated Company, net Net
Cash Used In Financing Activities Net
(Decrease) Increase in Cash and Cash Equivalents Cash
and Cash Equivalents at Beginning of Period Cash
and Cash Equivalents at End of Period Supplemental
Disclosure of Cash Flow Information: Income
Taxes Paid Interest
Paid, Net of Amounts Capitalized See disclosures regarding PSEG Power LLC 11
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For The Nine Months Ended
September 30,
2006
2005
(Millions)
(Unaudited)
$
394
$
106
—
178
(1
)
(5
)
116
96
73
69
25
21
74
239
2
(2
)
35
34
(54
)
(94
)
(57
)
(187
)
412
(89
)
(325
)
(348
)
303
177
39
—
25
61
(34
)
(35
)
(107
)
55
920
276
(316
)
(345
)
1
226
1,056
2,751
29
25
(1,069
)
(2,769
)
—
(62
)
10
5
(289
)
(169
)
(500
)
—
(134
)
(98
)
(634
)
(98
)
(3
)
9
8
10
$
5
$
19
$
200
$
9
$
92
$
62
included in the Notes to Condensed Consolidated Financial Statements.
[THIS PAGE INTENTIONALLY LEFT BLANK]
PSEG ENERGY HOLDINGS L.L.C. OPERATING REVENUES Electric Generation and Distribution Revenues Income from Leveraged and Operating Leases Other Total Operating Revenues OPERATING EXPENSES Energy Costs Operation and Maintenance Write-down of Project Investments Depreciation and Amortization Total Operating Expenses Income from Equity Method Investments OPERATING INCOME Other Income Other Deductions Interest Expense INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND MINORITY INTEREST Income Tax (Expense) Benefit Minority Interests in Earnings of Subsidiaries INCOME FROM CONTINUING OPERATIONS (Loss) Income from Discontinued Operations, net of tax benefit (expense) of $0, $(4), $0 and $2 for the quarter and nine months ended 2006
and 2005, respectively Gain on Disposal of Discontinued Operations, net of tax expense of $142 for the nine months ended 2006 NET INCOME Preference Units Distributions EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED See disclosures regarding PSEG Energy Holdings L.L.C. 13
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
For The Quarters
Ended
September 30,
For The Nine Months
Ended
September 30,
2006
2005
2006
2005
(Millions)
(Unaudited)
$
358
$
280
$
939
$
728
38
44
115
136
5
10
26
53
401
334
1,080
917
195
184
583
484
49
41
150
151
—
—
263
—
14
10
38
35
258
235
1,034
670
30
30
93
90
173
129
139
337
14
5
33
18
(16
)
(3
)
(27
)
(17
)
(50
)
(56
)
(151
)
(168
)
121
75
(6
)
170
(20
)
(27
)
31
(42
)
—
—
(1
)
(1
)
101
48
24
127
—
(9
)
(1
)
13
—
—
228
—
101
39
251
140
—
—
—
(3
)
$
101
$
39
$
251
$
137
included in the Notes to Condensed Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C. ASSETS CURRENT ASSETS Cash and Cash Equivalents Accounts Receivable: Trade—net of allowances of $4 and $3 in 2006 and 2005, respectively Other Accounts Receivable Affiliated Companies Notes Receivable: Affiliated Companies Other Inventory Restricted Funds Assets of Discontinued Operations Assets Held for Sale Derivative Contracts Other Total Current Assets PROPERTY, PLANT AND EQUIPMENT Less: Accumulated Depreciation and Amortization Net Property, Plant and Equipment NONCURRENT ASSETS Leveraged Leases, net Corporate Joint Ventures and Partnership Interests Goodwill and Other Intangibles Derivative Contracts Other Total Noncurrent Assets TOTAL ASSETS See disclosures regarding PSEG Energy Holdings L.L.C. 14
CONDENSED CONSOLIDATED BALANCE SHEETS
September 30,
2006
December 31,
2005
(Millions)
(Unaudited)
$
102
$
68
103
101
12
14
2
—
374
409
—
5
45
27
83
62
—
498
21
—
21
—
10
7
773
1,191
1,674
1,560
(290
)
(237
)
1,384
1,323
2,779
2,720
920
1,180
531
540
34
3
104
98
4,368
4,541
$
6,525
$
7,055
included in the Notes to Condensed Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C. LIABILITIES AND MEMBER’S EQUITY CURRENT LIABILITIES Long-Term Debt Due Within One Year Accounts Payable: Trade Affiliated Companies Derivative Contracts Accrued Interest Liabilities of Discontinued Operations Other Total Current Liabilities NONCURRENT LIABILITIES Deferred Income Taxes and Investment and Energy Tax Credits Derivative Contracts Other Total Noncurrent Liabilities COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) MINORITY INTERESTS LONG-TERM DEBT Project Level, Non-Recourse Debt Senior Notes Total Long-Term Debt MEMBER’S EQUITY Ordinary Unit Retained Earnings Accumulated Other Comprehensive Income (Loss) Total Member’s Equity TOTAL LIABILITIES AND MEMBER’S EQUITY See disclosures regarding PSEG Energy Holdings L.L.C. 15
CONDENSED CONSOLIDATED BALANCE SHEETS
September 30,
2006
December 31,
2005
(Millions)
(Unaudited)
$
341
$
348
53
50
76
11
8
13
48
42
—
436
73
83
599
983
1,839
1,705
18
27
103
66
1,960
1,798
24
15
855
891
1,149
1,448
2,004
2,339
1,288
1,713
568
317
82
(110
)
1,938
1,920
$
6,525
$
7,055
included in the Notes to Condensed Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C. CASH FLOWS FROM OPERATING ACTIVITIES Net Income Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization Demand Side Management Amortization Investment Write-off Deferred Income Taxes (Other than Leases) Leveraged Lease Income, Adjusted for Rents Received and Deferred Income Taxes Undistributed Earnings from Affiliates Loss (Gain) on Sale of Investments Gain on Sale of Discontinued Operations Foreign Currency Transaction Loss (Gain) Change in Fair Value of Derivative Financial Instruments Other Non-Cash Charges Net Changes in Certain Current Assets and Liabilities: Accounts Receivable Inventory Accounts Payable Other Current Assets and Liabilities Proceeds from Withdrawal of Partnership Interests and Other Distributions Other Net Cash Provided By Operating Activities CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment Proceeds from Sale of Discontinued Operations Proceeds from the Sale of Investments Short-Term Loan Receivable—Affiliated Company, net Restricted Funds Proceeds from Collection of Notes Receivable Additions to other assets Other Net Cash Provided By Investing Activities CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from Non-Recourse Long-Term Debt Repayment of Non-Recourse Long-Term Debt Repayment of Senior Notes Return of Capital Contributed Redemptions Preference Units Cash Distributions Paid on Preference Units Other Net Cash Used In Financing Activities Effect of Exchange Rate Change Net Increase In Cash and Cash Equivalents Cash and Cash Equivalents at Beginning of Period Cash and Cash Equivalents at End of Period Supplemental Disclosure of Cash Flow Information: Income Taxes (Received) Paid Interest Paid, Net of Amounts Capitalized See disclosures regarding PSEG Energy Holdings L.L.C. 16
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
For The Nine Months Ended
September 30,
2006
2005
(Millions)
(Unaudited)
$
251
$
140
38
45
2
6
—
22
(8
)
(7
)
32
9
(45
)
(40
)
255
(50
)
(228
)
—
4
(1
)
(49
)
6
3
4
(23
)
(3
)
(15
)
4
(58
)
18
(21
)
15
7
63
4
(2
)
149
229
(37
)
(26
)
494
—
186
26
34
54
(21
)
(44
)
—
137
(5
)
(11
)
8
9
659
145
—
4
(37
)
(20
)
(309
)
—
(425
)
(100
)
—
(184
)
—
(3
)
(1
)
(6
)
(772
)
(309
)
(2
)
1
34
66
68
183
$
102
$
249
$
(86
)
$
4
$
108
$
203
included in the Notes to Condensed Consolidated Financial Statements.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS This combined Form 10-Q is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG
Energy Holdings L.L.C. (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make
representations only as to itself and make no representations as to any other company. Note 1. Organization and Basis of Presentation Organization PSEG PSEG has four principal direct wholly owned subsidiaries: PSE&G, Power, Energy Holdings and PSEG Services Corporation (Services). As previously disclosed, on December 20, 2004, PSEG entered into an agreement and plan of merger (Merger Agreement) with Exelon Corporation (Exelon) providing for a merger of PSEG with and
into Exelon (Merger). On September 14, 2006, PSEG received from Exelon a formal notice of termination of the Merger under the provisions of the Merger Agreement. PSE&G PSE&G is an operating public utility engaged principally in the transmission of electric energy and distribution of electric energy and natural gas in certain areas of New Jersey. PSE&G is subject to
regulation by the BPU and the Federal Energy Regulatory Commission (FERC). PSE&G also owns PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), bankruptcy-remote entities that purchased certain transition
property from PSE&G and issued transition bonds secured by such property. The transition property consists principally of the rights to receive electricity consumption-based per kilowatt-hour (kWh) charges
from PSE&G electric distribution customers, which represent irrevocable rights to receive amounts sufficient to recover certain of PSE&G’s transition costs related to deregulation, as approved by the BPU. Power Power is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply, energy trading and
marketing and risk management function through three principal direct wholly owned subsidiaries: PSEG Nuclear LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC
(ER&T). Nuclear and Fossil own and operate generation and generation-related facilities. ER&T is responsible for the day-to-day management of Power’s portfolio. Fossil, Nuclear and ER&T are subject to
regulation by FERC and Nuclear is also subject to regulation by the Nuclear Regulatory Commission (NRC). Energy Holdings Energy Holdings has two principal direct wholly owned subsidiaries: PSEG Global L.L.C. (Global), which owns and operates international and domestic projects engaged in the generation and
distribution of energy, including power production facilities and electric distribution companies, and PSEG Resources L.L.C. (Resources), which has invested primarily in energy-related leveraged leases.
Energy Holdings also owns Enterprise Group Development Corporation (EGDC), a commercial real estate property management business. Services Services provides management and administrative services to PSEG and its subsidiaries. These include accounting, legal, communications, human resources, information technology, treasury and 17
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS financial services, investor relations, stockholder services, real estate, environmental, health and safety, insurance, risk management, tax, library, records and information services, security, corporate
secretarial and certain planning, budgeting and forecasting services. Services charges PSEG and its subsidiaries for the cost of work performed and services provided pursuant to the terms and conditions of
intercompany service agreements. Basis of Presentation PSEG, PSE&G, Power and Energy Holdings The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) for Quarterly Reports on Form 10-Q.
Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed
or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction
with, and update and supplement matters discussed in PSEG’s, PSE&G’s, Power’s and Energy Holdings’ respective Annual Reports on Form 10-K for the year ended December 31, 2005 and Quarterly
Reports on Form 10-Q for the quarters ended March 31, 2006 and June 30, 2006. The unaudited condensed consolidated 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 Condensed Consolidated Balance Sheets were derived from the audited Consolidated Financial Statements included
in the Annual Report on Form 10-K for the year ended December 31, 2005. Pension and Other Postretirement Benefits (OPEB) PSEG PSEG sponsors several qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. In
September 2006, PSEG contributed $50 million to its pension plans and $12 million to its OPEB plans. PSEG does not anticipate making any further contributions to the plans in 2006. The following table
provides the components of net periodic benefit costs relating to all qualified and nonqualified pension and OPEB plans on an aggregate basis. OPEB costs are presented net of the federal subsidy expected
for prescription drugs under the Medicare Prescription Drug Improvement and Modernization Act of 2003. 18
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Components of Net
Periodic Benefit Costs: Service Cost Interest Cost Expected Return on Plan
Assets Amortization of Net Transition Obligation Prior Service Cost Loss Net Periodic Benefit
Costs Effect of Regulatory
Asset Total Benefit Costs PSE&G, Power, Energy Holdings and Services Pension costs and OPEB costs for PSE&G, Power, Energy Holdings and Services are detailed as follows: PSE&G Power Energy Holdings Services Total Benefit Costs Note 2. Recent Accounting Standards The following accounting standards were issued by the Financial Accounting Standards Board (FASB), or the SEC but have not yet been adopted by PSEG. Statement of Financial Accounting Standards (SFAS) No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans” (SFAS 158) PSEG, PSE&G, Power and Energy Holdings In September 2006, the FASB issued SFAS 158, which requires companies to record the under or over funded positions of defined benefit pension and OPEB plans on the balance sheet. For under
funded plans, the liability would be equal to the difference between the plan’s benefit obligation and the fair value of plan assets. For defined benefit pension plans, the benefit obligation is the projected
benefit obligation. For OPEB plans, the benefit obligation is the accumulated postretirement benefit obligation. In addition, the statement requires that the total unrecognized costs for defined benefit
pension and OPEB plans be recorded as an after-tax charge to Accumulated Other Comprehensive Income (OCI), a separate component of Stockholder’s Equity. However, for PSE&G, because the
amortization of the unrecognized costs is being collected from customers, the accumulated 19
(UNAUDITED)
Pension Benefits
OPEB
Pension Benefits
OPEB
Quarters Ended
September 30,
Quarters Ended
September 30,
Nine Months Ended
September 30,
Nine Months Ended
September 30,
2006
2005
2006
2005
2006
2005
2006
2005
(Millions)
$
22
$
22
$
4
$
4
$
65
$
67
$
13
$
13
53
52
17
16
158
155
51
46
(65
)
(62
)
(2
)
(2
)
(199
)
(187
)
(8
)
(7
)
—
—
7
7
—
—
21
21
3
4
4
3
8
12
10
6
14
12
2
—
41
35
6
2
27
28
32
28
73
82
93
81
—
—
4
5
—
—
14
15
$
27
$
28
$
36
$
33
$
73
$
82
$
107
$
96
Pension Benefits
OPEB
Pension Benefits
OPEB
Quarters Ended
September 30,
Quarters Ended
September 30,
Nine Months Ended
September 30,
Nine Months Ended
September 30,
2006
2005
2006
2005
2006
2005
2006
2005
(Millions)
$
14
$
14
$
31
$
29
$
37
$
41
$
91
$
84
8
8
4
3
22
24
12
9
1
1
—
—
2
2
—
—
4
5
1
1
12
15
4
3
$
27
$
28
$
36
$
33
$
73
$
82
$
107
$
96
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS unrecognized costs at adoption will be recorded as a Regulatory Asset. The unrecognized costs represent actuarial gains or losses, prior service costs and transition obligations arising from the adoption of
the current pension and OPEB accounting standards, which have not been expensed. Current accounting guidance requires that unrecognized costs be presented in a footnote to the financial statements as part of a reconciliation of a plan’s funded status to amounts recorded in the
financial statements. The unrecognized costs are amortized as a component of net periodic pension or OPEB expense. Under the new standard, for Power and Energy Holdings, the charge to OCI will be
amortized and recorded as net periodic pension cost on the Statement of Operations. For PSE&G, the Regulatory Asset will be amortized and recorded as net periodic pension cost on the Statement of
Operations. SFAS 158 is effective for fiscal periods ending after December 15, 2006 and will cause changes to the balance sheet at December 31, 2006 as described above. Assuming a year-end discount rate of
6.25% and an asset return rate of 8.75%, PSEG expects its aggregate under funded status at December 31, 2006 for both its defined benefit pension plans and its OPEB plans will be approximately
$1.4 billion. This amount would be recorded in Non-current liabilities on the Balance Sheet. The aggregate unrecognized costs are projected to be approximately $1.1 billion. Of this amount, approximately
$700 million relates to PSE&G and will be recorded as an increase in regulatory assets. The balance of approximately $400 million will be recorded, net of deferred taxes of approximately $150 million, as a
charge to OCI. PSEG, PSE&G, Power and Energy Holdings continue to evaluate the impact of this statement, which is expected to have a material impact on PSEG’s, PSE&G’s and Power’s respective
financial positions. SFAS 158 is not expected to have a material impact on Energy Holding’s financial position. SFAS No. 157, “Fair Value Measurements” (SFAS 157) PSEG, PSE&G, Power and Energy Holdings In September 2006, the FASB issued SFAS 157, which provides a single definition of fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements.
Prior to SFAS 157, guidance for applying fair value was incorporated into several accounting pronouncements. SFAS 157 emphasizes that fair value is a market-based measurement, not an entity-specific
measurement, and sets out a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources (observable inputs) and those based on an entity’s own
assumptions (unobservable inputs). Under SFAS 157, fair value measurements are disclosed by level within that hierarchy, with the highest priority being quoted prices in active markets. While this
statement does not require any new fair value measurements, the application of this statement will change current practice for some fair value measurements. This statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. PSEG, PSE&G, Power and Energy Holdings are
evaluating the impact of this new accounting pronouncement. FIN 48, “Accounting for Uncertainty in Income Taxes ‑ an Interpretation of FASB Statement 109” (FIN 48) PSEG, PSE&G, Power and Energy Holdings In July 2006, the FASB issued FIN 48, which prescribes a model for how a company should recognize, measure, present and disclose in its financial statements uncertain tax positions that the company
has taken or expects to take on a tax return. Under FIN 48, the financial statements will reflect expected future tax consequences of such positions presuming the tax authorities’ full knowledge of the
position and all relevant facts. FIN 48 will require an entity to recognize the benefit of tax positions when it is “more likely-than-not” that the position is sustainable based on the merits of the 20
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS position. FIN 48 also addresses the accrual of interest and penalties related to tax uncertainties and the classification of liabilities on the balance sheet. FIN 48 is effective as of the beginning of fiscal years that start after December 15, 2006. A company will record the change in net assets that result from the application of FIN 48 as an adjustment to
Retained Earnings. PSEG, PSE&G, Power and Energy Holdings are evaluating this guidance, which could have a material impact on their respective earnings and financial position. FSP No. FAS 13-2, “Accounting for a Change or Projected Change in the Timing of Cash Flows Relating to Income Taxes Generated by a Leveraged Lease Transaction” (FSP 13-2) PSEG and Energy Holdings In July 2006, the FASB issued FSP 13-2, which addresses how a change or projected change in the timing of cash flows relating to income taxes generated by a leveraged lease transaction affects the
accounting by a lessor for that lease. The FSP amends SFAS No. 13, “Accounting for Leases,” stating that a change in the timing of the above referenced cash flows must be reviewed at least annually. If a
change in timing has occurred, or is projected to occur, the rate of return and the allocation of income to positive investment years must be recalculated from the inception of the lease. The guidance in this FSP shall be applied to fiscal years beginning after December 15, 2006. The cumulative effect of applying the provisions of this FSP shall be reported as an adjustment to the
beginning balance of retained earnings as of the beginning of the period in which this FSP is adopted. PSEG and Energy Holdings are evaluating this guidance, which could have a material impact on their
respective earnings and financial positions. The following new accounting standards were adopted by PSEG during 2006. SFAS No. 123R, “Share-Based Payment, revised 2004” (SFAS 123R) PSEG Effective January 1, 2006, PSEG adopted SFAS 123R, which replaces SFAS No. 123, “Accounting for Stock-Based Compensation” (SFAS 123) and supersedes Accounting Principles Board (APB)
Opinion No. 25, “Accounting for Stock Issued to Employees” (APB 25). SFAS 123R focuses primarily on accounting for share-based awards to employees in exchange for services, and it requires entities to
recognize compensation expense for these awards. The cost for equity-based awards is expensed based on their grant date fair value, and liability awards are expensed based on their fair value, which is re-
measured each reporting period. The pro forma disclosure previously permitted under SFAS 123 is no longer an alternative to financial statement recognition. Prior to January 1, 2006, PSEG accounted for stock-based awards under the intrinsic value method of APB 25. In accordance with APB 25, PSEG did not record compensation expense related to its
stock option grants because the strike price was equal to the fair value of the underlying stock on the grant date; however, it did record compensation expense over the requisite service period for restricted
stock grants and performance unit awards. SFAS 123R is applicable to all of PSEG’s outstanding unvested share-based payment awards as of January 1, 2006 and all prospective awards using the modified prospective method. Accordingly, the
financial results for prior periods were not retroactively adjusted to reflect the effects of SFAS 123R. The compensation expense recorded as a result of adopting SFAS 123R was not material. For additional
information, see Note 12. Stock-Based Compensation. 21
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 3. Discontinued Operations, Dispositions and Acquisitions Discontinued Operations Power Waterford Generation Facility (Waterford) In September 2005, Power completed the sale of its electric generation facility located in Waterford, Ohio to a subsidiary of American Electric Power Company, Inc. In May 2005, Power recognized an
estimated loss on disposal of $177 million, net of tax benefit of $123 million. In the third quarter of 2005, Power completed the sale of Waterford and recognized an additional loss on disposal of $1 million,
net of tax. The proceeds of the sale, together with the anticipated reduction in tax liability, were approximately $320 million and were used to retire debt at Power. Waterford’s operating results for the quarter and nine months ended September 30, 2005, which were reclassified to Discontinued Operations, are summarized below: Operating Revenues Loss Before Income Taxes Net Loss Energy Holdings Elektrocieplownia Chorzow Elcho Sp. Z o.o. (Elcho) and Elektrownia Skawina SA (Skawina) On January 31, 2006, Global entered into an agreement with CEZ a.s. to sell its interest in two coal-fired plants in Poland, Elcho and Skawina. The sale was completed on May 29, 2006. Proceeds, net of
transaction costs, were $476 million, resulting in a gain of $228 million net of tax expense of $142 million. This gain is included in Discontinued Operations. The 2006 operating results for Global’s assets in
Poland have been reclassified to Discontinued Operations. Elcho’s and Skawina’s operating results for the quarter ended September 30, 2005 and nine months ended September 30, 2006 and 2005 are summarized below: Operating Revenues (Loss) Income Before Income Taxes Net (Loss) Income 22
(UNAUDITED)
Quarter Ended
September 30,
2005
Nine Months
Ended
September 30,
2005
(Millions)
$
13
$
18
$
10
$
32
$
6
$
19
Quarter Ended
September 30,
Nine Months Ended September 30,
2005
2006
2005
Elcho
Skawina
Elcho
Skawina
Elcho
Skawina
(Millions)
$
21
$
25
$
39
$
44
$
78
$
91
$
(8
)
$
(1
)
$
(3
)
$
2
$
12
$
2
$
(9
)
$
(1
)
$
(2
)
$
1
$
11
$
2
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The carrying amounts of the assets of Elcho and Skawina as of December 31, 2005 are summarized in the following table: Current Assets Noncurrent Assets Total Assets of Discontinued Operations Current Liabilities Noncurrent Liabilities Total Liabilities of Discontinued Operations Elcho’s and Skawina’s total non-recourse debt amounted to $287 million and $26 million, respectively, as of December 31, 2005. Dispositions Energy Holdings Rio Grande Energia (RGE) On May 10, 2006, Global entered into an agreement with Companhia Paulista de Force Luz (CPFL) to sell its 32% ownership interest in RGE, a Brazilian electric distribution company. The transaction
closed on June 23, 2006 and gross proceeds of $185 million were received. The transaction resulted in an after-tax loss of $178 million, primarily related to the devaluation of the Brazilian Real subsequent
to Global’s acquisition of its interests in RGE in 1997. Solar Electric Generating Systems (SEGS) Projects In January 2005, Resources and Global sold their minority limited partner interests in three SEGS projects for proceeds of approximately $7 million, resulting in an after-tax gain of $4 million. Dhofar Power Company S.A.O.C. (Dhofar Power) In April 2005, Global sold a 35% interest in Dhofar Power through a public offering on the Omani Stock Exchange, as required under the Concession Agreement, reducing Global’s ownership in
Dhofar Power from 81% to 46%. Net proceeds from the sale approximated $25 million, resulting in an after-tax gain of approximately $1 million. Following the sale, Global’s investment in Dhofar Power
has been accounted for under the equity method. On May 15, 2006, Global signed an agreement to sell its remaining 46% interest in Dhofar Power to Oman Technical Partners Ltd. (Oman), a consortium formed by The GCC Energy Fund of Dubai,
Darbat Power of Oman and Malakoff Berhad of Malaysia; therefore, Energy Holdings reclassified the investment to Assets Held for Sale on the Condensed Consolidated Balance Sheet. The sale, which is
contingent upon obtaining consents from Dhofar Power’s lenders and receiving no objections from the Government of Oman, is expected to close in the fourth quarter of 2006 and generate proceeds of
approximately $33 million, which is the approximate book value of the investment. Meiya Power Company Limited (MPC) In January and April 2005, Global received payments of approximately $38 million and $99 million, respectively, representing the full payment of the receivable relating to the sale of its 50% equity
interest in MPC in December 2004. 23
(UNAUDITED)
As of
December 31,
2005
Elcho
Skawina
(Millions)
$
41
$
27
319
111
$
360
$
138
$
27
$
24
336
49
$
363
$
73
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Resources In January 2005, a KKR Fund, in which Resources had invested, sold its investment in KinderCare Learning Centers, Inc. and Resources received proceeds of approximately $17 million, resulting in an
after-tax gain of approximately $1 million. On October 16, 2006, Resources entered into an agreement under which Puget Sound Energy, Inc. will purchase Whitehorn Units Nos. 2 and 3 from Resources on the current lease expiration date of
February 2, 2009 for a cash price of approximately $23 million. This transaction is expected to produce incremental after-tax income and cash flow for Resources of approximately $3 million and $17 million
respectively, at such time. Acquisitions Energy Holdings Prisma 2000 S.p.A. (Prisma) In May 2006, Global forgave the guarantees of its partner in the Prisma investment of certain loans Global had made to Prisma and converted such loans totaling $38 million into additional equity in
Prisma, thereby increasing its ownership interest from 50% to 85% and giving Global voting control of the project. As a result, Energy Holdings began consolidating this investment in May 2006 and
reclassified the investment balance to Property, Plant and Equipment of approximately $62 million, Long-Term Investments of approximately $13 million, Capital Lease Obligations of approximately
$40 million and certain other assets and liabilities on Energy Holdings’ Condensed Consolidated Balance Sheet. Although the purchase price allocation has not been finalized due to the recent acquisition,
Energy Holdings recorded certain immaterial purchase accounting adjustments to reflect the plant, contracts and investment in Biomasse Italia S.p.A. (Biomasse) at fair value. The consolidation of Prisma is
expected to add approximately $45 million of annual revenue to Energy Holdings’ financial statements, and the additional ownership interest is expected to result in a modest increase to Energy Holdings’
earnings. Prisma indirectly owns and operates three biomass generation plants in Italy through its ownership of 100% of San Marco Bioenergie S.p.A., which owns a 20 MW plant, and 50% of Biomasse, a
partnership with Api Holding S.p.A., which owns two plants totaling 60 MW. Global records Prisma’s investment in Biomasse as an equity method investment due to Global’s approximate 43% indirect
ownership in Biomasse. The output of the plants is sold under power purchase agreements with the Italian national grid (CIP contracts), which include a premium for the renewable energy output. These
contracts expire from 2009 through 2012. Note 4. Earnings Per Share (EPS) PSEG Diluted EPS is calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding under
PSEG’s stock option plans, upon payment of performance units and upon conversion of Participating Units. 24
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The following table shows the effect of these stock options, performance units and Participating Units on the weighted average number of shares outstanding used in calculating diluted EPS: EPS Numerator: Earnings (Millions) Continuing Operations Discontinued Operations Net Income EPS Denominator (Thousands): Weighted Average Common Shares Outstanding Effect of Stock Options Effect of Stock Performance Units Effect of Participating Units Total Shares Earnings Per Share: Continuing Operations Discontinued Operations Net Income No stock options had an antidilutive effect for the quarters and nine months ended September 30, 2006 and 2005. Dividend payments on common stock for the quarters ended September 30, 2006 and 2005 were $0.57 and $0.56 per share, respectively, and totaled approximately $144 million and $134 million,
respectively. Dividend payments on common stock for the nine months ended September 30, 2006 and 2005 were $1.71 and $1.68 per share, respectively, and totaled approximately $430 million and
$401 million, respectively. Note 5. Commitments and Contingent Liabilities Guaranteed Obligations Power Power has unconditionally guaranteed payments by its subsidiaries, ER&T and PSEG Power New York Inc. (Power New York) in commodity-related transactions in the ordinary course of business.
These payment guarantees are provided to counterparties in order to obtain credit under physical and financial agreements for gas, power, pipeline capacity, transportation, oil, electricity and related
commodities and services. These payment guarantees support the current exposure, interest and other costs on sums due and payable by ER&T and Power New York. Under these agreements, guarantees
offered for trading and marketing cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction. The face value of the
guarantees outstanding as of September 30, 2006 and December 31, 2005 was approximately $1.4 billion and $1.6 billion, respectively. In order for Power to incur a liability for the face value of the
outstanding guarantees, ER&T and Power New York would have to fully utilize the credit granted to it by every counterparty to whom Power has provided a guarantee and all of ER&T’s and Power New
York’s contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties). The probability of all contracts at ER&T and Power New York being
simultaneously “out-of-the-money” is highly unlikely due to offsetting positions within the portfolio. For this reason, the current exposure at any point in time is a more meaningful representation of the
potential liability to Power under these guarantees. The current exposure consists of the net of accounts 25
(UNAUDITED)
Quarters Ended September 30,
Nine Months Ended September 30,
2006
2005
2006
2005
Basic
Diluted
Basic
Diluted
Basic
Diluted
Basic
Diluted
$
374
$
374
$
269
$
269
$
559
$
559
$
640
$
640
—
—
(16
)
(16
)
227
227
(184
)
(184
)
$
374
$
374
$
253
$
253
$
786
$
786
$
456
$
456
251,747
251,747
239,034
239,034
251,471
251,471
238,696
238,696
—
490
—
1,052
—
599
—
1,044
—
92
—
36
—
91
—
36
—
—
—
4,164
—
—
—
3,436
251,747
252,329
239,034
244,286
251,471
252,161
238,696
243,212
$
1.48
$
1.48
$
1.12
$
1.10
$
2.22
$
2.22
$
2.68
$
2.63
—
—
(0.06
)
(0.07
)
0.90
0.90
(0.77
)
(0.76
)
$
1.48
$
1.48
$
1.06
$
1.03
$
3.12
$
3.12
$
1.91
$
1.87
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS receivable and accounts payable and the forward value on open positions, less any margins posted. The current exposure from such liabilities was $304 million and $549 million as of September 30, 2006 and
December 31, 2005, respectively. Power is subject to collateral calls related to commodity contracts that are bilateral and are subject to certain creditworthiness standards as guarantor under performance guarantees for ER&T’s
agreements. Changes in commodity prices, including fuel, emissions allowances and electricity, can have a material impact on margin requirements under such contracts that are entered into in the normal
course of business. As of September 30, 2006, Power had posted margin of approximately $59 million, including approximately $49 million in the form of letters of credit, and received margin of
approximately $67 million, including approximately $65 million in the form of letters of credit, to satisfy collateral obligations and support various contractual and environmental obligations. As of
December 31, 2005, Power had posted margin of approximately $1.2 billion, including approximately $1 billion in the form of letters of credit, and received margin of approximately $168 million, including
approximately $115 million in the form of letters of credit. Collateral obligations may be posted in the form of cash or letters of credit. Assuming no changes in forward energy prices and positions, Power’s collateral requirements can be expected to decline
over time as its contracts expire. Power also routinely enters into exchange-traded futures and options transactions for electricity and natural gas as part of its operations. Generally, such future contracts require a deposit of cash
margin, the amount of which is subject to change based on market movement and in accordance with exchange rules. As of September 30, 2006 and December 31, 2005, Power had deposited margin of
approximately $171 million and $176 million, respectively, related to exchange-traded transactions that are margined and monitored separately from physical trading activity. In the event of a deterioration of Power’s credit rating to below investment grade, which represents a two level downgrade from its current ratings, many of these agreements allow the counterparty to
demand that ER&T provide further performance assurance, generally in the form of a letter of credit or cash. As of September 30, 2006, if Power were to lose its investment grade rating and, assuming all
counterparties to which ER&T is “out-of-the-money” were contractually entitled to demand, and demanded, performance assurance, ER&T could be required to post additional collateral in an amount equal to
approximately $509 million. Power believes that it has sufficient liquidity to post such collateral, if necessary. 26
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Energy Holdings Energy Holdings and/or Global have guaranteed certain obligations of their subsidiaries or affiliates, including the successful completion, performance or other obligations related to certain projects.
The guaranteed obligations as of September 30, 2006 and December 31, 2005 are as follows: Subsidiaries/Affiliates Skawina
(a) PSEG
Global Funding II LLC Prisma Texas
Independent Energy L.P. (TIE) - Guadalupe Elcho
(b) PSEG
Energy Technologies Asset Management Company LLC Other Total
Contingent Obligations (b) Global’s obligation was terminated as a result of the sale. In September 2003, Energy Holdings completed the sale of PSEG Energy Technologies Inc. (Energy Technologies) and nearly all of its assets. However, Energy Holdings retained certain outstanding
construction and warranty obligations related to ongoing construction projects previously performed by Energy Technologies. These construction obligations have performance bonds issued by insurance
companies for which exposure is adequately supported by the outstanding letters of credit shown in the table above for PSEG Energy Technologies Asset Management Company LLC. As of September 30,
2006, there were $14 million of such bonds outstanding related to uncompleted construction projects and other obligations. These performance bonds are not included in the $84 million of guaranteed
obligations above. Environmental Matters PSEG, PSE&G and Power Hazardous Substances The New Jersey Department of Environmental Protection (NJDEP) has regulations in effect concerning site investigation and remediation that require an ecological evaluation of potential damages to
natural resources in connection with an environmental investigation of contaminated sites. These regulations may substantially increase the costs of environmental investigations and necessary remediation,
particularly at sites situated on surface water bodies. PSE&G, Power and respective 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 is not currently estimable. However, neither PSE&G nor Power anticipates that compliance with these
regulations will have a material adverse effect on their respective financial positions, results of operations or net cash flows. 27
(UNAUDITED)
As of
Location
Description
Expiration
Date
September 30,
2006
December 31,
2005
(Millions)
Poland
Equity commitment
August 2007
Delaware
Contingent guarantee related to debt service obligations associated with Chilquinta
Energia S.A. (Chilquinta)
April 2011
Italy
Leasing agreement guarantee
N/A
Guadalupe
Interest Rate Swap Guarantee
December 2009
Poland
Debt Service Reserve Backup
October 2006
New Jersey
Performance guarantee
N/A
Various
Various
N/A
(a)
Sold in May 2006. The guaranteed amount has been indemnified by the purchaser, CEZ a.s. For further information, see Note 3. Discontinued Operations, Dispositions and Acquisitions.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The U.S. Environmental Protection Agency (EPA) has determined that a six-mile 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 (CERCLA). PSE&G and certain of its predecessors conducted industrial operations at properties adjacent to the
Passaic River facility. The operations included one operating electric generating station (Essex Site), one former generating station and four former manufactured gas plants (MGPs). PSE&G’s costs to clean
up former MGPs are recoverable from utility customers through the societal benefits clause (SBC). PSE&G has sold the site of the former generating station and obtained releases and indemnities for
liabilities arising out of the site in connection with the sale. The Essex Site was transferred to Power in August 2000. Power assumed any environmental liabilities of PSE&G associated with the electric
generating stations that PSE&G transferred to it, including the Essex Site. In 2003, the EPA notified 41 potentially responsible parties (PRPs), including PSE&G and Power, that it was expanding its assessment of the Passaic River Study Area to the entire 17-mile tidal reach of
the lower Passaic River. The EPA further indicated, with respect to PSE&G, that it believed that hazardous substances had been released from the Essex Site and a former MGP located in Harrison, New
Jersey (Harrison Site), which also includes facilities for PSE&G’s ongoing gas operations. The EPA estimated that its study would require five to eight years to complete and would cost approximately $20
million, of which it would seek to recover $10 million from the PRPs, including PSE&G and Power. Power has provided notice to insurers concerning this potential claim. Also, in 2003, PSEG, PSE&G and 56 other PRPs received a Directive and Notice to Insurers from the NJDEP that directed the PRPs to arrange for a natural resource damage assessment and interim
compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Compensation and Control Act. The NJDEP alleged in the Directive
that it had determined that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP announced that it had estimated the cost of interim natural resource injury
restoration activities along the lower Passaic River to approximate $950 million. PSE&G and Power have indicated to both the EPA and NJDEP that they are willing to work with the agencies in an effort to resolve their respective claims and, along with approximately 61 other
PRPs, have entered into an agreement with the EPA or have indicated their intention to enter an agreement that provides for sharing the costs of the $20 million study between the government
organizations and the PRPs. The EPA recently has notified the PRPs that the cost of the study will greatly exceed the $20 million initially estimated and offered to the PRPs the opportunity to conduct the
study themselves rather than reimburse the government for the additional costs it incurs. The PRP group is considering the offer and has engaged in discussions with the EPA. Whether the PRP group, or
some number of the PRPs, agree to assume responsibility for the study will depend upon many factors, including a revised estimated cost of the study, the number of parties who agree to participate and the
manner in which the parties divide the costs among themselves. PSEG, PSE&G and Power cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to
the Passaic River or natural resource damages. However, such costs could be material. PSE&G MGP Remediation Program PSE&G is currently working with the NJDEP under a program to assess, investigate and remediate environmental conditions at PSE&G’s former MGP sites (Remediation Program). To date, 38 sites have
been identified as requiring some level of remedial action. In addition, the NJDEP has announced initiatives to accelerate the investigation and subsequent remediation of the riverbeds underlying surface
water bodies that have been impacted by hazardous substances from adjoining sites. Specifically, in 2005, the NJDEP initiated a program on the Delaware River aimed at identifying the 10 most significant
sites for cleanup. One of the sites identified is a former MGP facility located in Camden, New Jersey. The Remediation Program is periodically reviewed and the estimated costs are revised by 28
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS PSE&G based on regulatory requirements, experience with the program and available remediation technologies. Since the inception of the Remediation Program in 1988 through September 30, 2006, PSE&G
had expenditures of approximately $366 million. During the fourth quarter of 2005, PSE&G refined the detailed site estimates. The cost of remediating all sites to completion, as well as the anticipated costs to address MGP-related material discovered
in two rivers adjacent to former MGP sites, could range between $751 million and $796 million. No amount within the range was considered to be most likely. Therefore, $385 million was accrued as of
September 30, 2006, which represents the difference between the low end of the total program cost estimate of $751 million and the total incurred costs through September 30, 2006 of $366 million. Of this
amount, approximately $44 million was recorded in Other Current Liabilities and $341 million was reflected in Other Noncurrent Liabilities. The costs associated with the MGP Remediation Program have
historically been recovered through the SBC charges to PSE&G ratepayers. As such, a $385 million Regulatory Asset was recorded. PSE&G anticipates spending $44 million in 2006, $45 million in 2007 and an
average of $36 million per year through 2016 to remediate MGP-related environmental conditions. Power Prevention of Significant Deterioration (PSD)/New Source Review (NSR) The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets, in
some circumstances, when those sources undergo a “major modification,” as defined in the regulations. The Federal government may order companies not in compliance with the PSD/NSR regulations to
install the best available control technology at the affected plants and to pay monetary penalties of up to approximately $27,500 for each day of continued violation. The EPA and the NJDEP issued a demand in March 2000 under the CAA requiring information to assess whether projects completed since 1978 at the Hudson and Mercer coal-burning units were
implemented in accordance with applicable PSD/NSR regulations. Power completed its response to requests for information and, in January 2002, reached an agreement with the NJDEP and the EPA to
resolve allegations of noncompliance with PSD/NSR regulations. Under that agreement, over the course of 10 years, Power agreed to install advanced air pollution controls to reduce emissions of Sulfur
Dioxide (SO2), Nitrogen Oxide (NOx), particulate matter and mercury from the coal-burning units at the Mercer and Hudson generating stations to ensure compliance with PSD/NSR. The cost of the
program was approximately $112 million for selective catalytic reduction systems (SCRs) which have been installed at Mercer, as well as additional capital expenditures of approximately $400 million to
$500 million at Hudson and $150 million to $250 million at Mercer for other pollution control equipment to be installed between December 31, 2006 and December 31, 2012. Power has spent over $6 million
on supplemental environmental projects and paid a $1.4 million civil penalty. The agreement resolving the NSR allegations concerning the Hudson and Mercer coal-fired units also resolved a dispute over
Bergen 2 regarding the applicability of PSD requirements and allowed construction of the unit to be completed and operations to commence. Power has notified the EPA and the NJDEP that it is evaluating the continued operation of the Hudson coal unit in light of changes in the energy and capacity markets, increases in the cost of pollution
control equipment and other necessary modifications to the unit. Power will be unable to complete the installation of the pollution control equipment at Hudson by the December 31, 2006 deadline. Power
has proposed to the NJDEP and the EPA an alternate pollution reduction plan to permit Hudson to continue to operate on coal beyond December 31, 2006. The proposal would require Power to
compensate for emission reductions contemplated under the 2002 agreement through other emission control technology, operational measures and the retirement of emission allowances until the originally
specified controls are installed on Hudson or the unit is shutdown. Discussions relating to this issue are ongoing. Power believes that the unit will likely continue to operate after December 31, 2006; 29
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS however, no assurances can be given. Power provided notice to PJM, pursuant to the requirements of its tariff, that Power may be required to deactivate Hudson Unit 2 if an agreement is not reached with
environmental regulators. The additional capital expenditures referenced above are incremental to the capital expenditure forecast included in the Annual Report on Form 10-K for the year ended
December 31, 2005. As a result of ongoing discussions, Power has increased its environmental reserves by approximately $15 million to account for potential civil penalties and other costs. PSEG and Power recorded the
charge in Other Deductions on their respective Condensed Consolidated Statements of Operations. Mercury Regulation New Jersey and Connecticut have adopted standards for the reduction of emissions of mercury from coal-fired electric generating units. The Connecticut legislation requires coal-fired power plants in
Connecticut to achieve either an emissions limit or a 90% mercury removal efficiency through technology installed to control mercury emissions effective in July 2008. The regulations in New Jersey require
coal-fired electric generating units in New Jersey to meet certain emissions limits or reduce emissions by 90% by December 15, 2007. Under the New Jersey regulations, companies that are parties to multi-
pollutant reduction agreements are permitted to postpone such reductions on half of their coal-fired electric generating capacity until December 15, 2012. Power has a multi-pollutant reduction agreement
with the NJDEP as a result of a consent decree that resolved issues arising out of the PSD and the NSR air pollution control programs at the Hudson, Mercer and Bergen facilities. The estimated costs of
technology believed to be capable of meeting these emissions limits at Power’s coal-fired unit in Connecticut and at its Mercer Station are included in Power’s capital expenditures forecast. Total estimated
costs for each project are between $150 million and $200 million. On September 12, 2006, Connecticut released proposed revisions to mercury regulations that encompass “Permit Requirements for Mercury Emissions from Coal-Fired Electric Generating Units”.
Power is evaluating these proposed revisions; however, it cannot predict the impact of these proposed revisions. New Jersey Industrial Site Recovery Act (ISRA) In the second quarter of 1999, a study was conducted pursuant to ISRA and potential environmental liabilities related to subsurface contamination at certain generating stations were identified. Power
had a $51 million liability as of September 30, 2006 and December 31, 2005 related to these obligations, which is included in Other Noncurrent Liabilities on Power’s Condensed Consolidated Balance
Sheets and Environmental Costs on PSEG’s Condensed Consolidated Balance Sheets. Permit Renewals In June 2001, the NJDEP issued a renewed New Jersey Pollutant Discharge Elimination System (NJPDES) permit for Salem Nuclear Generating Station (Salem), which expired in July 2006, allowing
for the continued operation of Salem with its existing cooling water system. A renewal application prepared in accordance with the new Phase II 316(b) rule was filed with the NJDEP that allows the station
to continue operating under its existing NJPDES permit until a new permit is issued. Power believes that its application to renew Salem’s NJPDES permit demonstrates that the station meets the Phase II
316(b) rule’s performance standards for reduction of impingement mortality and entrainment through the station’s existing cooling water intake technology and operations plus implemented restoration
measures. Power believes that the application further demonstrates that the station meets the Phase II 316(b) rule’s site-specific determination standards without the benefits of restoration. If the NJDEP
were to require the installation of technologies at the Salem facility to reduce cooling water 30
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS intake flow commensurate with closed-cycle cooling as a result of an unfavorable decision in the litigation that has been filed challenging the Phase II 316(b) rule or otherwise, Power estimates that the costs
associated with cooling towers for Salem are approximately $1 billion, of which Power’s share would be approximately $575 million. These costs are not included in Power’s currently forecasted capital
expenditures. Energy Holdings Prisma As
previously disclosed, Global became a majority owner of Prisma in May 2006.
During the third quarter of 2006, Global became aware of an investigation concerning
certain allegations of violations with respect to air emissions at Prisma’s
20 MW San Marco biomass generating facility. Such alleged violations appear
to consist primarily of the failure to appropriately monitor and report emissions
and exceeding certain air emission limits. Global is conducting an investigation
of the allegations, including the scope and timing of the potential violations,
and is cooperating with Italian authorities in their investigation. Global believes
that the plant is currently monitoring and reporting emissions in accordance
with applicable regulations. In the event that future operations are not in
compliance with air emissions regulations and associated prescribed limits,
Italian law may permit the local prosecutor to close the plant to prevent any
such future violations. If the alleged environmental violations have occurred,
financial penalties could be assessed, operating restrictions on the plant could
be implemented by the prosecutor and/or the regulators, including closure, the
impact of which could be material to Energy Holdings’ results of operations,
financial position and cash flows. Global expects to complete its investigation
of the allegations in the fourth quarter of 2006 and discuss the appropriate
remedies, if any, with the authorities. New Generation and Development Power Power has contracts with outside parties to purchase upgraded turbines for Salem Units 1 and 2 and to purchase upgraded turbines and complete a power uprate for Hope Creek to modestly increase its
generating capacity. Phase II of the Salem Unit 2 turbine replacement is currently scheduled for 2008 concurrent with steam generator replacement and is anticipated to increase capacity by 26 MW. Phase
II of the Hope Creek turbine replacement is expected to be completed in 2007 along with the thermal power uprate and is expected to add approximately 125 MW. Power’s expenditures to date
approximate $217 million (including Interest Capitalized During Construction (IDC) of $20 million) with an aggregate estimated share of total costs for these projects of $244 million (including IDC of
$24 million). Timing, costs and results of these projects are dependent on timely completion of work, timely approval from the NRC and various other factors. Completion of the projects discussed above within the estimated time frames and cost estimates cannot be assured. Construction delays, cost increases and various other factors could result in changes
in the operational dates or ultimate costs to complete. Energy Holdings Electroandes S.A. (Electroandes) A 35 MW expansion project of an existing hydro station at Electroandes, a generating facility in Peru, is under review. Construction has been indefinitely postponed as the project is being re-evaluated.
No construction funds have been disbursed on the project thus far and capital expenditures related to this project have been removed from Energy Holdings’ forecast. 31
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS) Power Power seeks to mitigate volatility in its results by contracting in advance for its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey Electric Distribution Companies (EDCs) with a portion of their respective BGS requirements
through the New Jersey BGS auction process, described below. In addition to the BGS-related contracts, Power has entered into firm supply contracts with EDCs in Pennsylvania and Connecticut, as well as
other firm sales and trading positions and commitments. PSE&G and Power PSE&G is required to obtain all electric supply requirements for customers that do not purchase electric supply from third-party suppliers through the annual New Jersey BGS auctions. The BGS auction
process is a statewide process in which all of the New Jersey EDCs participate. The BGS auctions are “descending clock” auctions, where the EDCs accept offers for the amount of electric supply bidders
are willing to offer with higher prices at the beginning of the auction. The auction proceeds when the amount of supply bid exceeds what is needed. The offer price is subsequently lowered and the process
continues in a series of steps. When the amount of supply bid by the prospective suppliers matches the EDCs’ electric supply needs, the auction ends. The BPU renders a decision whether or not to accept
the auction results within two business days of its conclusion. PSE&G enters into the Supplier Master Agreement (SMA) with the winners of these BGS auctions within three business days of the BPU’s approval. PSE&G has entered into contracts with Power, as well
as with other winning BGS suppliers, to purchase BGS for PSE&G’s anticipated load requirements. The winners of the auction are responsible for fulfilling all the requirements of a PJM Interconnection,
L.L.C. (PJM) Load Serving Entity (LSE) including capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume any migration risk and must satisfy New
Jersey’s renewable portfolio standards. Through the BGS auctions, PSE&G has contracted for its anticipated BGS-Fixed Price load, as follows: Term Load (MW) $ per kWh (b) Prices set in the February 2004 BGS auction. (c) Prices set in the February 2005 BGS auction. (d) Prices set in the February 2006 BGS auction, which became effective on June 1, 2006. PSE&G entered into a full requirements contract through 2007 with Power to meet the supply requirements of PSE&G’s gas customers. Power has entered into hedges for a portion of its anticipated BGSS
obligations, as permitted by the BPU. The BPU permits recovery of the cost of gas hedging up to 115 billion cubic feet or approximately 80% of PSE&G’s residential gas supply annually through the BGSS
tariff. For additional information, see Note 13. Related-Party Transactions. 32
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Term Ending
May 2006(a)
May 2007(b)
May 2008(c)
May 2009(d)
34 months
36 months
36 months
36 months
2,900
2,840
2,840
2,882
$
0.05560
$
0.05515
$
0.06541
$
0.10251
(a)
Prices set in the February 2003 BGS auction.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Minimum Fuel Purchase Requirements Power Power purchases coal for certain of its fossil generation stations through various long-term commitments. The total minimum purchase requirements included in these commitments amount to
approximately $634 million through 2012. Power has various multi-year requirements-based purchase commitments that average approximately $89 million per year to meet Salem’s and Hope Creek’s nuclear fuel needs, of which Power’s share
is approximately $64 million per year through 2010. Power has been advised by the co-owner and operator of Peach Bottom, Exelon Generation LLC (Exelon Generation), that it has similar purchase
contracts to satisfy the fuel requirements for Peach Bottom through 2010, of which Power’s share is approximately $31 million per year. In addition to its fuel requirements, Power has entered into various multi-year contracts for firm transportation and storage capacity for natural gas, primarily to meet its gas supply obligations to PSE&G.
As of September 30, 2006, the total minimum requirements under these contracts were approximately $1.2 billion through 2016. These purchase obligations are aligned with Power’s strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts. Energy Holdings TIE The Guadalupe and Odessa plants of TIE, an indirect, wholly owned subsidiary of Energy Holdings, have entered into gas supply agreements for their anticipated fuel requirements to satisfy
obligations under their forward energy sales contracts. As of September 30, 2006, the Guadalupe and Odessa plants, which total approximately 2,000 MW of capacity, had forward energy sales contracts in
place, which support the majority of their margin expectations for the balance of 2006. The plants had fuel purchase commitments totaling $63 million to fully support these contracts. TIE has also entered
into an agreement to sell approximately 19% of its aggregate capacity for 2007 through 2010. Chilquinta Energy
Holdings has a 50% indirect ownership interest in Chilquinta Energia (Chilquinta)
which owns a Chilean natural gas distribution company, Energas. Energas has
various long-term commitments for natural gas and for firm transportation contracts
with Metrogas and Electrogas, Chilean gas distribution/transport companies,
which were entered into to support anticipated sales to its customers. Due to current natural gas restrictions imposed by Metrogas, Energas may have contracted pipeline transport capacity in excess of available gas. Such transport capacity contracts, which are non-
recourse to Energy Holdings, have an estimated maximum commitment of up to $22 million pre-tax over the next fifteen years (considering Energy Holdings’ ownership percentage in Energas). Energas
continues to review anticipated natural gas supply levels and its transport
capacity contracts relative to its projected customer needs. Energas is also
attempting to identify additional sources of gas, including liquified natural
gas (LNG), and is working to mitigate any potential impact through both legal
and commercial means. These factors will be considered as the future business
direction of Energas is assessed. Operating Services Contract (OSC) Power Nuclear has entered into an OSC with Exelon Generation, a subsidiary of Exelon, which commenced on January 17, 2005, relating to the operation of the Hope Creek and Salem nuclear 33
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS generating
stations. The OSC requires Exelon Generation to provide a chief nuclear officer
and other key personnel to oversee daily plant operations at the Hope Creek
and Salem nuclear generating stations and to implement the Exelon Generation
operating model, which defines practices that Exelon Generation has used to
manage the operations of its own nuclear facilities. Nuclear continues as the
license holder with exclusive legal authority to operate and maintain the plants,
retains responsibility for management oversight and has full authority with
respect to the marketing of its share of the output from the facilities. Exelon
Generation is entitled to receive reimbursement of its costs in discharging
its obligations, an annual operating services fee of $3 million and incentive
fees up to $12 million annually based on attainment of goals relating to safety,
capacity factor and operation and maintenance expenses. The OSC is in full force
and effect and currently terminates in January 2007. PSEG has provided notice
to Exelon that it is electing to continue the OSC for two years during which
time it will move into a transition phase. PSEG has the right to extend the
transition phase of the OSC for an additional year if it so elects. PSEG
is considering various long-term alternatives, ranging from rebuilding its stand-alone
nuclear capabilities to long-term Exelon operations that could be accompanied
by a swap of nuclear capacity. PSEG expects to define a long-term strategy well
before the two-year period is completed. Maintenance Agreement Power Power entered into a long-term contractual services agreement with a vendor in September 2003 to provide the outage and service needs for certain of Power’s fossil generating units at market rates.
The contract covers approximately 25 years and could result in annual payments ranging from approximately $10 million to $50 million for services, parts and materials rendered. Nuclear Fuel Disposal Power Under the Nuclear Waste Policy Act of 1982, as amended (NWPA), the Federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate
disposal of spent nuclear fuel. To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund at a rate of one mil ($0.001) per kWh of nuclear generation, subject to such
escalation as may be required to assure full cost recovery by the Federal government. Under the NWPA, the U.S. Department of Energy (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 for such purpose to be available earlier than 2017. Pursuant to NRC rules, spent nuclear fuel generated in any reactor can be stored in reactor facility storage pools or in independent spent fuel storage installations located at reactors or away-from-
reactor sites for at least 30 years beyond the licensed life for reactor operation (which may include the term of a revised or renewed license). Adequate spent fuel storage capacity is estimated to be available
through 2011 for Salem 1, 2015 for Salem 2 and 2007 for Hope Creek. Power has commenced construction of an on-site storage facility that will satisfy the spent fuel storage needs of both Salem and Hope
Creek through the end of their current respective license lives. Exelon Generation has advised Power that it has a licensed and operational on-site storage facility at Peach Bottom that will satisfy Peach
Bottom’s spent fuel storage requirements until at least 2014. Exelon Generation had previously advised Power that it had signed an agreement with the DOE, applicable to Peach Bottom, under which Exelon Generation would be reimbursed for costs incurred
resulting from the DOE’s delay in accepting spent nuclear fuel for permanent storage. Under this agreement, Power’s portion of Peach Bottom’s Nuclear Waste Fund fees was reduced by approximately 34
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS $18 million through August 31, 2002, at which point credits were fully utilized and covered the cost of Exelon Generation’s on-site storage facility. In September 2002, the U.S. Court of Appeals for the
Eleventh Circuit issued an opinion upholding a petition seeking to set aside the receipt of these credits by Exelon Generation. On August 14, 2003, Exelon Generation received a letter from the DOE
demanding repayment of previously received credits from the Nuclear Waste Fund. The letter also demanded a total of approximately $1.5 million of accrued interest. In August 2004, Exelon Generation
advised Nuclear that it reached a settlement with the U.S. Department of Justice, under which Exelon Generation would be reimbursed for costs associated with the storage of spent nuclear fuel at the
Peach Bottom facility, a portion of which would be paid to Nuclear as a co-owner of Peach Bottom. Future costs incurred resulting from the DOE delays in accepting spent fuel will be reimbursed annually
until the DOE fulfills its obligation to accept spent nuclear fuel. In addition, Exelon Generation and Nuclear are required to reimburse the DOE for the previously received credits from the Nuclear Waste
Fund, plus lost earnings. Under this settlement, Power received approximately $27 million for its share of previously incurred storage costs for Peach Bottom, $22 million of which was used for the required
reimbursement to the Nuclear Waste Fund. Exelon Generation paid Power approximately $5.4 million for its portion of the spent fuel storage costs reimbursed by the DOE in 2005 for costs incurred
between October 1, 2003 and June 30, 2005. In September 2001, Power filed a complaint in the U.S. Court of Federal Claims seeking damages for Salem and Hope Creek caused by the DOE not taking possession of spent nuclear fuel in 1998. On
October 14, 2004, an order to show cause was issued regarding whether the U.S. Court of Federal Claims has jurisdiction over the matter. Power responded to this order in November 2004. On January 31,
2005, the Court dismissed the breach-of-contract claims of Power and three other utilities. Power moved for reconsideration in the U.S. Court of Federal Claims and jointly petitioned for permission to
appeal the January 31, 2005 order to the U.S. Court of Appeals for the Federal Circuit. On September 29, 2006, the U.S. Court of Appeals for the Federal Circuit reversed the adverse U.S. Court of Federal
Claims jurisdicational ruling. Power is seeking reinstatement of claims in the U.S. Court of Federal Claims. No assurances can be given as to any damage recovery or the ultimate availability of a disposal
facility. Spent Fuel Pool Power The spent fuel pool at each Salem unit has an installed leakage collection system. This system was found to be obstructed at Salem Unit 1. Power developed a solution to maintain the design function of
the leakage collection system at Salem Unit 1 and investigated the existence of any structural degradation that might have been caused by the obstruction. The concrete and reinforcing steel laboratory tests
results were completed in March 2006. Test results that have been collected as part of the ongoing testing indicate that no repairs are anticipated. The NRC issued Information Notice 2004-05 in March 2004
concerning this emerging industry issue and Power cannot predict what further actions the NRC may take on this matter. Elevated concentrations of tritium in the shallow groundwater at Salem Unit 1 were detected in early 2003. This information was reported to the NJDEP and the NRC, as required. Power conducted a
comprehensive investigation in accordance with NJDEP site remediation regulations to determine the source and extent of the tritium in the groundwater. Power is conducting remedial actions to address
the contamination in accordance with a remedial action workplan approved by the NJDEP in November 2004. The remedial actions are expected to be ongoing for several years. The costs necessary to
address this on-site groundwater contamination issue are not expected to be material. 35
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Investment Tax Credits (ITC) PSEG and PSE&G As of June 1999, the Internal Revenue Service (IRS) had issued several private letter rulings (PLRs) that concluded that the refunding of excess deferred tax and ITC balances to utility customers was
permitted only over the related assets’ regulatory lives, which were terminated upon New Jersey’s electric industry deregulation. Based on this fact, PSEG and PSE&G reversed the deferred tax and ITC
liability relating to PSE&G’s generation assets that were transferred to Power, and recorded a $235 million reduction of the extraordinary charge in 1999 due to the restructuring of the utility industry in New
Jersey. PSE&G was directed by the BPU to seek a PLR from the IRS to determine if the ITC included in the impairment write-down of generation assets could be credited to customers without violating the
tax normalization rules of the Internal Revenue Code. PSE&G filed a PLR request with the IRS in 2002. On December 21, 2005, the U.S. Department of the Treasury (Treasury) proposed new regulations for comment addressing the normalization of ITC, replacing regulations originally proposed in 2003.
The new proposed regulations, if finalized, would not permit retroactive application. Accordingly, the IRS’s conclusions in the above referenced PLRs would continue to remain in effect for all industry
deregulations prior to December 21, 2005. On April 26, 2006, the BPU issued an order to PSE&G revoking its previous instruction and directing PSE&G to withdraw its request for a PLR by April 27, 2006. The BPU asserted that the Treasury’s
proposed regulation project was the more appropriate authority to rely upon in deciding the ITC issue. On May 1, 2006, PSE&G filed a motion for reconsideration with the BPU requesting that it modify its April 26, 2006 order to PSE&G to withdraw the PLR request. On May 5, 2006, the BPU denied
PSE&G’s motion for reconsideration and reiterated its order to withdraw the PLR request. On May 8, 2006, PSE&G filed a petition with the Appellate Court of New Jersey challenging the BPU’s order to
withdraw the PLR. On May 11, 2006, the IRS issued a PLR to PSE&G. The PLR concluded that none of the generation ITC could be passed to utility customers without violating the normalization rules. While the holding
in the PLR is a favorable development for PSE&G, the outstanding Treasury regulation project could overturn the holding in the PLR if the Treasury were to alter the position set out in the December 21,
2005 proposed regulations. The issue cannot be fully resolved until the final Treasury regulations are issued. On May 16, 2006, the BPU voted in favor of a special investigation and hearing before the BPU concerning PSE&G’s actions leading up to receiving the PLR, specifically its failure to abide by the BPU
order to withdraw the request. An order detailing such special investigation has not yet been issued and no investigation has begun. On October 13, 2006, the Appellate Division of the Superior Court of New Jersey granted PSE&G’s motion to dismiss PSE&G’s appeal of the BPU’s order to withdraw the PLR since PSE&G has already
received the PLR. The court also determined that if the BPU seeks to take future action against PSE&G based on the alleged violation of its order, PSE&G can restart the appeal. BPU Deferral Audit PSEG and PSE&G The BPU Energy and Audit Division conducts periodic audits of utilities’ deferred balances. A draft Deferral Audit—Phase II report relating to PSE&G for the 12-month period ended July 31, 2003 was
released by the consultant to the BPU in April 2005. The draft report addresses PSE&G’s SBC, Market Transition Charge (MTC) and Non-Utility Generation (NUG) deferred balances. The BPU released
the report on May 13, 2005. 36
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS While the consultant to the BPU found that PSE&G’s Phase II deferral balances complied in all material respects with the BPU orders regarding such deferrals, the consultant noted that the BPU Staff
had raised certain questions with respect to the reconciliation method PSE&G employed in calculating the overrecovery of its MTC and other charges during the Phase I and Phase II four-year transition
period. The amount in dispute is approximately $114 million. PSE&G and the BPU Staff are continuing discussions to resolve these questions and, if a resolution cannot be achieved, a BPU proceeding may
be instituted to consider the issues raised. While PSE&G believes the MTC methodology it used was fully litigated and resolved, without exception, by the BPU and other intervening parties in its previous
electric base rate case, deferral audit and deferral proceeding that were approved by the BPU in its order on April 22, 2004, and that such order is non-appealable, PSE&G cannot predict the impact of the
outcome of any such proceeding. New Jersey Clean Energy Program The BPU has approved a funding requirement for each New Jersey utility applicable to its Renewable Energy and Energy Efficiency programs for the years 2005 to 2008. The liability for the funding
requirement has been recorded at the discounted present value. The costs associated with this program will be recovered from PSE&G ratepayers through the SBC over a period of four years and, therefore,
a Regulatory Asset was also recorded. The liability for the funding requirement as of September 30, 2006 and December 31, 2005 was $274 million and $329 million, respectively. Leveraged Lease Investments PSEG and Energy Holdings Resources faces risks with regard to the creditworthiness of certain lessees that collectively comprise a substantial portion of its investment portfolio. Resources also faces risks related to potential
changes in the current accounting and tax treatment of certain investments in leveraged leases. From 1996 through 2002, PSEG, through its indirect wholly owned subsidiary, Resources, entered into a number of leveraged lease transactions in the ordinary course of business. Certain of these
transactions are similar to a type that the IRS subsequently announced its intention to challenge, and PSEG understands that similar transactions entered into by other companies have been the subject of
review and challenge by the IRS. As of each of September 30, 2006 and December 31, 2005, Resources’ total gross investment in such transactions was approximately $1.5 billion. The IRS is presently
reviewing the tax returns of PSEG and its subsidiaries for tax years 1997 through 2003, when Resources entered into the transactions. On September 27, 2005, the IRS proposed to disallow PSEG’s deductions associated with certain of these leveraged leases which have been designated by the IRS as “listed transactions.” On July 8,
2006, the IRS proposed to disallow deductions associated with another group of these leveraged leases. The IRS may propose additional disallowances in the future. If deductions associated with these lease
transactions entered into by PSEG are successfully challenged by the IRS, it could have a material adverse impact on PSEG’s and Energy Holdings’ financial position, results of operations and net cash
flows and could impact future returns on these transactions. PSEG believes that its tax position related to these transactions is proper based on applicable statutes, regulations and case law and believes that
it should prevail with respect to any IRS challenge, although no assurances can be given. If the tax benefits associated with all of the listed lease transactions were completely disallowed by the IRS and sustained on appeal, approximately $741 million of PSEG’s deferred tax liabilities that
have been recorded under leveraged lease accounting through September 30, 2006 would become currently payable. In addition, interest of approximately $115 million, after-tax, and penalties could be
assessed. Management assessed the probability of various outcomes to this matter and recorded appropriate reserves in accordance with SFAS No. 5 “Accounting for Contingencies.” Management has also
prepared various sensitivity analyses regarding potential payment obligations, including scenarios 37
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS that consider the current position of the IRS regarding these types of listed transactions, and believes that Energy Holdings has the financial capacity to meet such potential obligations, if required. The FASB recently issued additional guidance for leveraged leases. See Note 2. Recent Accounting Standards for additional information. Restructuring Charge Power In June 2005, Power implemented a plan to reduce its Nuclear workforce by approximately 200 positions. The plan included voluntary and involuntary separations offered to both represented and non-
represented employees. The major cost associated with the restructuring relates to payments to the employees who were terminated. Power’s $14 million share of the estimated total cost was recorded in
2005, approximately $12 million of which had been paid as of September 30, 2006. Retention Program PSEG, PSE&G, Power and Energy Holdings The Retention Program, effective as of December 20, 2004, provided for payments to be made to certain key employees of PSEG who remained employed from the date of execution of the Merger
Agreement through the date that would have been 90 days after the consummation of the Merger. The amount of a participant’s retention was between 40% and 150% of the participant’s annual base
salary. PSEG paid the first installment, equal to half of a participant’s total retention payment, in December 2005. The final installment payments, which were contingent on successful completion of the
Merger, will not be made. Other Energy Holdings Electroandes In July 2005, Electroandes received a notice from Superintendencia Nacional de Administracion Tributaria (SUNAT), the governing tax authority in Peru, claiming past due taxes for 2002 totaling
approximately $2 million related to certain interest deductions. Electroandes has taken similar interest deductions subsequent to 2002. The total cumulative estimated potential amount for past due taxes,
including associated interest and penalties, is approximately $8 million through September 30, 2006. Electroandes believes it has valid legal defenses to these claims, and has filed an appeal with SUNAT to
which it has not yet received a response; however, no assurances can be given regarding the outcome of this matter. Dhofar Power Since commencing operations in Oman in May 2003, Dhofar Power has experienced a number of unplanned service interruptions, which resulted from a combination of force majeure events and
breaches of general warranties of the contractors that installed equipment at Dhofar Power. Dhofar Power and the Government of Oman have been in a dispute regarding the applicability and extent of any
penalties under Dhofar Power’s Concession Agreement arising from these service interruptions. On July 14, 2005, the expert engaged by the parties recommended no penalties be assessed for the 2003
service interruptions and agreed with Dhofar Power’s interpretation of the Concession Agreement with respect to the criteria to be utilized in assessing penalties. The Government of Oman has exercised its
right to appeal the expert’s determination to a full arbitration panel. Penalties have also been assessed for service interruptions for subsequent years, which may be addressed in the same arbitration. While
Dhofar Power believes this matter will be favorably resolved, no assurances can be given. 38
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Dhofar Power and the Government of Oman are also in disagreement on the basis of the calculation of certain monthly allowances to be paid to compensate Dhofar Power for the capital investment
costs associated with the enhancements and extensions of the transmission and distribution system in Salalah. On August 24, 2005, the expert engaged by the parties found in favor of Dhofar Power with
respect to the criteria to be used in determining the monthly allowances. In the view of Dhofar Power, the Government of Oman has failed to timely exercise its right to appeal the expert’s determination to
a full arbitration panel. The Government of Oman has now paid all sums previously due, totaling approximately $1 million, and is continuing to make payments on the basis of Dhofar Power’s calculations,
but has not agreed that it is obligated to continue to pay Dhofar Power on the basis recognized by the expert. Dhofar Power will seek to enforce the expert’s determination that it is entitled to
approximately $1 million annually through December 2018 and believes that this matter will be favorably resolved in 2006, although no assurances can be given. Note 6. Financial Risk Management Activities PSEG, PSE&G, Power and Energy Holdings The operations of PSEG, PSE&G, Power and Energy Holdings are exposed to market risks from changes in commodity prices, foreign currency exchange rates, interest rates and equity prices that could
affect their results of operations and financial conditions. PSEG, PSE&G, Power and Energy Holdings manage exposure to these market risks through their regular operating and financing activities and,
when deemed appropriate, hedge these risks through the use of derivative financial instruments. PSEG, PSE&G, Power and Energy Holdings use the term “hedge” to mean a strategy designed to manage
risks of volatility in prices or rate movements on certain assets, liabilities or anticipated transactions and by creating a relationship in which gains or losses on derivative instruments are expected to
counterbalance the gains or losses on the assets, liabilities or anticipated transactions exposed to such market risks. Each of PSEG, PSE&G, Power and Energy Holdings uses derivative instruments as risk
management tools consistent with its respective business plan and prudent business practices. Derivative Instruments and Hedging Activities Power Power maintains a strategy of entering into positions to optimize the value of its portfolio and reduce earnings volatility of generation assets, gas supply contracts and its electric and gas supply
obligations. Power engages in physical and financial transactions in the electricity wholesale markets and executes an overall risk management strategy seeking to mitigate the effects of adverse movements
in the fuel and electricity markets. These contracts also involve financial transactions, including swaps, options and futures. Energy Trading Contracts (ETCs) Power Power actively trades energy and energy-related products, including electricity, natural gas, electric capacity, firm transmission rights (FTRs), coal, oil and emissions allowances in the spot, forward and
futures markets, primarily in PJM, but also in the surrounding region, which extends from Maine to the Carolinas and the Atlantic Coast to Indiana, and natural gas in the producing region. Power marks to market its derivative ETCs in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS 133), with changes in fair value
charged to the Condensed Consolidated Statements of Operations. Wherever possible, fair values for these contracts are obtained from quoted market sources. For contracts where no quoted market exists,
modeling techniques are employed using assumptions reflective of current market rates, yield curves 39
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS and forward prices, as applicable, to interpolate certain prices. The effect of using such modeling techniques is not material to Power’s financial results. Commodity Contracts Power 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,
market conditions, transmission availability and other events. Power manages its risk of fluctuations of energy price and availability through derivative instruments, such as forward purchase or sale
contracts, swaps, options, futures and FTRs. Cash Flow Hedges Power uses forward sale and purchase contracts, swaps and FTR contracts to hedge forecasted energy sales from its generation stations and to hedge related load obligations. Power also enters into
swaps and futures transactions to hedge the price of fuel to meet its fuel purchase requirements. These derivative transactions are designated and effective as cash flow hedges under SFAS 133. As of
September 30, 2006, the fair value of these hedges was $(292) million. These hedges, along with realized losses on hedges of $20 million retained in Accumulated Other Comprehensive Loss (OCL), resulted
in a $(183) million after-tax impact on OCL. As of December 31, 2005, the fair value of these hedges was $(951) million. These hedges, along with realized gains on hedges of $11 million retained in OCL,
resulted in a $(558) million after-tax impact on OCL. During the 12 months ending September 30, 2007, $102 million (after-tax) of net unrealized and realized losses on these commodity derivatives is
expected to be reclassified to earnings. Approximately $90 million of after-tax unrealized losses on these commodity derivatives in OCL is expected to be reclassified to earnings for the 12 months ending
September 30, 2008. Ineffectiveness associated with these hedges, as defined in SFAS 133, was immaterial at September 30, 2006. The expiration date of the longest-dated cash flow hedge is in 2009. Other Derivatives Power also enters into certain other contracts that are derivatives, but do not qualify for hedge accounting under SFAS 133. Most of these contracts are used for fuel purchases for generation
requirements and for electricity purchases for contractual sales obligations. Therefore, the changes in fair market value of these derivative contracts are recorded in Energy Costs or Operating Revenues, as
appropriate, on the Condensed Consolidated Statements of Operations. The net fair value of these instruments as of September 30, 2006 was $3 million. The net fair value of these instruments as of
December 31, 2005 was not material. Energy Holdings Other Derivatives TIE enters into electricity forward and capacity sale contracts to sell its 2,000 MW capacity for portions of the current calendar year and into the daily spot market. TIE also enters into gas purchase
contracts to specifically match the generation requirements to support the electricity forward sales contracts. Although these contracts fix the amount of revenue, fuel costs and cash flows, and thereby
provide financial stability to TIE, these contracts are, based on their terms, derivatives that do not meet the specific accounting criteria in SFAS 133 to qualify for the normal purchases and normal sales
exception, or to be designated as a hedge for accounting purposes. As a result, these contracts must be recorded at fair value. The net fair value of the open positions was approximately $53 million and
$(7) million as of September 30, 2006 and December 31, 2005, respectively. 40
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Interest Rates PSEG, PSE&G, Power and Energy Holdings PSEG, PSE&G, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s policy is to manage interest rate risk through the use of fixed and
floating rate debt and interest rate derivatives. Fair Value Hedges PSEG and Power In March 2004, Power issued $250 million of 3.75% Senior Notes due April 2009. PSEG used an interest rate swap to convert Power’s fixed-rate debt into variable-rate debt. The interest rate swap is
designated and effective as a fair value hedge. The fair value changes of the interest rate swap are fully offset by the fair value changes in the underlying debt. As of September 30, 2006 and December 31,
2005, the fair value of the hedge was $(9) million and $(10) million, respectively. Cash Flow Hedges PSEG, PSE&G and Energy Holdings PSEG, PSE&G and Energy Holdings use interest rate swaps and other interest rate derivatives to manage their exposures to the variability of cash flows, primarily related to variable-rate debt
instruments. The interest rate derivatives used are designated and effective as cash flow hedges. Except for PSE&G’s cash flow hedges, the fair value changes of these derivatives are initially recorded in
Accumulated Other Comprehensive Income (Loss). As of September 30, 2006, the fair value of these cash flow hedges was $(6) million, primarily at PSE&G. As of December 31, 2005, the fair value of these
cash flow hedges was $(17) million, including $(11) million and $(6) million at PSE&G and Energy Holdings, respectively. The $(5) million and $(11) million at PSE&G as of September 30, 2006 and December
31, 2005, respectively, is not included in OCL, as it is deferred as a Regulatory Asset and is expected to be recovered from PSE&G’s customers. During the 12 months ending September 30, 2007, $2 million of
unrealized losses (net of taxes) on interest rate derivatives in Accumulated Other Comprehensive Income (Loss) is expected to be reclassified to earnings at PSEG and Energy Holdings. As of September
30, 2006, there was essentially no hedge ineffectiveness associated with these hedges. The fair value amounts above as of December 31, 2005 do not include approximately $(60) million for the cash flow
hedges at Elcho, which had been reclassified into Discontinued Operations. Other Derivatives Energy Holdings As of September 30, 2006, Energy Holdings had no cross-currency interest rate swaps where changes in fair values of such swaps are recorded in Income from Equity Method Investments on the
Condensed Consolidated Statements of Operations. The fair values of these swaps at December 31, 2005 totaled approximately $(2) million. Foreign Currencies Energy Holdings Global is exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of its risks is that some of its foreign
subsidiaries and affiliates have functional currencies other than the consolidated reporting currency, the U.S. Dollar. Additionally, Global and certain of its foreign subsidiaries and affiliates have entered
into monetary obligations and maintain receipts/receivables in U.S. Dollars or currencies other than their own functional currencies. Global, a U.S. Dollar functional currency entity, is primarily exposed to 41
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS changes in the Euro, the Peruvian Nuevo Sol and the Chilean Peso. Changes in valuation of these currencies can impact the value of Global’s investments. Global has attempted to limit potential foreign
exchange exposure by entering into revenue contracts that adjust for changes in foreign exchange rates. Global also uses foreign currency forward, swap and option agreements to manage risk related to
certain foreign currency fluctuations. As of September 30, 2006, due to the strengthening of the Chilean Peso relative to the U.S. Dollar, the net cumulative foreign currency revaluations have increased the total amount of Global’s
Member’s Equity by $115 million. In November and December 2005, Energy Holdings purchased foreign currency options in order to hedge the majority of its 2006 expected earnings denominated in Brazilian Real, Chilean Pesos and
Peruvian Nuevo Soles. 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. Energy Holdings
terminated its remaining Brazilian Real options on June 28, 2006 following its sale of RGE. The fair value of the options outstanding at September 30, 2006 was immaterial. At December 31, 2005, the fair
value of the options was approximately $2 million. Hedges of Net Investments in Foreign Operations Energy Holdings In March 2004 and April 2004, Energy Holdings entered into four cross-currency interest rate swap agreements. The swaps are designed to hedge the net investment in a foreign subsidiary associated
with the exposure to the U.S. Dollar to Chilean Peso exchange rate. The fair value of the cross-currency swaps was $(25) million and $(33) million as of September 30, 2006 and December 31, 2005,
respectively. The change in fair value is recorded net of tax in Cumulative Translation Adjustment within Accumulated Other Comprehensive Income (Loss). As a result, Energy Holdings’ Member’s
Equity was reduced by $22 million as of September 30, 2006. Note 7. Comprehensive Income (Loss), Net of Tax For the Quarter Ended September 30, 2006: Net Income (Loss) Other Comprehensive Income Comprehensive Income (Loss) For the Quarter Ended September 30, 2005: Net Income (Loss) Other Comprehensive (Loss) Income Comprehensive Income (Loss) For the Nine Months Ended September 30, 2006: Net Income (Loss) Other Comprehensive Income Comprehensive Income (Loss) For the Nine Months Ended September 30, 2005: Net Income (Loss) Other Comprehensive (Loss) Income Comprehensive Income (Loss) 42
(UNAUDITED)
PSE&G
Power (A)
Energy
Holdings (B)
Other (C)
Consolidated
Total
(Millions)
$
88
$
205
$
101
$
(20
)
$
374
1
204
1
—
206
$
89
$
409
$
102
$
(20
)
$
580
$
115
$
125
$
39
$
(26
)
$
253
—
(291
)
101
(7
)
(197
)
$
115
$
(166
)
$
140
$
(33
)
$
56
$
200
$
394
$
251
$
(59
)
$
786
1
383
192
—
576
$
201
$
777
$
443
$
(59
)
$
1,362
$
282
$
106
$
140
$
(72
)
$
456
—
(395
)
81
(2
)
(316
)
$
282
$
(289
)
$
221
$
(74
)
$
140
(A)
Changes at Power primarily relate to SFAS 133 unrealized losses on derivative contracts that qualify for hedge accounting and unrealized gains and losses on Nuclear Decommissioning Trust
(NDT) Funds.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (B) Changes at Energy Holdings primarily relate to the realization of losses on Brazilian currency as a result of the sale of RGE and unrealized gains and losses on various derivative transactions. (C) Other primarily consists of activity at PSEG (as parent company), Services and intercompany eliminations. Note 8. Changes in Capitalization PSEG On September 1, 2006, PSEG began using treasury stock to settle the exercise of stock options. Previously, PSEG had purchased shares on the open market to meet the exercise of stock options.
Through September 30, 2006, PSEG issued approximately 121,067 shares of its treasury stock in connection with settling the stock options for approximately $5 million. During the nine months ended September 30, 2006, PSEG issued approximately 790,825 shares of its common stock under its Dividend Reinvestment Program and Employee Stock Purchase Program
for approximately $51 million. In February 2006, PSEG redeemed $154 million of its Subordinated Debentures underlying $150 million of Enterprise Capital Trust II, Floating Rate Capital Securities and its common equity
investment in the trust. PSE&G On June 23, 2006, PSE&G repaid at maturity $174 million of its Floating Rate Series A First and Refunding Mortgage Bonds. On March 1, 2006, PSE&G repaid at maturity $148 million of its 6.75% Series UU First and Refunding Mortgage Bonds. In September 2006, June 2006 and March 2006, Transition Funding repaid approximately $41 million, $35 million and $36 million, respectively, of its transition bonds. In June 2006, Transition Funding II repaid approximately $3 million of its transition bonds. Power In April 2006, Power repaid at maturity $500 million of its 6.875% Senior Notes. Energy Holdings In January 2006, Energy Holdings redeemed $309 million of its 7.75% Senior Notes due in 2007. On February 17, 2006, the maturity of the Odessa‑Ector Power Partners, L.P (Odessa) debt was extended to December 31, 2009. Interest on the debt is based on a spread (currently 2.25%) above
LIBOR. On September 29, 2006, an interest rate swap took effect, which converts the floating LIBOR interest rate on approximately 80% of Odessa’s debt to a fixed rate of 5.4275% through December 31,
2009. On
October 23, 2006, Energy Holdings redeemed $300 million of its $507 million
outstanding 8.625% Senior Notes due in 2008. Additionally, on September 20,
2006, Energy Holdings made a cash distribution to PSEG of $425 million in the
form of a return of capital. During the first nine months of 2006, Energy Holdings’ repaid approximately $37 million of non-recourse debt, of which $30 million was paid by Global, primarily related to Sociedad Austral de
Electricidad S.A. and TIE, $5 million by Resources and $2 million by EGDC. 43
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 9. Other Income and Deductions Other Income: For the Quarter Ended September 30, 2006: Interest and Dividend Income Disposition of Property NDT Fund Realized Gains NDT Interest and Dividend Income Other Total Other Income For the Quarter Ended September 30, 2005: Interest and Dividend Income Disposition of Property Gain on Investments NDT Fund Realized Gains NDT Interest and Dividend Income Foreign Currency Gains Other Total Other Income For the Nine Months Ended September 30, 2006: Interest and Dividend Income Disposition of Property NDT Fund Realized Gains NDT Interest and Dividend Income Foreign Currency Gains Change in Derivative Fair Value Other Total Other Income For the Nine Months Ended September 30, 2005: Interest and Dividend Income Disposition of Property Gain on Sale of Investments NDT Fund Realized Gains NDT Interest and Dividend Income Foreign Currency Gains Change in Derivative Fair Value Other Total Other Income 44
(UNAUDITED)
PSE&G
Power
Energy
Holdings
Other (A)
Consolidated
Total
(Millions)
$
3
$
3
$
12
$
(7
)
$
11
—
1
—
—
1
—
20
—
—
20
—
10
—
—
10
3
4
2
—
9
$
6
$
38
$
14
$
(7
)
$
51
$
2
$
1
$
1
$
2
$
6
—
5
—
—
5
—
—
—
8
8
—
60
—
—
60
—
8
—
—
8
—
—
4
—
4
1
—
—
—
1
$
3
$
74
$
5
$
10
$
92
$
9
$
10
$
22
$
(11
)
$
30
—
1
—
—
1
—
69
—
—
69
—
29
—
—
29
—
—
4
—
4
—
—
1
—
1
9
4
6
—
19
$
18
$
113
$
33
$
(11
)
$
153
$
6
$
4
$
10
$
1
$
21
—
5
—
—
5
—
—
1
8
9
—
100
—
—
100
—
25
—
—
25
—
—
5
—
5
—
—
1
—
1
1
1
1
—
3
$
7
$
135
$
18
$
9
$
169
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Other Deductions: For the Quarter Ended September 30, 2006: Donations Foreign Currency Losses Change in Derivative Fair Value NDT Fund Realized Losses and Expenses Loss on Extinguishment of Debt Environmental Reserves Other Total Other Deductions For the Quarter Ended September 30, 2005: Donations Foreign Currency Losses NDT Fund Realized Losses and Expenses Other Total Other Deductions For the Nine Months Ended September 30, 2006: Donations Foreign Currency Losses Change in Derivative Fair Value NDT Fund Realized Losses and Expenses Minority Interest Loss on Extinguishment of Debt Environmental Reserves Other Total Other Deductions For the Nine Months Ended September 30, 2005: Donations Foreign Currency Losses Change in Derivative Fair Value NDT Fund Realized Losses and Expenses Minority Interest Other Total Other Deductions 45
(UNAUDITED)
PSE&G
Power
Energy
Holdings
Other (A)
Consolidated
Total
(Millions)
$
—
$
—
$
—
$
1
$
1
—
—
2
—
2
—
—
1
—
1
—
12
—
—
12
—
—
12
—
12
—
15
—
—
15
—
—
1
—
1
$
—
$
27
$
16
$
1
$
44
$
—
$
—
$
—
$
14
$
14
—
—
1
—
1
—
12
—
—
12
1
1
2
—
4
$
1
$
13
$
3
$
14
$
31
$
2
$
—
$
—
$
1
$
3
—
—
8
—
8
—
—
3
—
3
—
44
—
—
44
—
—
—
1
1
—
—
12
—
12
—
15
—
—
15
—
1
4
—
5
$
2
$
60
$
27
$
2
$
91
$
1
$
1
$
—
$
14
$
16
—
—
12
—
12
—
—
3
—
3
—
31
—
—
31
—
—
—
1
1
1
1
2
(1
)
3
$
2
$
33
$
17
$
14
$
66
(A)
Other consists of reclassifications for minority interests in PSEG’s consolidated results of operations and intercompany eliminations at PSEG (as parent company).
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS An analysis of the tax provision expense is as follows: For the Quarter Ended September 30, 2006: Income (Loss) from Continuing Operations Before Income Taxes Tax Computed at the Statutory Rate Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments: State Income Taxes After Federal Benefit Rate Differential of Foreign Operations Plant Related Items Other Total Income Tax Expense (Benefit) Effective Income Tax Rate For the Quarter Ended September 30, 2005: Income (Loss) from Continuing Operations Before Income Taxes Tax Computed at the Statutory Rate Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments: State Income Taxes After Federal Benefit Repatriation Rate Differential of Foreign Operations Plant Related Items Other Total Income Tax Expense (Benefit) Effective Income Tax Rate For the Nine Months Ended September 30, 2006: Income (Loss) from Continuing Operations Before Income Taxes Tax Computed at the Statutory Rate Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments: State Income Taxes After Federal Benefit Rate Differential of Foreign Operations Plant Related Items Other Total Income Tax Expense (Benefit) Effective Income Tax Rate For the Nine Months Ended September 30, 2005: Income (Loss) from Continuing Operations Before Income Taxes Tax Computed at the Statutory Rate Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments: State Income Taxes After Federal Benefit Repatriation Rate Differential of Foreign Operations Plant Related Items Lease Rate Differential Other Total Income Tax Expense (Benefit) Effective Income Tax Rate 46
(UNAUDITED)
PSE&G
Power
Energy
Holdings
Other (A)
Consolidated
Total
(Millions)
$
157
$
360
$
121
$
(35
)
$
603
55
126
42
(12
)
211
12
23
(3
)
(2
)
30
—
—
(21
)
—
(21
)
4
—
—
—
4
(2
)
6
2
(1
)
5
$
69
$
155
$
20
$
(15
)
$
229
43.9
%
43.1
%
16.5
%
42.9
%
38.0
%
$
189
$
233
$
75
$
(45
)
$
452
67
82
26
(16
)
159
13
13
(1
)
—
25
—
—
9
—
9
—
—
(7
)
—
(7
)
(5
)
—
—
—
(5
)
(1
)
6
—
(3
)
2
$
74
$
101
$
27
$
(19
)
$
183
39.2
%
43.3
%
36.0
%
42.2
%
40.5
%
$
360
$
684
$
(6
)
$
(100
)
$
938
126
239
(2
)
(35
)
328
27
42
(8
)
(6
)
55
—
—
(24
)
—
(24
)
12
—
—
—
12
(5
)
9
3
1
8
$
160
$
290
$
(31
)
$
(40
)
$
379
44.4
%
42.4
%
N/A
40.0
%
40.4
%
$
473
$
528
$
170
$
(119
)
$
1,052
166
185
60
(42
)
369
33
30
(3
)
(1
)
59
—
—
9
—
9
—
—
(27
)
—
(27
)
(4
)
—
—
—
(4
)
—
—
2
—
2
(4
)
10
1
(3
)
4
$
191
$
225
$
42
$
(46
)
$
412
40.4
%
42.6
%
24.7
%
38.7
%
39.2
%
(A)
PSEG’s other activities include amounts applicable to PSEG (as parent company) that primarily relate to financing and certain administrative and general costs.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Note 11. Financial Information by Business Segments Information related to the segments of PSEG and its subsidiaries is detailed below: For the Quarter Ended September 30, 2006: Total Operating Revenues Income (Loss) from Continuing Operations Net Income (Loss) Preferred Securities Dividends/Preference Unit Distributions Segment Earnings (Loss) Gross Additions to Long-Lived Assets For the Quarter Ended September 30, 2005: Total Operating Revenues Income (Loss) from Continuing Operations Loss from Discontinued Operations, net of tax Loss on Disposal of Discontinued Operations, net of tax Net Income (Loss) Preferred Securities Dividends/Preference Unit Distributions Segment Earnings (Loss) Gross Additions to Long-Lived Assets For the Nine Months Ended September 30, 2006: Total Operating Revenues Income (Loss) from Continuing Operations Loss from Discontinued Operations, net of tax Income on Disposal of Discontinued Operations, net of tax Net Income (Loss) Preferred Securities Dividends/Preference Unit Distributions Segment Earnings (Loss) Gross Additions to Long Lived Assets For the Nine Months Ended September 30, 2005: Total Operating Revenues Income (Loss) from Continuing Operations (Loss) Income from Discontinued Operations, net of tax Loss on Disposal of Discontinued Operations, net of tax Net Income (Loss) Preferred Securities Dividends/Preference Unit Distributions Segment Earnings (Loss) Gross Additions to Long-Lived Assets 47
(UNAUDITED)
PSE&G
Power
Energy Holdings
Consolidated
Total
Resources
Global
Other (A)
Other (B)
(Millions)
$
2,017
$
1,489
$
40
$
358
$
3
$
(515
)
$
3,392
88
205
10
92
(1
)
(20
)
374
88
205
10
92
(1
)
(20
)
374
(1
)
—
—
—
—
1
—
87
205
10
92
(1
)
(19
)
374
133
123
—
17
—
2
275
$
1,934
$
1,444
$
52
$
280
$
2
$
(388
)
$
3,324
115
132
17
32
(1
)
(26
)
269
—
(6
)
—
(9
)
—
—
(15
)
—
(1
)
—
—
—
—
(1
)
115
125
17
23
(1
)
(26
)
253
(1
)
—
—
—
—
1
—
114
125
17
23
(1
)
(25
)
253
133
118
—
7
1
12
271
$
5,901
$
4,591
$
134
$
939
$
7
$
(2,056
)
$
9,516
200
394
49
(22
)
(3
)
(59
)
559
—
—
—
(1
)
—
—
(1
)
—
—
—
228
—
—
228
200
394
49
205
(3
)
(59
)
786
(3
)
—
—
—
—
3
—
197
394
49
205
(3
)
(56
)
786
392
316
1
36
—
3
748
$
5,559
$
4,234
$
141
$
769
$
7
$
(1,770
)
$
8,940
282
303
39
91
(3
)
(72
)
640
—
(19
)
—
13
—
—
(6
)
—
(178
)
—
—
—
—
(178
)
282
106
39
104
(3
)
(72
)
456
(3
)
—
—
(3
)
—
6
—
279
106
39
101
(3
)
(66
)
456
372
345
2
24
—
8
751
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS As of September 30, 2006: Total Assets Investments in Equity Method Subsidiaries As of December 31, 2005: Total Assets Investments in Equity Method Subsidiaries (B) PSEG’s other activities include amounts applicable to PSEG (as parent company) and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. No
gains or losses are recorded on any intercompany transactions; rather, all intercompany transactions are at cost or, in the case of the BGS and BGSS contracts between Power and PSE&G, at rates
prescribed by the BPU. For a further discussion of the intercompany transactions between Power and PSE&G, see Note 13. Related-Party Transactions. The net losses primarily relate to financing
and certain administrative and general costs at PSEG, as parent company. Note 12. Stock-Based Compensation PSEG As approved at the Annual Meeting of Stockholders in 2004, PSEG’s 2004 Long-Term Incentive Plan (2004 LTIP) replaced prior Long-Term Incentive Plans (the 1989 LTIP and 2001 LTIP). The 2004
LTIP is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance shares,
restricted stock, cash awards or any combination thereof. The types of long-term incentive awards that have been granted and remain outstanding under the LTIPs are non-qualified options to purchase
shares of PSEG’s common stock, restricted stock awards and performance unit awards. However, since 2004, only restricted stock has been granted. The 2004 LTIP currently provides for the issuance of equity awards with respect to approximately 13.0 million shares of common stock. As of September 30, 2006, there were 11.8 million shares
available for future awards under the 2004 LTIP. Stock Options Under the 2004 LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees of PSEG and its subsidiaries selected by the Organization
and Compensation Committee of PSEG’s Board of Directors, the plan’s administrative committee (Committee). Option awards are granted with an exercise price equal to the market price of PSEG’s
common stock at the grant date. The options generally vest based on three to five years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-
in-control, retirement, death or disability. Options are exercisable over a period of time designated by the Committee (but not prior to one year or longer than 10 years from the date of grant) and are
subject to such other terms and conditions as the Committee determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the Committee, by delivering
previously acquired shares of PSEG common stock. 48
(UNAUDITED)
PSE&G
Power
Energy Holdings
Consolidated
Total
Resources
Global
Other (A)
Other (B)
(Millions)
$
14,114
$
8,473
$
2,985
$
3,144
$
396
$
(398
)
$
28,714
—
—
5
844
—
—
849
$
14,291
$
8,945
$
2,871
$
3,799
$
385
$
(478
)
$
29,813
—
—
5
1,128
—
—
1,133
(A)
Energy Holdings’ other activities include amounts applicable to Energy Holdings (as parent company) and EGDC. The net losses primarily relate to financing and certain administrative and
general costs of Energy Holdings.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS On September 1, 2006, PSEG began using treasury stock to settle the exercise of stock options. Prior to September 1, 2006, PSEG had purchased shares on the open market to meet the exercise of
stock options. Restricted Stock Under the 2004 LTIP, PSEG has granted restricted stock awards to officers and other key employees. These shares are subject to risk of forfeiture until vested by continued employment. Restricted
stock generally vests annually over three years, but is considered outstanding at the time of grant, as the recipients are entitled to dividends and voting rights. Vesting may be accelerated upon certain
events, such as change in control (unless substituted with an equity award of equal value), retirement, death or disability. In addition, from 1998 to 2001, PSEG granted 210,000 shares of restricted stock to a key executive, which are subject to risk of forfeiture until vested by continued employment. The shares vest on a
staggered schedule through March 2007. PSEG issues restricted stock from treasury stock. Performance Units Under the 2004 LTIP, performance units were granted to certain key executives, which provide for payment in shares of PSEG common stock based on achievement of certain financial goals over the
three-year period from 2004 through 2006. The payout varies from 0% to 200% of the number of performance units granted depending on PSEG’s performance compared to the performance of other
companies in the Dow Jones Utilities Index. The performance units are credited with dividend equivalents in an amount equal to dividends paid on PSEG common stock up until January 1, 2007. Vesting
may be accelerated upon certain events such as change in control, retirement, death or disability. Stock-Based Compensation Effective January 1, 2006, PSEG adopted SFAS 123R. See Note 2. Recent Accounting Standards for a description of the adoption of SFAS 123R. As a result, all outstanding unvested stock options as
of January 1, 2006 are being expensed based on their grant date fair values, which were determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific
basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest. Prior to the adoption of SFAS 123R, PSEG recognized compensation expense for restricted stock over the vesting period based on the grant date fair market value of the shares. PSEG will continue to
recognize compensation expense over the vesting term. Also prior to the adoption of SFAS 123R, PSEG recognized compensation expense for performance units. The fair value of each performance unit was based on the grant date fair value of PSEG
common stock. The accrual of compensation cost was based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. The current accrual is
estimated at 100% of the original grant. The accrual is adjusted for subsequent changes in the estimated or actual outcome. Compensation cost from options, restricted stock and performance units is included in Operation and Maintenance Expense on PSEG’s Condensed Consolidated Statements of Operations and
amounted to approximately $3.4 million and $1.5 million for the quarters ended September 30, 2006 and 2005, respectively, and approximately $10.0 million and $4.9 million for the nine months ended
September 30, 2006 and 2005, respectively. The total income tax benefit recognized on PSEG’s Condensed Consolidated Statements of Operations was approximately $1.4 million and $0.6 million for the
quarters ended September 30, 2006 and 2005, respectively, and approximately $4.1 million and 49
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS $2.0 million for the nine months ended September 30, 2006 and 2005, respectively. Compensation cost capitalized as part of Property, Plant and Equipment was less than $0.1 million for each of the quarters
ended September 30, 2006 and 2005 and approximately $0.2 million for each of the nine months ended September 30, 2006 and 2005. Of the total compensation cost for the nine months ended September
30, 2006, approximately $0.8 million, or $0.5 million after-tax, related to the adoption of SFAS 123R, which was primarily due to expensing stock options for the first time. There was no impact on basic and
diluted earnings per share from the implementation of SFAS 123R because there were a relatively small number of outstanding unvested stock options as of the implementation date. Prior to the adoption of SFAS 123R, PSEG presented all tax benefits for deductions resulting from the exercise of share-based compensation as operating cash flows on the Condensed Consolidated
Statement of Cash Flows. SFAS 123R requires the benefits of tax deductions in excess of the taxes expensed on recognized compensation cost to be reported as financing cash flows. There was
approximately $13.1 million of excess tax benefits included as a financing cash inflow on the September 30, 2006 Condensed Consolidated Statement of Cash Flow. Total cash flow will remain unchanged
from what would have been reported under prior accounting rules. The following table illustrates the effect on Net Income and earnings per share if PSEG had applied the fair value recognition provisions of SFAS 123R for the quarter and nine months ended
September 30, 2005. Net Income, as Reported Add: Total Stock-Based Compensation Expensed During the Period, net of tax Deduct: Total Stock-Based Employee Compensation Expense Determined Under Fair Value-Based Method for All Awards, net of related tax
effects Pro Forma Net Income Earnings Per Share: Basic—as Reported Basic—Pro Forma Diluted—as Reported Diluted—Pro Forma Prior to the adoption of SFAS 123R, PSEG recognized the compensation cost of stock based awards issued to retirement eligible employees that fully or partially vest upon an employee’s retirement
over the nominal vesting period of performance, and recognized any remaining compensation cost at the date of retirement. In accordance with SFAS 123R, PSEG recognizes compensation cost of awards
issued after January 1, 2006 over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is eligible for retirement and the award vests. 50
(UNAUDITED)
Quarter Ended
September 30,
Nine Months Ended
September 30,
2005
2005
(Millions, except Share Data)
$
253
$
456
1
3
(2
)
(5
)
$
252
$
454
$
1.06
$
1.91
$
1.05
$
1.90
$
1.03
$
1.87
$
1.03
$
1.87
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS There were no options granted during 2005 or 2006. Changes in stock options for the nine months ended September 30, 2006 are summarized as follows: Options Outstanding at January 1, 2006 Granted Exercised Canceled Outstanding at September 30, 2006 Exercisable at September 30, 2006 The intrinsic value of options is the difference between the current market price and the exercise price. The total intrinsic value of options exercised during the nine months ended September 30, 2006
and 2005 was approximately $50 million and $56 million, respectively. During the nine months ended September 30, 2006 and 2005, cash received from stock options exercised was approximately
$75.2 million and $114.2 million, respectively. The tax benefit realized from stock options exercised during the nine months ended September 30, 2006 and 2005 was approximately $13.1 million and $22.9
million, respectively. As of September 30, 2006, there was approximately $0.4 million of unrecognized compensation cost related to stock options, which is expected to be recognized over a weighted average period of seven
months. Restricted Stock Information Changes in restricted stock for the nine months ended September 30, 2006 are summarized as follows: Options Outstanding at January 1, 2006 Granted Vested Canceled Outstanding at September 30, 2006 The weighted average grant date fair value per share was $51.91 for restricted stock awards granted during the nine months ended September 30, 2005. The total intrinsic value of restricted stock vested during the nine months ended September 30, 2006 was approximately $6.1 million. No restricted shares vested during the nine months ended
September 30, 2005. As of September 30, 2006, there was approximately $16.3 million of unrecognized compensation cost related to restricted stock, which is expected to be recognized over a weighted average period of 1.9
years. Performance Units Information As of September 30, 2006, 82,700 performance units were outstanding and unvested, net of 900 units forfeited in the nine-month period then ended. Approximately 8,700 dividend equivalents had 51
(UNAUDITED)
Shares
Weighted
Average
Exercise
Price
Weighted
Average
Remaining
Contractual
Term
Aggregate
Intrinsic
Value
3,981,555
$
41.07
—
—
(1,895,655
)
39.67
(14,266
)
42.75
2,071,634
$
42.33
5.7
$
39,064,982
1,654,253
$
42.22
5.3
$
31,379,460
Shares
Weighted
Average
Grant
Date
Fair
Value
Weighted
Average
Remaining
Contractual
Term
Aggregate
Intrinsic
Value
466,744
$
56.69
43,800
66.53
(87,047
)
51.90
(9,370
)
59.71
414,127
$
58.67
1.7
$
25,340,431
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS accrued on these performance units. The grant date fair value of the performance units is $42.75 per unit. Assuming performance units are paid out at the 100% performance level, the total intrinsic value of performance units outstanding at September 30, 2006 was approximately $5.6 million. As of September 30, 2006, there was approximately $0.4 million of unrecognized compensation cost related to performance units, which is expected to be recognized over the next three months. Outside Directors During 2006, each director who was not an officer of PSEG or its subsidiaries and affiliates will be paid an annual retainer of $50,000. Pursuant to the Compensation Plan for Outside Directors, a
certain percentage, currently 50%, of the annual retainer is paid in PSEG common stock. PSEG also maintains a Stock Plan for Outside Directors (Stock Plan) pursuant to which directors of PSEG who are not employees of PSEG or its subsidiaries receive a restricted stock award, currently
1,000 shares per year, for each year of service as a director. The restrictions on the stock granted under the Stock Plan provide that the shares are subject to forfeiture if the director leaves service at any
time prior to the Annual Meeting of Stockholders following his or her 70th birthday. This restriction would be deemed to have been satisfied if the director’s service were terminated after a “change in
control” as defined in the Stock Plan or if the director were to die in office. PSEG also has the ability to waive this restriction for good cause shown. Restricted stock may not be sold or otherwise
transferred prior to the lapse of the restrictions. Dividends on shares held subject to restrictions are paid directly to the director who has the right to vote the shares. The fair value of these shares is recorded
as compensation expense on the Condensed Consolidated Statements of Operations. Compensation expense for the Stock Plan was less than $0.1 million for each of the quarters ended September 30, 2006
and 2005 and approximately $0.4 million for each of the nine months ended September 30, 2006 and 2005. Employee Stock Purchase Plan PSEG maintains an employee stock purchase plan for all eligible employees of PSEG and its subsidiaries. Under the plan, shares of PSEG common stock may be purchased at 95% of the fair market
value through payroll deductions. In any year, employees may purchase shares having a value not exceeding 10% of their base pay. During the nine months ended September 30, 2006 and 2005, employees
purchased 36,380 and 45,657 shares at an average price of $62.12 and $54.65 per share, respectively. As of September 30, 2006, 1.9 million shares were available for future issuance under this plan. Note 13. Related-Party Transactions The majority of the following discussion relates to intercompany transactions, which are eliminated during the consolidation process in accordance with GAAP. BGS and BGSS Contracts PSE&G and Power PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements through March 2007.
Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. 52
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The amounts which Power charged to PSE&G for BGS and BGSS are presented below: BGS BGSS As of September 30, 2006 and December 31, 2005, Power had net receivables from PSE&G of approximately $145 million and $454 million, respectively, primarily related to the BGS and BGSS
contracts. These transactions were properly recognized on each company’s stand-alone financial statements and were eliminated when preparing PSEG’s Condensed Consolidated Financial Statements. In
addition, as of September 30, 2006 and December 31, 2005, PSE&G had a payable
to Power of approximately $198 million and a receivable of approximately $152
million, respectively, related to gas supply hedges Power entered into for BGSS. Services PSE&G, Power and Energy Holdings Services provides and bills administrative services to PSE&G, Power and Energy Holdings. In addition, PSE&G, Power and Energy Holdings have other payables to Services, including amounts related to
certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies. The billings for administrative services and payables are presented below: PSE&G Power Energy Holdings These transactions were properly recognized on each company’s stand-alone financial statements and were eliminated when preparing PSEG’s Condensed Consolidated Financial Statements. PSE&G,
Power and Energy Holdings believe that the costs of services provided by Services approximate market value for such services. Tax Sharing Agreements PSEG, PSE&G, Power and Energy Holdings PSE&G, Power and Energy Holdings had (payables to) receivables from PSEG related to taxes as follows: PSE&G Power Energy Holdings 53
(UNAUDITED)
Power’s Billings for the
Quarters Ended
September 30,
Nine Months Ended
September 30,
2006
2005
2006
2005
(Millions)
$
330
$
172
$
594
$
395
$
175
$
203
$
1,435
$
1,325
Services’ Billings for the
Quarters Ended
September 30,
Nine Months Ended
September 30,
Payable to Services as of
2006
2005
2006
2005
September 30,
2006
December 31,
2005
(Millions)
$
50
$
51
$
158
$
154
$
27
$
34
$
29
$
39
$
99
$
114
$
14
$
21
$
4
$
4
$
13
$
13
$
1
$
2
(Payable to) Receivable from PSEG
As of
September 30, 2006
December 31, 2005
(Millions)
$
(39
)
$
(59
)
$
9
$
4
$
(77
)
$
(12
)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Affiliate Loans and Advances PSEG and Power As of September 30, 2006 and December 31, 2005, Power had a demand note payable to PSEG of approximately $68 million and $202 million, respectively, for short-term funding needs. PSEG and Energy Holdings As of September 30, 2006 and December 31, 2005, Energy Holdings had a demand note receivable due from PSEG of $374 million and $409 million, respectively. These notes reflect the investment of
Energy Holdings’ excess cash with PSEG. PSE&G and Services As of each of September 30, 2006 and December 31, 2005, PSE&G had advanced working capital to Services of approximately $33 million. This amount is included in Other Noncurrent Assets on
PSE&G’s Condensed Consolidated Balance Sheets. Power and Services As of each of September 30, 2006 and December 31, 2005, Power had advanced working capital to Services of approximately $17 million. This amount is included in Other Noncurrent Assets on
Power’s Condensed Consolidated Balance Sheets. Other PSEG and PSE&G As of September 30, 2006 and December 31, 2005, PSE&G had net receivables from PSEG of approximately $3 million and $6 million, respectively, related to amounts that PSEG had collected on
PSE&G’s behalf. PSEG and Power As of September 30, 2006 and December 31, 2005, Power had net receivables from PSEG of approximately $1 million related to amounts that PSEG had collected on Power’s behalf. PSEG and Energy Holdings As of September 30, 2006 and December 31, 2005, Energy Holdings had net receivables from PSEG of approximately $3 million and $1 million, respectively, primarily for interest due on the demand
note receivable from PSEG. Energy Holdings and PSE&G As of September 30, 2006 and December 31, 2005, Energy Holdings had a receivable of approximately $2 million and $3 million, respectively, related to efficiency incentive initiatives performed for
PSE&G’s customers. Energy Holdings recorded revenues for such services of approximately $2 million and $6 million for the quarters ended September 30, 2006 and 2005, respectively, and approximately $9
million and $18 million for the nine months ended September 30, 2006 and 2005, respectively. Changes in Capitalization PSEG and Energy Holdings On September 20, 2006, Energy Holdings made a cash contribution to PSEG of $425 million in the form of a return of capital. 54
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Power Each series of Power’s Senior Notes and Pollution Control Notes is fully and unconditionally and jointly and severally guaranteed by Fossil, Nuclear and ER&T. The following table presents condensed
financial information for the guarantor subsidiaries, as well as Power’s non-guarantor subsidiaries. For the Quarter ended September 30, 2006 Revenues Operating Expenses Operating Income Equity Earnings (Losses) of Subsidiaries Other Income Other Deductions Interest Expense Income Taxes Net Income (Loss) For the Quarter ended September 30, 2005 Revenues Operating Expenses Operating (Loss) Income Equity Earnings (Losses) of Subsidiaries Other Income Other Deductions Interest Expense Income Taxes Loss on Discontinued Operations, Including Loss on Disposal, net of tax benefit Net Income (Loss) 55
(UNAUDITED)
Power
Guarantor
Subsidiaries
Other
Subsidiaries
Consolidating
Adjustments
Consolidated
Total
(Millions)
$
—
$
1,720
$
33
$
(264
)
$
1,489
—
1,322
32
(261
)
1,093
—
398
1
(3
)
396
205
(9
)
—
(196
)
—
44
49
4
(59
)
38
—
(27
)
—
—
(27
)
(45
)
(42
)
(19
)
59
(47
)
1
(164
)
6
2
(155
)
$
205
$
205
$
(8
)
$
(197
)
$
205
$
—
$
1,673
$
27
$
(256
)
$
1,444
1
1,466
30
(257
)
1,240
(1
)
207
(3
)
1
204
135
(17
)
—
(118
)
—
35
74
—
(35
)
74
—
(11
)
(1
)
(1
)
(13
)
(40
)
(13
)
(15
)
36
(32
)
(4
)
(105
)
6
2
(101
)
—
—
(7
)
—
(7
)
$
125
$
135
$
(20
)
$
(115
)
$
125
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS For the Nine Months ended September 30, 2006 Revenues Operating Expenses Operating (Loss) Income Equity Earnings (Losses) of Subsidiaries Other Income Other Deductions Interest Expense Income Taxes Net Income (Loss) For the Nine Months ended September 30, 2005 Revenues Operating Expenses Operating (Loss) Income Equity Earnings (Losses) of Subsidiaries Other Income Other Deductions Interest Expense Income Taxes Loss on Discontinued Operations, Including Loss on Disposal, net of tax benefit Net Income (Loss) For the Nine Months ended September 30, 2006 Net Cash Provided By Operating Activities Net Cash Provided By (Used In) Investing Activities Net Cash Used In Financing Activities For the Nine Months ended September 30, 2005 Net Cash (Used in) Provided By Operating Activities Net Cash Provided By (Used in) Investing Activities Net Cash Provided By (Used In) Financing Activities 56
(UNAUDITED)
Power
Guarantor
Subsidiaries
Other
Subsidiaries
Consolidating
Adjustments
Consolidated
Total
(Millions)
$
—
$
5,309
$
103
$
(821
)
$
4,591
1
4,545
103
(820
)
3,829
(1
)
764
—
(1
)
762
403
(32
)
—
(371
)
—
126
138
5
(156
)
113
—
(59
)
(1
)
—
(60
)
(142
)
(88
)
(57
)
156
(131
)
8
(320
)
21
1
(290
)
$
394
$
403
$
(32
)
$
(371
)
$
394
$
—
$
4,900
$
98
$
(764
)
$
4,234
1
4,401
84
(764
)
3,722
(1
)
499
14
—
512
116
(208
)
—
92
—
102
135
1
(103
)
135
—
(31
)
(1
)
(1
)
(33
)
(110
)
(47
)
(32
)
103
(86
)
(1
)
(231
)
7
—
(225
)
—
—
(197
)
—
(197
)
$
106
$
117
$
(208
)
$
91
$
106
$
318
$
1,303
$
10
$
(711
)
$
920
$
182
$
(1,237
)
$
29
$
737
$
(289
)
$
(500
)
$
(69
)
$
(39
)
$
(26
)
$
(634
)
$
(1,188
)
$
44
$
1,112
$
308
$
276
$
88
$
202
$
(25
)
$
(434
)
$
(169
)
$
1,100
$
(237
)
$
(1,087
)
$
126
$
(98
)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS As of September 30, 2006 Current Assets Property, Plant and Equipment, net Investment in Subsidiaries Noncurrent Assets Total Assets Current Liabilities Noncurrent Liabilities Long-Term Debt Member’s Equity Total Liabilities and Member’s Equity As of December 31, 2005 Current Assets Property, Plant and Equipment, net Investment in Subsidiaries Noncurrent Assets Total Assets Current Liabilities Noncurrent Liabilities Long-Term Debt Member’s Equity Total Liabilities and Member’s Equity PSE&G Gas Base Rate Case On
October 27, 2006, PSE&G reached a settlement agreement in the Gas Base Rate
Case with the BPU Staff, New Jersey Public Advocate (Advocate) and other intervening
parties. The agreement has been approved by the Office of Administrative Law
(OAL) and submitted to the BPU for its approval. The agreement provides for
an annual increase in gas revenues of $40 million or approximately 1.1%. In
addition, the settlement provides for an adjustment to lower book depreciation
and amortization expense for PSE&G by approximately $26 million annually
and the amortization of accumulated cost of removal that will further reduce
depreciation and amortization expense by $13 million annually for five years. Electric Distribution Financial Review On October 27, 2006, PSE&G reached a settlement agreement in the Electric Distribution Financial Review with the BPU Staff, Advocate and other intervening parties concerning the excess
depreciation rate credit. The agreement, which has been submitted to the BPU for its approval, authorizes a reduction in the credit to $22 million resulting in additional revenue to PSE&G of approximately
$47 million annually based on current sales volumes. The settlements above are not final until approved by the BPU and include a restriction against any further base rate changes becoming effective before November 15, 2009. In addition, PSE&G must file
a joint electric and gas petition for any future base rate increases. 57
(UNAUDITED)
Power
Guarantor
Subsidiaries
Other
Subsidiaries
Consolidating
Adjustments
Consolidated
Total
(Millions)
$
1,990
$
3,212
$
220
$
(3,450
)
$
1,972
151
3,357
1,488
—
4,996
4,302
421
—
(4,723
)
—
189
1,406
16
(106
)
1,505
$
6,632
$
8,396
$
1,724
$
(8,279
)
$
8,473
$
116
$
3,158
$
1,195
$
(3,432
)
$
1,037
84
936
108
(123
)
1,005
2,817
—
—
—
2,817
3,615
4,302
421
(4,724
)
3,614
$
6,632
$
8,396
$
1,724
$
(8,279
)
$
8,473
$
2,584
$
2,616
$
251
$
(2,876
)
$
2,575
143
3,271
1,466
—
4,880
3,507
453
—
(3,960
)
—
179
1,609
17
(315
)
1,490
$
6,413
$
7,949
$
1,734
$
(7,151
)
$
8,945
$
695
$
3,213
$
1,146
$
(2,877
)
$
2,177
63
1,268
96
(313
)
1,114
2,817
—
—
—
2,817
2,838
3,468
492
(3,961
)
2,837
$
6,413
$
7,949
$
1,734
$
(7,151
)
$
8,945
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A) Following are the significant changes in or additions to information reported in the 2005 Annual Report on Form 10-K affecting the consolidated financial condition and the results of operations. This
discussion refers to the Condensed Consolidated Financial Statements (Statements) and the related Notes to Condensed Consolidated Financial Statements (Notes) and should be read in conjunction with
such Statements and Notes. This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power), and PSEG Energy
Holdings L.L.C. (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make
representations only as to itself and make no representations as to any other company. TERMINATION OF MERGER AGREEMENT PSEG, PSE&G, Power and Energy Holdings On December 20, 2004, PSEG entered into an Agreement and Plan of Merger (Merger Agreement) with Exelon Corporation (Exelon) providing for a merger of PSEG with and into Exelon (Merger).
On September 14, 2006, PSEG received from Exelon a formal notice of termination of the Merger under the provisions of the Merger Agreement. OVERVIEW OF 2006 AND FUTURE OUTLOOK PSEG PSEG’s business consists of four reportable segments, which are PSE&G, Power and the two direct subsidiaries of Energy Holdings: PSEG Global L.L.C. (Global) and PSEG Resources L.L.C.
(Resources). The following is a discussion of the markets in which PSEG and its subsidiaries compete, the corporate strategy for the conduct of PSEG’s businesses within these markets, significant events
that have occurred during the first nine months of 2006 and expectations for the full year 2006 and beyond. Throughout the Merger approval process, PSEG maintained a stand-alone business capability in the event the Merger did not close. PSEG took steps to improve its financial stability and reduce risk,
including opportunistically monetizing certain of its assets that no longer had a strategic fit, reducing international exposure, paying down debt, significantly hedging its future generation business and
improving the performance and reliability of its nuclear and fossil units. For the nine months ended September 30, 2006, PSEG had Net Income of $786 million, or $3.12 per share, discussed below in Results of Operations. Included in Net Income is an after-tax gain of $228
million, or $0.90 per share, related to the sale of two generating stations in Poland, which is included in Income from Discontinued Operations and an after-tax loss of approximately $178 million, or $0.70
per share, related to the sale of Rio Grande Energia S.A. (RGE), an electric distribution company in Brazil. The loss at RGE primarily related to devaluation of the Brazilian Real subsequent to Global’s
acquisition of its interests in RGE in 1997. Also included in Net Income for the nine months ended September 30, 2006 are net unrealized gains of approximately $40 million, after tax, or $0.16 per share,
related to non-trading mark-to-market (MTM) accounting and Merger-related costs of approximately $7 million, after-tax, or $0.03 per share. In order to provide a more consistent and comparable measure of the performance of its businesses to help shareholders understand performance trends, earnings projections for PSEG and its
subsidiaries consist of projected Income from Continuing Operations, excluding impacts from asset sales and Merger-related costs and do not contemplate any potential impacts from MTM accounting.
Excluding such items, PSEG continues to project earnings for 2006 to range from $3.45 to $3.75 per share, although the range of expected earnings from each of PSE&G, Power and Energy Holdings has been
revised from originally announced projections. PSE&G’s guidance has decreased due to the prolonged lack of rate relief; Power’s guidance has increased due to improved operations and stronger energy 58
markets and Energy Holdings’ guidance has increased due to a strong Texas market. The projections for 2006 also include $60 million to $70 million of expenses at the PSEG parent level, primarily for
financing costs. PSEG expects operating cash flows in 2006 and beyond to be sufficient to meet capital needs and dividend requirements and may employ any excess cash to reduce debt, invest in its businesses, increase
dividends or, in the longer term, repurchase shares. On October 17, 2006, PSEG’s Board of Directors approved a common stock dividend of $0.57 per share for the fourth quarter of 2006, reflecting an
indicated annual dividend rate of $2.28 per share. Several key factors that will drive PSEG’s future success are energy, capacity and fuel prices, performance of Power’s and Energy Holdings’ generating facilities and PSE&G’s ability to attain a
reasonable rate of return under its regulated rate structure. The stability of international economies, Resources’ ability to realize tax benefits associated with its leveraged lease investments and the
accounting and tax treatment associated with such investments are also key factors that will influence Energy Holdings’ contribution to PSEG’s future success. PSE&G PSE&G operates as an electric and gas public utility in New Jersey under cost-based regulation by the New Jersey Board of Public Utilities (BPU) for its distribution operations and by the Federal
Energy Regulatory Commission (FERC) for its electric transmission and wholesale sales operations. Consequently, PSE&G’s earnings are largely determined by the regulation of its rates by those agencies. Commodity costs continue to put upward pressure on customer charges and have contributed to flat electric delivery sales and a decline in year-over-year gas delivery sales. On June 1, 2006, new
electric Basic Generation Service (BGS)-Fixed Price (FP) rates went into effect and residential customers’ bills increased by approximately 14%. While gas prices have stabilized and even declined recently,
the current cost to a residential Basic Gas Supply Service (BGSS) customer is approximately 24% higher than a year ago. The 1% increase in the New Jersey sales tax on July 15, 2006 also increased
customer charges. Since sales tax and commodity price increases are passed through to customers, they do not increase PSE&G’s earnings but they can have a negative impact on PSE&G’s earnings if they
result in reduced customer demand. PSE&G
made its 2006/2007 BGSS filing on May 26, 2006. In this filing, PSE&G requested
a reduction in annual BGSS gas revenues of approximately $19.7 million (excluding
losses and New Jersey Sales and Use Tax) or approximately a 1.0% decrease to
be implemented for service rendered on and after October 1, 2006 or earlier.
Additionally, PSE&G requested an increase in its Balancing Charge. Since
the time of the filing, prices of gas futures have dropped significantly and
as a result, additional BGSS data has been requested by and provided to the
BPU. Settlement discussions with the BPU Staff have been completed and a new
Stipulation has been executed by the parties. This new Stipulation, which requires
BPU approval, results in a decrease in annual BGSS revenues of approximately
$120 million, which is approximately a 6% reduction in a typical residential
gas customer’s bill. The Stipulation did not include any change in the
balancing charge, as requested. On
September 30, 2005, PSE&G filed a petition with the BPU seeking a $133 million
increase in annual gas base rates, an overall 3.78% increase. On October 27,
2006, PSE&G reached a settlement agreement in the Gas Base Rate Case with
the BPU Staff, New Jersey Public Advocate (Advocate) and other intervening parties.
The agreement has been approved by the Office of Administrative Law (OAL) and
submitted to the BPU for its approval. The agreement provides for an annual
increase in gas revenues of $40 million or approximately 1.1%. In addition,
the settlement provides for an adjustment to lower book depreciation expense
for PSE&G by approximately $26 million annually and the amortization of
accumulated cost of removal that will further reduce depreciation and amortization
expense by $13 million annually for five years. On October 27, 2006, PSE&G also reached a settlement agreement in the Electric Distribution Financial Review with the BPU Staff, Advocate and other intervening parties concerning the excess
depreciation rate credit. The agreement, which has been submitted to the BPU for its approval, 59
authorizes
a reduction in the credit to $22 million, resulting in additional revenue to
PSE&G of approximately $47 million annually based on current sales volumes. The settlements above are not final until approved by the BPU and include a restriction against any further base rate changes becoming effective before November 15, 2009. In addition, PSE&G must file
a joint electric and gas petition for any future base rate increases. For
the nine months ended September 30, 2006, PSE&G had Net Income of $200 million.
As a result of the substantial decline in earnings at PSE&G as compared
to 2005 due to the delay in decisions for the Gas Base Rate Case and the Electric
Distribution Financial Review, PSE&G lowered its earnings guidance from
a range of $315 million to $335 million to a range of $250 million to $270 million
in 2006. As disclosed previously, these amounts exclude any Merger-related costs. The risks to PSE&G’s business generally relate to the treatment of the various rate and other issues by the state and federal regulatory agencies, specifically the BPU and FERC. In 2006 and beyond,
PSE&G’s success will depend, in part, on its ability to attain a reasonable rate of return, continue cost containment initiatives, maintain system reliability and safety levels and continued recovery, with an
adequate return, of the regulatory assets it has deferred and the investments it plans to make in its electric and gas transmission and distribution system. Since PSE&G earns no margin on the commodity
portion of its electric and gas sales through tariff agreements, there is no anticipated commodity price volatility for PSE&G. Power Power is an electric generation and wholesale energy marketing and trading company that is focused on a generation market extending from Maine to the Carolinas and the Atlantic Coast to Indiana.
Power’s principal operating subsidiaries, PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T) are regulated by FERC. Through its subsidiaries, Power
seeks to balance its generating capacity, fuel requirements and supply obligations through integrated energy marketing and trading, enhance its ability to produce low-cost energy through efficient nuclear
operations and pursue modest growth based on market conditions. Changes in the operation of Power’s generating facilities, fuel and capacity prices, expected contract prices, capacity factors or other
assumptions could materially affect its ability to meet earnings targets and/or liquidity requirements. In addition to the electric generation business described above, Power’s revenues include gas supply
sales under the BGSS contract with PSE&G. As a merchant generator, Power’s profit is derived from selling under contract or on the spot market a range of diverse products such as energy, capacity, emissions credits, congestion credits and a
series of energy-related products that the system operator uses to optimize the operation of the energy grid, known as ancillary services. Accordingly, the prices of commodities, such as electricity, gas, coal
and emissions, as well as the availability of Power’s diverse fleet of generation units to produce these products, can have a material effect on Power’s profitability. Power seeks to mitigate volatility in its results by contracting in advance for a significant portion of its anticipated electric output and fuel needs. Power believes this contracting strategy increases
stability of earnings and cash flow. By keeping some portion of its output uncontracted, Power is able to retain some ability to take advantage of market changes as well as provide some protection in the
event of unexpected generation outages. In a changing market environment, this hedging strategy may cause Power’s realized prices to be materially different than current market prices. At the present time, a significant portion of Power’s
existing contractual obligations, entered into during lower-priced periods, resulted in lower margins than would have been the case if no or little hedging activity had been conducted. Alternatively, in a
falling price environment, this hedging strategy will tend to create margins in excess of those implied by the then current market. For Power’s BGSS contracts, commodity costs are passed on to residential customers. Any differences from the BGSS contract prices are deferred by PSE&G for future recovery. For commercial and
industrial (C&I) customers, a tariff structure is applied that is adjusted monthly based on the current New York Mercantile Exchange (NYMEX) prices. During the first nine months of 2006, market 60
prices for natural gas declined from the historically high price levels experienced in the first nine months of 2005 while the cost of gas in inventory changed less, which reduced Power’s margins as compared
to 2005. For the nine months ended September 30, 2006, Power had Net Income of $394 million. Power has raised its earnings guidance from a range of $475 million to $525 million to a range of $500 million to
$550 million for 2006, reflecting improved results and anticipated continued strong operating performance of its nuclear and fossil stations and attractive contracting opportunities in current energy markets.
The guidance range does not include Merger-related costs and does not contemplate any potential impacts from MTM accounting. The net unrealized gains (after-tax) related to Power’s non-trading activity
were $12 million and $2 million for the quarter and nine months ended September 30, 2006, respectively. A key factor in Power’s ability to achieve its objectives is its capability to operate its nuclear and fossil stations at sufficient capacity factors to limit the need to purchase higher-priced electricity to
satisfy its obligations. Power’s ability to achieve its objectives will also depend on the implementation of reasonable capacity markets. Power’s ability to benefit from any future increases in market prices
will depend, to a large extent, on efficient power plant operations, especially for its low-cost nuclear and coal-fired facilities. Power must also be able to effectively manage its construction projects and
continue to economically operate its generation facilities under increasingly stringent environmental requirements. In addition, with an increase in competition and market complexity and constantly
changing forward prices, there is no assurance that Power will be able to contract its output at attractive prices. While these increases may have a potentially significant beneficial impact on margins, they
could also raise any replacement power costs that Power may incur in the event of unanticipated outages, and could also further increase liquidity requirements as a result of contract obligations. For
additional information on liquidity requirements, see Liquidity and Capital Resources. Energy Holdings Energy Holdings’ operations are principally conducted through its subsidiaries: Global, which has invested in international rate-regulated distribution companies and domestic and international
merchant generation companies, and Resources, which primarily invests in energy-related leveraged leases. In September 2006, Energy Holdings had accumulated excess cash of over $750 million from the sales of Global’s two investments in generating stations in Poland, the sale of its interest in RGE, a
distribution company in Brazil and from ongoing operations. Energy Holdings used this cash to return $425 million of capital to PSEG in September 2006 and call $300 million of its outstanding $507 million
2008 Senior Notes, which were redeemed on October 23, 2006. Including such amounts, Energy Holdings has returned a total of $1.3 billion of capital to PSEG and redeemed $900 million of its Senior
Notes since 2004. After this redemption, Energy Holdings has $1.15 billion of Senior Notes outstanding with the next maturity of $207 million in 2008. For the nine months ended September 30, 2006, Energy Holdings had Net Income of $251 million, which includes a net gain of $51 million related to the asset sales discussed above. During the year,
Energy Holdings’ earnings guidance for 2006, which excludes the $51 million net gain, has been increased from a range of $155 million to $175 million to a range of $185 million to $205 million. The increase
was largely driven by the performance of the Texas generating stations of Global’s subsidiary, Texas Independent Energy, L.P. (TIE). Spark margins in Texas increased substantially in 2005 and continued
at high levels through the summer of 2006. The plants’ high availability factors have enabled TIE to benefit from the increased price levels in the marketplace. In addition, during the fall of 2005, TIE
entered into long-term contracts for a portion of its output that is subject to MTM accounting treatment. The net unrealized gains (after-tax) related to such contracts were $29 million and $38 million for the
quarter and nine months ended September 30, 2006, respectively. Approximately $11 million, after-tax of the unrealized gains are expected to reverse during the fourth quarter of 2006. Although market
prices have significantly softened in recent months and are inherently volatile, TIE is expected to continue to be a major contributor to Energy Holdings’ earnings. Stable earnings from Global’s South
American distribution companies also continue to provide a sustainable platform for Energy Holdings’ business. 61
Global Although Global continues to produce significant earnings and operating cash flow, the returns on several of the investments in its international portfolio have not been commensurate with the level of
risk associated with international investments in developing energy markets. As a result, since 2003, Global has refocused its strategy from one of growth to one that places emphasis on increasing the
efficiency and returns of its existing assets. In the first half of 2006, Global successfully closed on two major transactions as part of its strategy to opportunistically monetize assets that no longer have a strategic fit. In May 2006, Global completed
the sale of its ownership interests in two generating facilities in Poland for $476 million, recording an after-tax gain of $228 million, which is included in Income from Discontinued Operations. In June 2006,
Global completed the sale of its 32% interest in RGE for $185 million, resulting in an after-tax loss of $178 million. Together, Global received gross sales proceeds of $654 million, or approximately
$612 million after taxes, and recorded a net after-tax gain of approximately $51 million. In May 2006, Global also entered into an agreement to sell its 46% ownership interest in Dhofar Power Company S.A.O.C. (Dhofar Power), a generation facility and distribution system in Oman, for
proceeds of approximately $33 million, which is the approximate book value. The sale of Dhofar Power, which is contingent upon attaining consents from Dhofar Power’s lenders and no objections from the
Government of Oman, is expected to be completed in the fourth quarter of 2006. In May 2006, Global also converted its loans to Prisma 2000 S.p.A. (Prisma) to equity, thereby increasing its ownership
interest from 50% to 85% and obtaining operating control. Prisma is a joint venture that operates several biomass generation plants in Italy. See Note 3. Discontinued Operations, Dispositions and
Acquisitions of the Notes for further discussion. Global’s results are driven by the performance of the domestic and international generation and distribution companies in which it invests. Global’s earnings and cash flows from its investment in
distribution companies are impacted by the tariffs determined by the regulatory agencies in periodic rate cases and its ability to control costs and maintain reliable operations. With respect to its investment
in generation companies, Global’s earnings and cash flows are impacted by the operating factors of the plants, including their availability factors, heat rates, fuel costs and environmental restrictions.
Although some of Global’s investments have long-term power purchase agreements, several of its projects, including its operations in Texas, have a substantial amount of uncontracted capacity and are
therefore affected by prevailing market prices, which can be volatile. Also, the economic and political conditions in certain countries where Global has investments present risks that may be different or
more significant than those found in the U.S., including renegotiation or nullification of existing contracts, changes in law or tax policy, nationalization, expropriation and other factors. Operations in foreign
countries also present risks associated with currency exchange and convertibility, inflation and repatriation of earnings. Resources Resources has primarily invested in energy-related leveraged leases. Resources is focused on maintaining its current investment portfolio and does not expect to make any new investments. Resources’
ability to realize tax benefits associated with its leveraged lease investments is dependent upon taxable income generated by its affiliates. Resources’ earnings and cash flows are expected to decrease in the
future as the investment portfolio matures. Resources faces risks related to potential changes in the current accounting and tax treatment of certain investments in leveraged leases. For additional
information on current accounting and tax treatment of Resources’ leveraged lease investments, see Note 2. Recent Accounting Standards and Note 5. Commitments and Contingent Liabilities. Resources
also faces risks with regard to the creditworthiness of its counterparties, specifically certain lessees that collectively comprise a substantial portion of Resources’ investment portfolio. 62
The results for PSEG, PSE&G, Power and Energy Holdings for the quarter and nine months ended September 30, 2006 and 2005 are presented below: PSE&G Power Energy Holdings: Global (D) Resources Other (A) Total Energy Holdings Other (B) PSEG Income from Continuing Operations Income (Loss) from Discontinued Operations, including Gain/(Loss) on Disposal (C) PSEG Net Income PSE&G Power Energy Holdings: Global Resources Other (A) Total Energy Holdings Other (B) PSEG Income from Continuing Operations Income (Loss) from Discontinued Operations, including Gain/(Loss) on Disposal (C) PSEG Net Income (B) Other activities include non-segment amounts of PSEG (as parent company) and intercompany eliminations. Specific amounts include interest on certain financing transactions, Merger expenses
and certain other administrative and general expenses at PSEG (as parent company). (C) The Gain on Disposal of Skawina and Elcho is included in 2006 and their Discontinued Operations are included in 2006 and 2005. The Loss on Disposal and Discontinued Operations of
Waterford, an electric generation facility in Waterford, Ohio that was sold in September 2005, are included in 2005. See Note 3. Discontinued Operations, Dispositions and Acquisitions of the
Notes. (D) Global’s Income from Continuing Operations for 2006 includes the $178 million after-tax loss on the sale of RGE in June 2006. 63
Earnings (Losses)
Quarters Ended
September 30,
Nine Months Ended
September 30,
2006
2005
2006
2005
(Millions)
$
88
$
115
$
200
$
282
205
132
394
303
92
32
(22
)
91
10
17
49
39
(1
)
(1
)
(3
)
(3
)
101
48
24
127
(20
)
(26
)
(59
)
(72
)
374
269
559
640
—
(16
)
227
(184
)
$
374
$
253
$
786
$
456
Contribution to PSEG Earnings
Per Share (Diluted) (E)
Quarters Ended
September 30,
Nine Months Ended
September 30,
2006
2005
2006
2005
$
0.35
$
0.47
$
0.79
$
1.16
0.81
0.54
1.56
1.25
0.36
0.13
(0.08
)
0.37
0.04
0.07
0.19
0.16
—
—
(0.01
)
(0.01
)
0.40
0.20
0.10
0.52
(0.08
)
(0.11
)
(0.23
)
(0.30
)
1.48
1.10
2.22
2.63
—
(0.07
)
0.90
(0.76
)
$
1.48
$
1.03
$
3.12
$
1.87
(A)
Other activities include non-segment amounts of Energy Holdings and its subsidiaries and intercompany eliminations. Specific amounts include interest on certain financing transactions and
certain other administrative and general expenses at Energy Holdings.
(E) Earnings Per Share of any segment does not represent a direct legal interest in the assets and liabilities allocated to any one segment but rather represents a direct interest in PSEG’s assets and
liabilities as a whole. The $105 million or $0.38 per share increase in Income from Continuing Operations for the quarter was due to increases of $73 million, $53 million and $6 million at Power, Energy Holdings and PSEG
(as parent company), respectively, partially offset by a decrease of $27 million at PSE&G. The increase at Power was due principally to higher realized prices from re-contracting its generation portfolio
combined with improved nuclear performance. Power’s increase was partially offset by lower realized income related to its Nuclear Decommissioning Trust (NDT) Funds, increased costs due to the
commencement of commercial operations at Linden in May 2006 and a reserve accrual of approximately $15 million related to negotiations regarding the continued operation of its Hudson unit. The
increase at Energy Holdings was primarily due to its strong operations in Texas, reflecting unrealized gains on forward gas contracts and higher margins due to increased output, partially offset by higher
Operations and Maintenance expense. PSEG’s increase was attributable to decreased Merger costs and lower Interest Expense. The decrease at PSE&G was mainly due to the full amortization of the excess
depreciation reserve as of December 31, 2005. Also decreasing PSE&G’s earnings was reduced demand due to higher pricing and weather. The $81 million or $0.41 per share decrease in Income from Continuing Operations for the nine months ended September 30, 2006, as compared to the same period in 2005, was due to decreases of $103
million and $82 million at Energy Holdings and PSE&G, respectively, partially offset by an increase of $91 million at Power and an improvement of $13 million at PSEG (as parent company). The decrease at
Energy Holdings was primarily due to the $178 million after-tax loss on the sale of RGE in June 2006 partially offset by improved operations in Texas discussed above. The changes for PSEG and PSE&G
were primarily attributable to the same reasons discussed above for the quarter. The increase at Power was due to higher sales volumes in the various power pools, supported by improved nuclear operations
and the commencement of commercial operations at Linden in May 2006 and at the Bethlehem Energy Center (BEC) in July 2005. Power’s increase was partially offset by lower realized income related to
its Nuclear Decommissioning Trust (NDT) Funds, increased costs related to Linden and BEC and reduced margins on BGSS as market prices for natural gas declined from the historically high price levels
experienced in the second half of 2005 while the cost of gas in inventory was relatively stable. PSEG Operating Revenues Energy Costs Operation and Maintenance Write-down of Project Investments Depreciation and Amortization Income from Equity Method Investments Other Income and Deductions Interest Expense Income Tax Expense Income (Loss) from Discontinued Operations, including Gain/(Loss) on Disposal, net of tax PSEG’s results of operations are primarily comprised of the results of operations of its operating subsidiaries, PSE&G, Power and Energy Holdings, excluding changes related to intercompany
transactions, which are eliminated in consolidation and certain financing costs at the parent company. For additional information on intercompany transactions, see Note 13. Related-Party Transactions of
the Notes. For a discussion of the causes for the variances at PSEG in the table above, see the discussions for PSE&G, Power and Energy Holdings that follow. 64
For the
Quarters Ended
September 30,
Increase
(Decrease)
%
For the
Nine Months
Ended
September 30,
%
Increase
(Decrease)
2006
2005
2006
2005
(Millions)
(Millions)
$
3,392
$
3,324
$
68
2
$
9,516
$
8,940
$
576
6
$
1,809
$
1,979
$
(170
)
(9
)
$
5,400
$
5,144
$
256
5
$
541
$
537
$
4
1
$
1,705
$
1,661
$
44
3
$
—
$
—
$
—
—
$
263
$
—
$
263
N/A
$
234
$
204
$
30
15
$
645
$
562
$
83
15
$
30
$
30
$
—
—
$
93
$
90
$
3
3
$
7
$
61
$
(54
)
(89
)
$
62
$
103
$
(41
)
(40
)
$
(209
)
$
(208
)
$
1
—
$
(617
)
$
(606
)
$
11
2
$
(229
)
$
(183
)
$
46
25
$
(379
)
$
(412
)
$
(33
)
(8
)
$
—
$
(16
)
$
16
N/A
$
227
$
(184
)
$
411
N/A
PSE&G Operating Revenues Energy Costs Operation and Maintenance Depreciation and Amortization Other Income and Deductions Interest Expense Income Tax Expense Operating Revenues PSE&G has three sources of revenue: commodity revenues from the sales of energy to customers and in the PJM Interconnection, L.L.C. (PJM) spot market; delivery revenues from the transmission and
distribution of energy through its system; and other operating revenues from the provision of various services. The $83 million increase for the quarter ended September 30, 2006, as compared to the same
period in 2005, was due to an increase of $115 million in commodity revenues, partially offset by a $32 million decrease in delivery revenues. The $342 million increase for the nine months ended September
30, 2006, as compared to the same period in 2005, was due to increases of $384 million in commodity revenues, partially offset by a $42 million decrease in delivery revenues. Commodity PSE&G makes no margin on commodity sales as the costs are passed through to customers. The difference between gas costs and the amount provided by customers in revenues is deferred and collected
from or returned to customers in future periods. Total commodity volumes and revenues are subject to market forces. Gas commodity prices fluctuate monthly for C&I customers and annually through the
BGSS tariff for residential customers. In addition, for residential gas customers, PSE&G has the ability to adjust rates upward two additional times and downward at any time, if warranted, between annual
BGSS proceedings. Electric commodity prices are set at the annual BGS auctions. The $115 million increase in commodity revenues for the quarter ended September 30, 2006, as compared to the same period in 2005, was due to increases of $118 million in electric commodity
revenues, partially offset by a $3 million decrease in gas commodity revenues. The increase in electric commodity revenues was primarily due to $149 million in higher BGS revenues (higher auction prices
of $198 million offset by reduced sales of $49 million) offset by $31 million in lower Non-Utility Generation (NUG) revenues (lower PJM prices of $38 million offset by $7 million for higher volumes due to
operations). The decrease in gas commodity revenues was primarily due to a $26 million reduction caused by lower volumes due to weather offset by an increase of $23 million due to higher BGSS prices. The $384 million increase in commodity revenues for the nine months ended September 30, 2006, as compared to the same period in 2005, was due to increases in electric and gas commodity revenues
of $250 million and $134 million, respectively. The increase in electric commodity revenues was primarily due to $262 million in higher BGS revenues (higher auction prices of $299 million offset by reduced
sales of $37 million) offset by $12 million in lower NUG revenues (lower PJM prices of $64 million offset by $52 million for higher volumes due to operations). The increase in gas commodity revenues was
primarily due to $371 million in higher BGSS prices offset by decreases of $179 million in lower volumes due to weather and $58 million due to the expiration of the Third Party Shopping Incentive in July
2005. There was a corresponding $58 million increase in delivery revenues. 65
For the
Quarters Ended
September 30,
Increase
(Decrease)
%
For the
Nine Months
Ended
September 30,
%
Increase
(Decrease)
2006
2005
2006
2005
(Millions)
(Millions)
$
2,017
$
1,934
$
83
4
$
5,901
$
5,559
$
342
6
$
1,296
$
1,195
$
101
8
$
3,872
$
3,472
$
400
12
$
278
$
276
$
2
1
$
855
$
839
$
16
2
$
174
$
155
$
19
12
$
476
$
418
$
58
14
$
6
$
2
$
4
N/A
$
16
$
5
$
11
N/A
$
(86
)
$
(86
)
$
—
—
$
(254
)
$
(256
)
$
(2
)
(1
)
$
(69
)
$
(74
)
$
(5
)
(7
)
$
(160
)
$
(191
)
$
(31
)
(16
)
Delivery The $32 million decrease in delivery revenues for the quarter ended September 30, 2006, as compared to the same period in 2005, was due to a $35 million decrease in electric revenues offset by a $3
million increase in gas revenues. The $35 million decrease in electric revenues was due to $37 million in decreased volumes due to weather and $1 million in lower securitization tariff rates, partially offset
by $3 million in higher demand revenues. The $3 million increase in gas delivery revenues resulted from $6 million in higher volumes primarily due to weather offset by $3 million in reduced prices. The $42 million decrease in delivery revenues for the nine months ended September 30, 2006, as compared to the same period in 2005, was due to a $44 million decrease in electric revenues and a
$2 million increase in gas revenues. The $44 million decrease in electric revenues was due to $37 million in lower volumes due to weather, $4 million due to lower demand revenues and $3 million due to
lower securitization tariff rates. The $2 million increase in gas delivery revenues was due primarily to $64 million in increased prices, primarily due to the expiration of the Third Party Shopping Incentive in
July 2005, described above in commodity revenues. This was offset by $56 million in lower volumes due to weather and $6 million due to impacts of price elasticity. Operating Expenses Energy Costs The $101 million increase for the quarter ended September 30, 2006, as compared to the same period in 2005, was comprised of an increase of $102 million in electric costs and a decrease of $1 million in
gas costs. The increase in electric costs was due to $147 million in higher BGS prices and $6 million in higher NUG volumes, offset by $46 million in lower BGS volumes and $5 million in lower NUG prices.
The decrease in gas costs was caused by a $31 million decrease in sales volumes due primarily to weather offset by a $30 million or 2% increase in gas prices. The $400 million increase for the nine months ended September 30, 2006, as compared to the same period in 2005, was comprised of increases of $207 million in electric costs and $193 million in gas
costs. The increase in electric costs was due to $208 million in higher BGS prices and $70 million in higher NUG volumes, offset by $34 million in lower BGS volumes and $37 million in lower NUG prices.
The increase in gas costs was caused by a $382 million or 23% increase in gas prices offset by a $181 million decrease in sales volumes due primarily to weather and an $8 million decrease due to the
expiration of the Gas Cost Underrecovery Adjustment (GCUA) clause in January 2005. Operation and Maintenance The $2 million increase for the quarter ended September 30, 2006, as compared to the same period in 2005, was due primarily to $1 million in increased injuries and damage claims and $1 million in
increased bad debt expense. The $16 million increase for the nine months ended September 30, 2006, as compared to the same period in 2005, was due primarily to $11 million in increased labor and fringe benefits due to increased
wages and OPEB costs and $7 million in increased bad debt expense. This was offset by a decrease of $2 million in miscellaneous expenses. Depreciation and Amortization The $19 million increase for the quarter ended September 30, 2006, as compared to the same period in 2005, was comprised of increases of $21 million from the expiration of an excess depreciation
credit and $2 million due to additional plant in service offset by a $4 million reduction in amortization of regulatory assets. The $58 million increase for the nine months ended September 30, 2006, as compared to the same period in 2005, was comprised of increases of $54 million from the expiration of an excess depreciation
credit, $7 million due to amortization of regulatory assets and $2 million due to additional plant in service. These increases were offset by decreases of $3 million due to software amortization and $2 million
due to the amortization of the Remediation Adjustment Clause (RAC). 66
Other Income and Deductions Other Income and Deductions increased $4 million for the quarter ended September 30, 2006, as compared to the same period in 2005, primarily due to a $3 million income tax gross-up on
contributions in aid of construction (CIAC) in 2006. CIAC is taxable and PSE&G recognizes the gross-up as income when collected. Other Income and Deductions increased $11 million for the nine months ended September 30, 2006, as compared to the same period in 2005, due to increases of $7 million due to an income tax gross-
up on CIAC in 2006 and $4 million due to increased income on investments. Income Taxes Income Taxes decreased $5 million for the quarter and $31 million for the nine months ended September 30, 2006, as compared to the same periods in 2005, primarily due to lower pre-tax income. Power Operating Revenues Energy Costs Operation and Maintenance Depreciation and Amortization Other Income and Deductions Interest Expense Income Tax Expense Loss from Discontinued Operations, including Loss on Disposal, net of tax benefit Operating Revenues The $45 million increase for the quarter ended September 30, 2006, as compared to the same period in 2005, was due to increases of $56 million in generation revenues and $19 million in trading
revenues, partially offset by a decrease of $30 million in gas supply revenues. The $357 million increase for the nine months ended September 30, 2006, as compared to the same period in 2005, was due to increases of $278 million in generation revenues, $47 million in gas supply
revenues and $32 million in trading revenues. Generation The increase of $56 million for the quarter ended September 30, 2006, as compared to the same period in 2005, was primarily due to an increase of $68 million due to higher sales volumes in the various
power pools, supported by improved nuclear operations and the commencement of the commercial operations of Linden in May 2006 and BEC in July 2005 and an increase of $56 million due to higher
prices under the BGS contracts. The increases were partially offset by a reduction in load being served under the BGS contracts, $32 million of unrealized losses on asset-backed electric forward contracts
and a decrease of $30 million due to the maturity of certain wholesale contracts in early 2006. The increase of $278 million for the nine months ended September 30, 2006, as compared to the same period in 2005, was primarily due to $307 million of higher sales volumes in the various power
pools, supported by improved nuclear operations and the commencement of the commercial operations of Linden and BEC and $59 million of higher prices under the BGS contracts. The increases were
partially offset by a reduction in load being served under the BGS contracts, $63 million of unrealized losses on asset-backed electric forward contracts and a decrease of $37 million due to the maturity of
certain wholesale contracts in early 2006 and 2005. 67
For the
Quarters Ended
September 30,
Increase
(Decrease)
%
For the
Nine Months
Ended
September 30,
%
Increase
(Decrease)
2006
2005
2006
2005
(Millions)
(Millions)
$
1,489
$
1,444
$
45
3
$
4,591
$
4,234
$
357
8
$
830
$
983
$
(153
)
(16
)
$
2,992
$
2,941
$
51
2
$
222
$
223
$
(1
)
—
$
721
$
685
$
36
5
$
41
$
34
$
7
21
$
116
$
96
$
20
21
$
11
$
61
$
(50
)
(82
)
$
53
$
102
$
(49
)
(48
)
$
(47
)
$
(32
)
$
15
47
$
(131
)
$
(86
)
$
45
52
$
(155
)
$
(101
)
$
54
53
$
(290
)
$
(225
)
$
65
29
$
—
$
(7
)
$
7
N/A
$
—
$
(197
)
$
197
N/A
Gas Supply Gas supply revenues decreased $30 million for the quarter ended September 30, 2006, as compared to the same period in 2005, principally due to a decrease of $32 million from lower gas prices and
reduced demand under the BGSS contract, resulting from customer conservation and warmer winter weather in 2006 and a decrease of $16 million in prices charged to other gas distributors for gas and
pipeline capacity. These decreases were partially offset by $22 million of gains on derivative forward contracts. The $47 million increase in gas supply revenues for the nine months ended September 30, 2006, as compared to the same period in 2005, was primarily due to increases of $304 million in gas prices
under the BGSS contract and $13 million in sales prices charged to other gas distributors for gas and pipeline capacity. Increased prices were partially offset by lower demand of $207 million under the
BGSS contract in 2006 and a reduction of $68 million in sales volume to other gas distributors. Trading The $19 million increase in trading revenues for the quarter ended September 30, 2006, as compared to the same period in 2005, was primarily due to higher realized gains related to electric contracts. The $32 million increase in trading revenues for the nine months ended September 30, 2006, as compared to the same period in 2005, was principally due to higher realized and unrealized gains related
to electric contracts and emissions credits. Operating Expenses Energy Costs Energy Costs represent the cost of generation, which includes fuel purchases for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS
contract with PSE&G. Energy Costs decreased approximately $153 million for the quarter ended September 30, 2006, as compared to the same period in 2005, primarily due to lower generation costs, reflecting decreases of
$90 million resulting from lower pool prices and a reduction in the volume of purchases from the various power pools due to lower load obligations and $20 million due to favorable pricing of fuel-related
asset-backed transactions in 2006. In addition, fossil fuel expenses decreased $19 million due to lower load obligations and gas purchased to satisfy Power’s BGSS obligations decreased $39 million due to
lower prices. These decreases were partially offset by an increase of $16 million in various congestion and transmission costs. The $51 million increase for the nine months ended September 30, 2006, as compared to the same period in 2005, was primarily due to increases of $91 million from higher prices on a reduced volume
of gas purchased to satisfy Power’s BGSS obligations and $85 million from a higher volume of fossil fuel purchases used to support generation by Linden and BEC. These increases were partially offset by a
decrease of $127 million, representing lower pool prices and a reduction in the volume of purchases from the various power pools. Operation and Maintenance Operation and Maintenance expense decreased $1 million and increased $36 million for the quarter and nine months ended September 30, 2006, respectively, as compared to the same periods in 2005.
The increase of $36 million was principally due to higher maintenance costs of $50 million related to certain of the fossil plants and a scheduled outage at a nuclear unit partially offset by the absence of a
$14 million restructuring charge incurred in 2005 related to Nuclear’s workforce realignment plan. 68
Depreciation and Amortization The $7 million and $20 million increases for the quarter and nine months ended September 30, 2006, respectively, as compared to the same periods in 2005, was primarily due to Linden and BEC being
placed into service. Other Income and Deductions Other Income and Deductions decreased $50 million and $49 million for the quarter and nine months ended September 30, 2006, respectively, as compared to the same periods in 2005, primarily due to
decreased net realized income related to the NDT Funds of $37 million and $39 million for the quarter and year-to-date periods, respectively. Also contributing to the decrease for the quarter and nine
months was an environmental reserve of approximately $15 million recorded in the third quarter of 2006 for potential penalties and other costs related to ongoing negotiations for an alternate pollution
reduction plan for Power’s Hudson unit. These decreases were partially offset by higher interest income of $2 million and $6 million for the quarter and nine months ended September 30, 2006, respectively,
as compared to the same period in 2005. Interest Expense Interest Expense increased $15 million and $45 million for the quarter and nine months ended September 30, 2006, respectively, as compared to the same periods in 2005, due primarily to lower
capitalized interest costs in 2006 related to commencement of operations of the BEC and Linden facilities. Income Taxes Income Taxes increased $54 million for the quarter and $65 million for the nine months ended September 30, 2006, as compared to the same periods in 2005, primarily due to higher pre-tax income. Loss from Discontinued Operations, including Loss on Disposal, net of tax On May 27, 2005, Power reached an agreement to sell its Waterford generation facility for approximately $220 million and recognized a loss on disposal of approximately $177 million for the initial
write-down of its carrying amount of Waterford to its fair value less cost to sell. On September 28, 2005, Power completed the sale of Waterford and recognized an additional loss of $1 million. The proceeds,
together with anticipated reduction in tax liability, were approximately $320 million, which was used to retire debt at Power. The loss from the discontinued operating results of Waterford was $6 million and
$19 million for the quarter and nine months ended September 30, 2005, respectively. See Note 3. Discontinued Operations, Dispositions and Acquisitions of the Notes for additional information. 69
Energy Holdings Operating Revenues Energy Costs Operation and Maintenance Write-down of Project Investments Depreciation and Amortization Income from Equity Method Investments Other Income and Deductions Interest Expense Income Tax (Expense) Benefit Income (Loss) from Discontinued Operations, including Gain/ (Loss) on Disposal, net of tax Operating Revenues The $67 million increase for the quarter ended September 30, 2006, as compared to the same period in 2005, was primarily due to higher revenues at Global of $78 million, which was primarily related
to a $60 million increase at TIE. The increase at TIE included an increase of $63 million related to unrealized gains on forward contracts and $13 million due to increased output available for sale, partially
offset by lower prices of $16 million driven by lower gas costs. Also included in the increase at Global were a $9 million increase due to the consolidation of Prisma which began in May 2006 when Global
increased its ownership interest from 50% to 85% and an $8 million increase at Sociedad Austral de Electricidad S.A. (SAESA) in Chile due to increased tariff prices and volume, offset by a decrease of
revenues at Resources of $12 million primarily due to $8 million of lower lease income. The $163 million increase for the nine months ended September 30, 2006, as compared to the same period in 2005, was primarily due to higher revenues at Global of $171 million, which was primarily
related to a $163 million increase at TIE. The increase at TIE included increases of $115 million related to unrealized gains on forward contracts, $27 million due to increased output available for sale and
$21 million due to price increases. Also contributing to the increase at Global was a $48 million increase at SAESA due to increased tariffs and volume and a $17 million increase due to the consolidation of
Prisma, partially offset by decreased revenues due to the absence of $37 million of income received in 2005 from withdrawal from Eagle Point Cogeneration Partnership (EPCP) and a $23 million decrease
related to the deconsolidation of Dhofar Power. The deconsolidation of Dhofar Power resulted from Global’s sale of a 35% interest in Dhofar Power through a public offering on the Omani Stock
Exchange in April 2005, reducing its ownership interest to 46% and thus accounting for the investment under the equity method of accounting following the sale. The increase at Global was partially offset
by an $8 million decrease in revenues at Resources primarily due to the reduction in leveraged lease income of $25 million, offset by the $21 million write-off of its leveraged lease investment with United
Airlines in 2005. Operating Expenses Energy Costs The
$11 million increase for the quarter ended September 30, 2006, as compared to
the same period in 2005, was primarily due to increases of $4 million at SAESA
due to increased volume and increases in energy costs due to higher spot prices,
$3 million due to the consolidation of Prisma and $3 million at TIE resulting
from an increase of $13 million in gas purchases offset primarily by lower fuel
costs of $10 million. The $99 million increase for the nine months ended September 30, 2006, as compared to the same period in 2005, was primarily due to a $64 million increase at TIE resulting mainly from an increase in 70
For the
Quarters Ended
September 30,
Increase
(Decrease)
%
For the
Nine Months
Ended
September 30,
%
Increase
(Decrease)
2006
2005
2006
2005
(Millions)
(Millions)
$
401
$
334
$
67
20
$
1,080
$
917
$
163
18
$
195
$
184
$
11
6
$
583
$
484
$
99
20
$
49
$
41
$
8
20
$
150
$
151
$
(1
)
(1
)
$
—
$
—
$
—
—
$
263
$
—
$
263
N/A
$
14
$
10
$
4
40
$
38
$
35
$
3
9
$
30
$
30
$
—
—
$
93
$
90
$
3
3
$
(2
)
$
2
$
(4
)
N/A
$
6
$
1
$
5
N/A
$
(50
)
$
(56
)
$
(6
)
(11
)
$
(151
)
$
(168
)
$
(17
)
(10
)
$
(20
)
$
(27
)
$
(7
)
(26
)
$
31
$
(42
)
$
(73
)
N/A
$
—
$
(9
)
$
(9
)
(100
)
$
227
$
13
$
214
N/A
unrealized losses on gas purchases of $51 million coupled with a $13 million increase in fuel purchases. Also contributing to the increase was a $33 million increase at SAESA due to increased volume and
increases in energy costs due to higher spot prices and a $6 million increase due to the consolidation of Prisma. These increases were partially offset by a $5 million decrease related to the deconsolidation of
Dhofar Power. Operation and Maintenance The
$8 million increase for the quarter ended September 30, 2006, as compared to
the same period in 2005, was primarily due to a $7 million increase at SAESA
resulting from repairs of a gas turbine for which it has filed a claim for insurance
recovery. Write-down of Project Investments The $263 million increase in the write-down of project investments relates to Global’s sale of its 32% indirect ownership interest in RGE to its partner. See Note 3. Discontinued Operations,
Dispositions and Acquisitions of the Notes. Income from Equity Method Investments The $3 million increase for the nine months ended September 30, 2006, as compared to the same period in 2005, was primarily due to the consolidation of Prisma generating an increase in earnings of
$5 million and stronger results from Global’s investments in Hawaii (Kalaeloa) and California (GWF) totaling $3 million, offset by a reduction of $5 million in the equity from investments in Latin America
due to the sale of Global’s 32% indirect interest in RGE. Other Income and Deductions The
$4 million decrease for the quarter ended September 30, 2006 compared to the
same period in the prior year, was primarily due to a loss recorded on the extinguishment
of debt, which was partially offset by higher interest income and lower losses
in foreign currency transactions. The
$5 million increase for the nine months ended September 30, 2006, as compared
to the same period in 2005, was primarily due to an increase in interest income
and lower losses in foreign currency transactions which was partially offset
by the loss recorded on the extinguishment of debt. Interest Expense The $6 million and $17 million decreases for the quarter and nine months ended September 30, 2006, respectively, as compared to the same periods in 2005, was primarily due to a decrease in Energy
Holdings’ debt outstanding. Income Taxes The $7 million decrease for the quarter ended September 30, 2006, as compared to the same period in 2005, was primarily attributable to a $9 million U.S. tax associated with repatriation of funds
recorded in 2005. The $73 million decrease for the nine months ended September 30, 2006, as compared to the same period in 2005, was primarily attributable to a tax benefit resulting from Global’s sale of
its 32% indirect ownership interest in RGE. Income from Discontinued Operations, including Gain on Disposal, net of tax In May 2006, Global completed the sale of its interest in two coal-fired plants in Poland, Elcho and Skawina. The sale resulted in an after-tax gain of $228 million. Income (Loss) from Discontinued
Operations related to Elcho and Skawina for the quarters ended September 30, 2006 and 2005 was $0 million and $9 million, respectively. Income (Loss) from Discontinued Operations related to Elcho and
Skawina for the nine months ended September 30, 2006 and 2005 was $(1) million and $13 million, 71
respectively. See Note 3. Discontinued Operations, Dispositions and Acquisitions of the Notes for additional information. LIQUIDITY AND CAPITAL RESOURCES The following discussion of liquidity and capital resources is on a consolidated basis for PSEG, noting the uses and contributions of PSEG’s three direct operating subsidiaries, PSE&G, Power and Energy
Holdings. Operating Cash Flows PSEG For the nine months ended September 30, 2006, PSEG’s operating cash flow increased approximately $541 million from $903 million to $1,444 million, as compared to the same period in 2005, primarily
due to net increases from its subsidiaries as discussed below. PSE&G PSE&G’s operating cash flow decreased approximately $41 million from $464 million to $423 million for the nine months ended September 30, 2006, as compared to the same period in 2005, primarily
due to a decrease in customer deposits partially offset by higher over recovery of gas costs resulting from lower commodity prices in 2006. Power Power’s operating cash flow increased approximately $644 million from $276 million to $920 million for the nine months ended September 30, 2006, as compared to the same period in 2005, due to
decreases in accounts receivable and fuel inventory, largely resulting from decreased commodity prices. Energy Holdings Energy
Holdings’ operating cash flow decreased approximately $80 million from
$229 million to $149 million for the nine months ended September 30, 2006, as
compared to the same period in 2005. The $80 million decrease is primarily due
to the timing of net tax payments associated with the net gain on the sale of
Elcho, Skawina and RGE during 2006 as well as higher distributions from partnerships
during 2005 due to the withdrawal from EPCP. The proceeds from the Elcho, Skawina
and RGE sales are included in Investing Activities on Energy Holdings’
Condensed Consolidated Statements of Cash Flows. Common Stock Dividends PSEG Dividend payments on common stock for the quarters ended September 30, 2006 and 2005 were $0.57 and $0.56 per share, respectively, and totaled approximately $144 million and $134 million,
respectively. Dividend payments on common stock for the nine months ended September 30, 2006 and 2005 were $1.71 and $1.68 per share, respectively, and totaled approximately $430 million and
$401 million, respectively. Future dividends declared will be dependent upon PSEG’s future earnings, cash flows, financial requirements, alternative investment opportunities and other factors. On
October 17, 2006, PSEG’s Board of Directors approved a common stock dividend of $0.57 per share for the fourth quarter of 2006, reflecting an indicated annual dividend rate of $2.28 per share. 72
Short-Term Liquidity PSEG, PSE&G, Power and Energy Holdings As of September 30, 2006, PSEG and its subsidiaries had a total of approximately $3.7 billion of committed credit facilities with approximately $3.1 billion of available liquidity under these facilities. In
addition, PSEG and PSE&G have access to certain uncommitted credit facilities. Each of the facilities is restricted to availability and use to the specific companies as listed below. Company PSEG: 4-year Credit Facility 5-year Credit Facility Bilateral Term Loan Uncommitted Bilateral PSE&G: 5-year Credit Facility Uncommitted Bilateral
Agreement PSEG and Power: (A) 3-year Credit Facility Bilateral Credit Facility Bilateral Credit Facility Bilateral Credit Facility Bilateral Credit Facility Bilateral Credit Facility Bilateral Credit Facility Bilateral Credit Facility Power: Bilateral Credit Facility Energy Holdings: 5-year Credit Facility (B) (B) Energy Holdings/Global/Resources joint and several co-borrower facility. (C) These amounts relate to letters of credit outstanding. (D) These facilities are expected to be replaced with a new syndicated facility in the fourth quarter of 2006. 73
Expiration
Date
Total
Facility
Primary
Purpose
Usage as of
September 30,
2006
Available
Liquidity as of
September 30,
2006
(Millions)
April 2008
$
450
CP Support/
Funding/Letters
of Credit
$
125
$
325
May 2010
$
650
CP Support/
Funding/Letters
of Credit
$
3
(C)
$
647
May 2007
$
100
Funding
$
100
$
—
Agreement
N/A
N/A
Funding
$
—
N/A
June 2009
$
600
CP Support/
Funding/Letters
of Credit
$
327
$
273
N/A
N/A
Funding
$
—
N/A
April 2007
$
600
CP Support/
Funding/Letters
of Credit
$
20
(C)
$
580
Oct 2006(D)
$
100
Funding/Letters
of Credit
$
—
$
100
Dec 2006(D)
$
100
Funding/Letters
of Credit
$
—
$
100
Dec 2006(D)
$
150
Funding/Letters
of Credit
$
10
(C)
$
140
Dec 2006(D)
$
150
Funding/Letters
of Credit
$
—
$
150
June 2007
$
200
Funding/Letters
of Credit
$
8
(C)
$
192
Dec 2006(D)
$
50
Funding/Letters
of Credit
$
1
(C)
$
49
Dec 2006(D)
$
275
Letters of Credit
$
2
(C)
$
273
March 2010
$
100
Funding/Letters
of Credit
$
8
(C)
$
92
June 2010
$
150
Funding/Letters
of Credit
$
7
(C)
$
143
(A)
PSEG/Power joint and several co-borrower facilities.
PSEG and PSE&G PSEG and PSE&G believe sufficient liquidity exists to fund their short-term cash needs. Power As of September 30, 2006, Power had borrowed $68 million from PSEG in the form of an intercompany loan. During the third quarter of 2006, Power’s required margin postings decreased for sales contracts entered into in the normal course of business as commodity prices declined. The required margin
postings will fluctuate based on volatility in commodity prices. Should commodity prices rise, additional margin calls may be necessary relative to existing power sales contracts. As Power’s contract
obligations are fulfilled, liquidity requirements are reduced. Power believes that it has sufficient liquidity to fund its short-term cash needs. In addition, ER&T maintains agreements that require Power, as its guarantor under performance guarantees, to satisfy certain creditworthiness standards. In the event of a deterioration of Power’s credit
rating to below investment grade, which represents at least a two level downgrade from its current ratings, many of these agreements allow the counterparty to demand that ER&T provide performance
assurance, generally in the form of a letter of credit or cash. Providing this support would increase Power’s costs of doing business and could restrict the ability of ER&T to manage and optimize Power’s asset
portfolio. Power believes it has sufficient liquidity to meet any required posting of collateral resulting from a credit rating downgrade. See Note 5. Commitments and Contingent Liabilities of the Notes for
further information. Energy Holdings Energy Holdings and its subsidiaries had $102 million in cash, including $19 million invested offshore as of September 30, 2006. In addition, as of September 30, 2006, Energy Holdings had an
outstanding demand loan receivable from PSEG of $374 million. See External Financings—Energy Holdings below for Energy Holdings’ additional use of its excess cash. External Financings PSEG On September 1, 2006, PSEG began using treasury stock to settle the exercise of stock options. Prior to September 1, 2006, PSEG had purchased shares on the open market to meet the exercise of
stock options. As of September 30, 2006, PSEG issued approximately 121,067 shares of its common treasury stock in connection with settling stock options for approximately $5 million. During the nine months ended September 30, 2006, PSEG issued approximately 790,825 shares of its common stock under its Dividend Reinvestment Program and Employee Stock Purchase Program
for approximately $51 million. In February 2006, PSEG redeemed $154 million of its Subordinated Debentures underlying $150 million of Enterprise Capital Trust II, Floating Rate Capital Securities and its common equity
investment in the trust. PSE&G On June 23, 2006, PSE&G repaid at maturity $174 million of its Floating Rate Series A First and Refunding Mortgage Bonds. On March 1, 2006, PSE&G repaid at maturity $148 million of its 6.75% Series UU First and Refunding Mortgage Bonds. In September 2006, June 2006 and March 2006, PSE&G Transition Funding LLC (Transition Funding) repaid approximately $41 million, $35 million and $36 million, respectively, of its transition bonds. 74
In June 2006, PSE&G Transition Funding II LLC (Transition Funding II) repaid approximately $3 million of its transition bonds. Power In April 2006, Power repaid at maturity $500 million of its 6.875% Senior Notes. Energy Holdings In January 2006, Energy Holdings redeemed all $309 million of its 7.75% Senior Notes due in 2007. On February 17, 2006, the maturity of the Odessa‑Ector Power Partners, L.P. (Odessa) debt was extended to December 31, 2009. Interest on the debt is based on a spread (currently 2.25%) above
LIBOR. On September 29, 2006, an interest rate swap took effect which converts the floating LIBOR interest rate on approximately 80% of Odessa’s debt to a fixed rate of 5.4275% through December 31,
2009. On October 23, 2006, Energy Holdings redeemed $300 million of its $507 million outstanding 8.625% Senior Notes due in 2008. Additionally, on September 20, 2006, Energy Holdings made a cash
distribution to PSEG of $425 million in the form of a return of capital. During
the first nine months of 2006, Energy Holdings repaid approximately $37 million
of non-recourse debt, of which $30 million was paid by Global, primarily related
to SAESA and TIE, $5 million by Resources and $2 million by EGDC. Contractual Obligations PSEG, PSE&G, Power and Energy Holdings As of September 30, 2006, contractual cash obligations and other commercial commitments have not changed significantly from those reported in the Capital Requirements section of Management’s
Discussion and Analysis included in the 2005 Annual Report on Form 10K, except for the debt redemptions discussed above in External Financings. Debt Covenants PSEG, PSE&G, Power and Energy Holdings PSEG’s, PSE&G’s, Power’s and Energy Holdings’ respective credit agreements generally contain customary provisions under which the lenders can refuse to advance loans in the event of a material
adverse change in the borrower’s business or financial condition. As explained in more detail below, these credit agreements may 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 the respective future financial position, level of earnings and cash flows of PSEG, PSE&G, Power and Energy Holdings, as to which no
assurances can be given. The ratios presented below are for the benefit of the investors of the related securities to which the covenants apply. They are not intended as a financial performance or liquidity
measure. PSEG Financial covenants contained in PSEG’s credit facilities include a ratio of debt (excluding non-recourse project financings, securitization debt and debt underlying preferred securities and including
commercial paper and loans, certain letters of credit and similar instruments) to total capitalization (including preferred securities outstanding) covenant. This covenant requires that at the end of any
quarterly financial period, such ratio not be more than 70.0%. As of September 30, 2006, PSEG’s ratio of debt to capitalization (as defined above) was 52.8%. 75
PSE&G Financial covenants contained in PSE&G’s credit facilities include a ratio of long-term debt (excluding securitization debt, long-term debt maturing within one year and short-term debt) to total
capitalization covenant. This covenant requires that at the end of any quarterly financial period, such ratio will not be more than 65.0%. As of September 30, 2006, PSE&G’s ratio of long-term debt to total
capitalization (as defined above) was 45.3%. In addition, under its First and Refunding Mortgage (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 to 1, and/or against retired Mortgage Bonds. As of September 30, 2006, PSE&G’s Mortgage coverage ratio was 4.5 to 1 and the
Mortgage would permit up to approximately $1.9 billion aggregate principal amount of new Mortgage Bonds to be issued against previous additions and improvements. PSEG and Power Financial covenants contained in the PSEG/Power joint and several credit facility include a ratio of debt to total capitalization for each specific borrower. This facility has a 70.0% debt to total
capitalization covenant for PSEG (calculated as set forth above) and a 65.0% debt to total capitalization covenant for Power. The Power ratio is the same debt to total capitalization calculation as set forth
above for PSEG except common equity is adjusted for the $986 million Basis Adjustment (see Condensed Consolidated Balance Sheets). This covenant requires that at the end of any quarterly financial
period, such ratio will not exceed 65.0%. As of September 30, 2006, Power’s ratio of debt to total capitalization (as defined above) was 39.3%. Energy Holdings Energy Holdings’ revolving credit agreement has a covenant requiring the ratio of Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) to fixed charges to be greater than or
equal to 1.75. As of September 30, 2006, Energy Holdings’ coverage of this covenant was 3.94. Additionally, Energy Holdings must maintain a ratio of net debt (recourse debt offset by funds loaned to
PSEG) to EBITDA of less than 5.25. As of September 30, 2006, Energy Holdings’ ratio under this covenant was 2.11. Energy Holdings is a co-borrower under this facility with Global and Resources, which
are joint and several obligors. The terms of the agreement include a pledge of Energy Holdings’ membership interest in Global, restrictions on the use of proceeds related to material sales of assets and the
satisfaction of certain financial covenants. Net cash proceeds from asset sales in excess of 5% of total assets of Energy Holdings during any 12-month period must be used to repay any outstanding amounts
under the credit agreement. Net cash proceeds from asset sales during any 12-month period in excess of 10% of total assets must be retained by Energy Holdings or used to repay the debt of Energy
Holdings, Global or Resources. Credit Ratings PSEG, PSE&G, Power and Energy Holdings On September 15, 2006, following the termination of the Merger Agreement, credit ratings remained unchanged as shown in the table below. Standard & Poor’s (S&P) affirmed its ‘BBB’ corporate credit
rating for PSEG, Power, and PSE&G. S&P revised its outlook from watch developing to negative. Moody’s Investors Service (Moody’s) affirmed its credit ratings for PSEG and PSE&G while revising the
outlooks from stable to negative. The ratings and outlooks for Power and Energy Holdings were unchanged by Moody’s. Fitch Ratings (Fitch) announced there would be no immediate impact on ratings
and outlooks for PSEG and its subsidiaries. The agencies noted that the ratings below are predicated on continued improvement in financial metrics, specifically operating cash flows and ongoing
deleveraging, as well as continued strong operating performance from Power’s generating units and reasonable outcomes to PSE&G’s pending electric and gas rate cases. 76
If the rating agencies lower or withdraw the credit ratings, such revisions may adversely affect the market price of PSEG’s, PSE&G’s, Power’s and Energy Holdings’ securities and serve to materially
increase those companies’ cost of capital and limit their access to capital. Outlooks assigned to ratings are as follows: stable, negative (Neg) or positive (Pos). There is no assurance that the ratings will
continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances so warrant. Each rating given by an agency should be evaluated
independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security. PSEG: Outlook Preferred Securities Commercial Paper Senior Unsecured Debt PSE&G: Outlook Mortgage Bonds Preferred Securities Commercial Paper Power: Outlook Senior Notes Energy Holdings: Outlook Senior Notes Other Comprehensive Income (OCI) PSEG, Power and Energy Holdings For the nine months ended September 30, 2006, PSEG, Power and Energy Holdings had OCI of $576 million, $383 million and $192 million, respectively, due primarily to a reduction in the net
unrealized losses on derivatives accounted for as hedges in accordance with SFAS 133 at Power and foreign currency translation adjustments at Energy Holdings. During the nine months ended September 30, 2006, Power’s Accumulated Other Comprehensive Loss (OCL) decreased from $487 million to $104 million. The primary cause was a decrease of
approximately $374 million related to energy and related contracts that qualify for hedge accounting that were entered into by Power in the normal course of business. During the nine months ended
September 30, 2006, the decrease in gas and electric prices resulted in a reduction in unrealized losses on many of those contracts, which are recorded in OCL. During the nine months ended September 30, 2006, Energy Holdings’ Accumulated Other Comprehensive (Loss) Income increased from $(110) million to $82 million. The primary cause was the
realization of losses on Brazilian currency as a result of the sale of RGE. 77
Moody’s (A)
S&P (B)
Fitch (C)
Neg
Neg
Pos
Baa3
BB+
BBB‑
P2
A3
F2
Baa2
BBB‑
BBB
Neg
Neg
Stable
A3
A‑
A
Baa3
BB+
BBB+
P2
A3
F2
Stable
Neg
Pos
Baa1
BBB
BBB
Neg
Neg
Neg
Ba3
BB‑
BB
(A)
Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.
(B)
S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.
(C)
Fitch ratings range from AAA (highest) to D (lowest) for long-term securities and F1 (highest) to D (lowest) for short-term securities.
PSEG, PSE&G, Power and Energy Holdings It is expected that the majority of funding for capital requirements of PSE&G, Power and Energy Holdings will come from their respective internally generated funds. The balance will be provided by the
issuance of debt at the respective subsidiary or project level and, for PSE&G and Power, equity contributions from PSEG. PSEG does not expect to contribute any additional equity to Energy Holdings.
Projected construction and investment expenditures for PSEG, PSE&G, Power and Energy Holdings are consistent with amounts disclosed in the Annual Reports on Form 10-K of PSEG, PSE&G, Power and
Energy Holdings for the year ended December 31, 2005, with the exception of the indefinite postponement of the $30 million Electroandes hydro-expansion project at Energy Holdings which was planned
for 2006 and 2007. For further information see Note 5. Commitments and Contingent Liabilities of the Notes. PSE&G During the nine months ended September 30, 2006, PSE&G made approximately $392 million of capital expenditures, primarily for reliability of transmission and distribution systems. The $392 million
excludes approximately $26 million spent on cost of removal. Power During the nine months ended September 30, 2006, Power made approximately $233 million of capital expenditures (excluding $83 million for nuclear fuel), primarily related to various projects at
Fossil and Nuclear. Energy Holdings During the nine months ended September 30, 2006, Energy Holdings incurred approximately $37 million of capital expenditures, of which approximately $18 million related to SAESA. OFF-BALANCE SHEET ARRANGEMENTS PSEG, Power and Energy Holdings For
a description of off-balance sheet arrangements, see Management’s Discussion
and Analysis in the 2005 Annual Report on Form 10-K. PSEG’s pro rata share
of the debt appearing on the consolidated financial statements of companies
for which Global accounts under the equity method of investment was approximately
$463 million as of September 30, 2006 as compared to $577 million as of December
31, 2005. The decrease related principally to Energy Holdings’ sale of
RGE in June 2006 and the change since May 2006 in Energy Holdings’ accounting
for Prisma from the equity method to full consolidation. There has been no material
change in the amount of Resources’ leveraged lease investments since December
31, 2005. See Note 5. Commitments and Contingent Obligations of the Notes for
an update of Power’s guarantees related to certain of its energy trading
activities and Energy Holdings’ guarantees of certain obligations of its
subsidiaries or affiliates related to certain projects. PSEG, PSE&G, Power and Energy Holdings For information related to recent accounting matters, see Note 2. Recent Accounting Standards of the Notes. 78
ITEM 3. QUALITATIVE AND QUANTITATIVE DISCLOSURES PSEG, PSE&G, Power and Energy Holdings The market risk inherent in PSEG’s, PSE&G’s, Power’s and Energy Holdings’ 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 Condensed Consolidated Financial Statements (Notes). It is the policy of each entity to use derivatives
to manage risk consistent with its respective business plans and prudent practices. PSEG, PSE&G, Power and Energy Holdings have a Risk Management Committee (RMC) comprised of executive officers
who utilize an independent risk oversight function to ensure compliance with corporate policies and prudent risk management practices. Additionally, PSEG, PSE&G, Power and Energy Holdings are exposed to counterparty credit losses in the event of non-performance or non-payment. PSEG has a credit management process, which is
used to assess, monitor and mitigate counterparty exposure for PSEG and its subsidiaries. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact
on PSEG and its subsidiaries’ financial condition, results of operations or net cash flows. Except as discussed below, there were no material changes from the disclosures in the Annual Reports on Form 10-K of PSEG, PSE&G, Power and Energy Holdings for the year ended December 31,
2005 or Quarterly Reports on Form 10-Q for the quarters ended March 31, 2006 and June 30, 2006. Commodity Contracts Power 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,
market rules and other events. To reduce price risk caused by market fluctuations, Power enters into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved
counterparties. These contracts, in conjunction with demand obligations, help reduce risk and optimize the value of owned electric generation capacity. Normal Operations and Hedging Activities Power enters into physical contracts, as well as financial contracts, including forwards, futures, swaps and options designed to reduce risk associated with volatile commodity prices. Commodity price
risk is associated with market price movements resulting from market generation demand, changes in fuel costs and various other factors. Under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended (SFAS 133), changes in the fair value of qualifying cash flow hedge transactions are recorded in
Accumulated Other Comprehensive Loss (OCL), and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet
hedge criteria under SFAS 133 and the ineffective portion of hedge contracts are recognized in earnings currently. Additionally, changes in the fair value attributable to fair value hedges are similarly
recognized in earnings. Many non-trading contracts qualify for the normal purchases and normal sales exemption under SFAS 133 and are accounted for upon settlement. Trading Power maintains a strategy of entering into trading positions to optimize the value of its portfolio of generation assets, gas supply contracts and its electric and gas supply obligations. 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. In
addition, Power has non-asset based trading activities, which have significantly decreased over the 79
ABOUT MARKET RISK
past year. These contracts also involve financial transactions including swaps, options and futures. These activities are marked to market in accordance with SFAS 133 with gains and losses recognized in
earnings. Value-at-Risk (VaR) Models Power Power uses VaR models to assess the market risk of its commodity businesses. The portfolio VaR model for Power includes its owned generation and physical contracts, as well as fixed price sales
requirements, load requirements and financial derivative instruments. VaR represents the potential gains or losses, under normal market conditions, for instruments or portfolios due to changes in market
factors, for a specified time period and confidence level. Power estimates VaR across its commodity businesses. Power manages its exposure at the portfolio level. Its portfolio consists of owned generation, load-serving contracts (both gas and electric), fuel supply contracts and energy derivatives designed to
manage the risk around generation and load. While Power manages its risk at the portfolio level, it also monitors separately the risk of its trading activities and its hedges. Non-trading mark-to-market
(MTM) VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The MTM derivatives that are not hedges are included in the trading VaR. The VaR models used by Power are variance/covariance models adjusted for the delta of positions with a 95% one-tailed confidence level and a one-day holding period for the MTM trading and non-
trading activities and a 95% one-tailed confidence level with a one-week holding period for the portfolio VaR. The models assume no new positions throughout the holding periods, whereas Power actively
manages its portfolio. As of September 30, 2006 and December 31, 2005, trading VaR was less than $1 million. For the Quarter Ended September 30, 2006 95% Confidence Level, One-Day Holding Period, One-Tailed: Period End Average for the Period High Low 99% Confidence Level, One-Day Holding Period, Two-Tailed: Period End Average for the Period High Low Other Supplemental Information Regarding Market Risk Power The following presentation of the activities of Power is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers. For additional information, see
Note 6. Risk Management of the Notes. The following table describes the drivers of Power’s energy trading and marketing activities and Operating Revenues included in its Condensed Consolidated Statement of Operations for the quarter
and nine months ended September 30, 2006. Normal operations and hedging activities represent the marketing of electricity available from Power’s owned or contracted generation sold into the wholesale
market. As the information in this table highlights, MTM activities represent a small portion of the total Operating Revenues for Power. Activities accounted for under the accrual method, including normal
purchases and sales, account for the majority of the revenue. The MTM activities reported here are those relating to changes in fair value due to external movement in prices. 80
Trading VaR
Non-Trading
MTM VaR
(Millions)
$
—
$
49
$
—
$
51
$
—
$
69
$
—
$
40
$
—
$
76
$
—
$
79
$
—
$
108
$
—
$
63
Operating Revenues MTM Activities: Unrealized MTM Gains (Losses) Changes in Fair Value of Open Positions Origination Unrealized Gain at Inception Changes in Valuation Techniques and Assumptions Realization at Settlement of Contracts Total Change in Unrealized Fair Value Realized Net Settlement of Transactions Subject to MTM Broker Fees and Other Related Expenses Net MTM Gains Accrual Activities Accrual Activities—Revenue, Including Hedge Reclassifications Total Operating Revenues Operating Revenues MTM Activities: Unrealized MTM Gains (Losses) Changes in Fair Value of Open Positions Origination Unrealized Gain at Inception Changes in Valuation Techniques and Assumptions Realization at Settlement of Contracts Total Change in Unrealized Fair Value Realized Net Settlement of Transactions Subject to MTM Broker Fees and Other Related Expenses Net MTM Gains Accrual Activities Accrual Activities—Revenue, Including Hedge Reclassifications Total Operating Revenues The following table indicates Power’s energy trading assets and liabilities, as well as Power’s hedging activity related to asset-backed transactions and derivative instruments that qualify for hedge
accounting under SFAS 133, its amendments and related guidance. This table presents amounts segregated by portfolio which are then netted for those counterparties with whom Power has the right to
offset and therefore, are not necessarily indicative of amounts presented on the Condensed Consolidated Balance Sheets since balances with many counterparties are subject to offset and are shown net on
the Condensed Consolidated Balance Sheets regardless of the portfolio in which they are included. 81
For the Quarter Ended September 30, 2006
Normal
Operations and
Hedging (A)
Trading
Total
(Millions)
$
10
$
2
$
12
—
—
—
—
—
—
(4
)
—
(4
)
6
2
8
4
1
5
—
—
—
10
3
13
1,476
—
1,476
—
—
—
$
1,486
$
3
$
1,489
For the Nine Months Ended September 30, 2006
Normal
Operations and
Hedging (A)
Trading
Total
(Millions)
$
7
$
25
$
32
—
—
—
—
—
—
(26
)
(30
)
(56
)
(19
)
(5
)
(24
)
26
31
57
—
—
—
7
26
33
4,558
—
4,558
—
—
—
$
4,565
$
26
$
4,591
(A)
Includes derivative contracts that Power enters into to hedge anticipated exposures related to its owned and contracted generation supply, all asset-backed transactions and hedging activities, but
excludes owned and contracted generation assets.
Energy Contract Net Assets/Liabilities MTM Energy Assets Current Assets Noncurrent Assets Total MTM Energy Assets MTM Energy Liabilities Current Liabilities Noncurrent Liabilities Total MTM Current Liabilities Total MTM Energy Contract Net Liabilities The following table presents the maturity of net fair value of MTM energy trading contracts. Maturity of Net Fair Value of MTM Energy Trading Contracts Trading Normal Operations and Hedging Total Net Unrealized Losses on MTM Contracts Wherever possible, fair values for these contracts were obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques were employed using assumptions
reflective of current market rates, yield curves and forward prices as applicable to interpolate certain prices. The effect of using such modeling techniques is not material to Power’s financial results. PSEG, Power and Energy Holdings The following table identifies losses on cash flow hedges that are currently in OCL, a separate component of equity. Power uses forward sale and purchase contracts, swaps and firm transmission rights
(FTRs) contracts to hedge forecasted energy sales from its generation stations and its contracted supply obligations. Power also enters into swaps, options and futures transactions to hedge the price of fuel
to meet its fuel purchase requirements for generation. PSEG, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s policy is to manage
interest rate risk through the use of fixed rate debt, floating rate debt and interest rate derivatives. The table also provides an estimate of the losses that are expected to be reclassified out of OCL and into
earnings over the next 12 months. Cash Flow Hedges Included in Accumulated Other Comprehensive Loss Commodities Interest Rates Foreign Currency Net Cash Flow Hedge Loss 82
As of September 30, 2006
Normal
Operations
and Hedging
Trading
Total
(Millions)
$
56
$
37
$
93
27
11
38
83
48
131
$
(374
)
$
(42
)
$
(416
)
(188
)
(14
)
(202
)
(562
)
(56
)
(618
)
$
(479
)
$
(8
)
$
(487
)
As of September 30, 2006
Maturities within
2006
2007
2008-2009
Total
(Millions)
$
(4
)
$
(6
)
$
2
$
(8
)
(117
)
(239
)
(123
)
(479
)
$
(121
)
$
(245
)
$
(121
)
$
(487
)
As of September 30, 2006
Accumulated
Other
Comprehensive
Loss
Portion Expected
to be Reclassified
in next 12 months
(Millions)
$
(183
)
$
(102
)
(9
)
(1
)
—
—
$
(192
)
$
(103
)
Power Credit Risk The following table provides information on Power’s credit exposure, net of collateral, as of September 30, 2006. Credit exposure is defined as any positive results of netting accounts
receivable/accounts payable and the forward value on open positions. It further delineates that exposure by the credit rating of the counterparties and provides guidance on the concentration of credit risk to
individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties. Schedule of Credit Risk Exposure on Energy Contracts Net Assets Rating Investment Grade—External Rating Non-Investment Grade—External Rating Investment Grade—No External Rating Non-Investment Grade—No External Rating Total The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more collateral than the outstanding
exposure, in which case there would not be exposure. As of September 30, 2006, Power had 129 active counterparties. ITEM 4. CONTROLS AND PROCEDURES PSEG, PSE&G, Power and Energy Holdings Disclosure Controls and Procedures PSEG, PSE&G, Power and Energy Holdings have established and maintain disclosure controls and procedures which are designed to provide reasonable assurance that information required to be
disclosed is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and that material information relating to each company, including their respective
consolidated subsidiaries, is accumulated and communicated to the respective company’s management, including the Chief Executive Officer and Chief Financial Officer of each company by others within
those entities to allow timely decisions regarding required disclosure. PSEG, PSE&G, Power and Energy Holdings have established a disclosure committee which is made up of several key management
employees and which reports directly to the Chief Financial Officer and Chief Executive Officer of each respective company. The committee monitors and evaluates the effectiveness of these disclosure
controls and procedures. The Chief Financial Officer and Chief Executive Officer of each company have evaluated the effectiveness of the disclosure controls and procedures as of September 30, 2006 and,
based on this evaluation, have concluded that the disclosure controls and procedures were effective in providing reasonable assurance during the period covered in these quarterly reports. Internal Controls PSEG, PSE&G, Power and Energy Holdings continually review their respective disclosure controls and procedures and make changes, as necessary, to ensure the quality of their financial reporting.
However, there have been no changes in internal control over financial reporting that occurred during the third quarter of 2006 that have materially affected, or are reasonably likely to materially affect,
each registrant’s internal control over financial reporting. 83
As of September 30, 2006
Current
Exposure
Securities
Held as
Collateral
Net
Exposure
Number
Counterparties
>10%
Net
Exposure of
Counterparties
>10%
(Millions)
(Millions)
$
275
$
59
$
274
2
(A)
$
144
1
—
1
—
—
9
—
9
—
—
21
—
21
—
—
$
306
$
59
$
305
2
$
144
(A)
Counterparty is PSE&G.
Certain information reported under Item 3 of Part I of the 2005 Annual Report on Form 10-K and under Item 1 of Part II of the Quarterly Reports on Form 10-Q for the quarters ended March 31,
2006 and June 30, 2006 is updated below. PSEG, PSE&G, Power and Energy Holdings See information on the following proceedings at the pages indicated for PSEG and each of PSE&G, Power and Energy Holdings as noted: Page
28. (PSE&G) Investigation Directive of NJDEP dated September 19, 2003
and additional investigation Notice dated September 15, 2003 by the EPA
regarding the Passaic River site. Docket No. EX93060255. Page
28. (Power) PSE&G’s MGP Remediation Program instituted by NJDEP’s
Coal Gasification Facility Sites letter dated March 25, 1988. Page
34. (Power) Filing of Complaint by Nuclear against the DOE on September
26, 2001 in the U.S. Court of Federal Claims, Docket No. 01-0551C seeking
damages caused by DOE’s failure to take possession of spent nuclear
fuel. The complaint was amended to include PSE&G as a prior owner
in interest. Page
36. (PSE&G) Deferral Proceeding filed with the BPU on August 28, 2002,
Docket No. EX02060363, and Deferral Audit beginning on October 2, 2002
at the BPU, Docket No. EA02060366. Page
38. (Energy Holdings) Dhofar Power Company SAOC v. Ministry of Housing,
Electricity and Water (Sultanate of Oman), ICC Reference EXP/233. Page
85. (PSEG, PSE&G Power and Energy Holdings) BPU proceeding on August
1, 2005 relating to ratepayer protections due to repeal of PUHCA under
the Energy Policy Act of 2005. Docket No. AX05070641. Page
86. (PSEG, PSE&G and Power) PJM Interconnection, L.L.C., Schedule
12 (Cost Allocation) filing with FERC, Docket No. ER06-456-000. Page
86. (PSEG, PSE&G and Power) FERC proceedings with MISO and PJM relating
to RTOR and SECA methodology, Docket No. ER05-6-000 et al. Page
86. (PSEG, PSE&G and Power) PJM Reliability Pricing Model filed with
FERC on August 31, 2005, Docket Nos. ER05-1410-000 and EL05-148-000. Page
87. (PSEG, PSE&G and Power) FERC proceeding relating to PJM Long-Term
Transmission Rate Design, Docket No. EL05-121-000. Page
87. (PSEG, PSE&G and Power) Notice of Inquiry issued by FERC on September
16, 2005 to prevent undue discrimination and preference in the provisions
of transmission service. Docket No. RM05-25-000. Page
88. (Power) PJM Interconnection, L.L.C. filing with FERC on November 2,
2004, Docket No. EL03-236-003 to amend Tariff and Operating Agreement
to request Reliability Must-Run (RMR) compensation. Page
88. (PSE&G) Neptune Regional Transmission System, LLC v. PJM Interconnection,
L.L.C. complaint filed with FERC on December 21, 2004, Docket No. EL05-48-00,
alleging PJM impermissibly conducted an interconnection re-study triggered
by generator retirements in PJM, which had the effect of increasing Neptune’s
cost exposure for network upgrades from approximately $4 million to $26
million. Page
89. (PSE&G) JCP&L v. ACE, et al. complaint filed with FERC on
December 30, 2004, Docket No. EL05-50-000, seeking to terminate its construction
obligations under the LDV Agreement. 84
(1)
(2)
(3)
(4)
(5)
(6)
Pages
57, 59 and 90. (PSE&G) BPU proceeding relating to Electric Distribution
financial review, Docket No. ER02050303.
(7)
Pages
57, 59 and 91. (PSE&G) PSE&G Petition for increase of gas base rates
filed with BPU on September 30, 2005, Docket No. GR05100845.
(8)
Pages
59 and 91. (PSE&G) PSE&G’s BGSS Commodity filing with the
BPU on May 28, 2004, Docket No. GR04050390.
(9)
(10)
(11)
(12)
(13)
(14)
(15)
(16)
(17)
Page
91. (PSE&G) Cost Recovery filing with the BPU on July 1, 2004, Docket
No. EE04070718.
Page 93. (PSE&G and Power) EPA request for a Remedial Investigation/Feasibility
Study on Berry's Creek Study Area.
Page 93. (PSE&G and Power) EPA notice to potentially responsible parties
with respect to contamination in the Newark Bay Study Area. Certain information reported under the 2005 Annual Report on Form 10-K and the Quarterly Report on Form 10-Q for the quarters ended March 31, 2006 and June 30, 2006 is updated below.
Additionally, certain information is provided for new matters that have arisen subsequent to the filing of the 2005 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for the quarters ended
March 31, 2006 and June 30, 2006. References are to the related pages on the Form 10-K and Form 10-Q as printed and distributed. Federal Regulation Public Utility Holding Company Act PSEG, PSE&G, Power and Energy Holdings 2005 Form 10-K, Page 15 and June 30, 2006 Form 10-Q, page 85. The Energy Policy Act, which became law on August 8, 2005, repealed the Public Utility Holding Company Act of 1935 (PUHCA)
as of February 8, 2006 and established PUHCA 2005. FERC has promulgated rules that would waive the accounting and reporting obligations of PUHCA 2005 for PSEG and its subsidiaries. Thus, PSEG,
PSE&G, Power and Energy Holdings do not expect PUHCA 2005 to materially affect their respective businesses, prospects or properties. For additional information on the impact of PUHCA repeal, see
State Regulation. FERC PSEG, PSE&G, Power and Energy Holdings Market Power 2005 Form 10-K, Page 16, March 31, 2006 Form 10-Q, Page 78 and June 30, 2006 Form 10-Q, Page 85. On February 28, 2006, PSEG Power Connecticut LLC (Power Connecticut) filed its triennial
updated market power report with FERC. On October 11, 2006, FERC issued an order accepting Power Connecticut’s triennial market power report. PSE&G and ER&T are required to file their respective
triennial updated market power reports with FERC by November 30, 2006. On May 19, 2006, FERC issued a Notice of Proposed Rulemaking (NOPR) concerning the standards to be used by FERC in granting market-based rate authority. The proposed regulations would
adopt, in most respects, the FERC’s current standards. In its NOPR, FERC suggests certain changes, such as in the areas of cost-based market power mitigation, modifications to the horizontal (generation)
market power screens, and clarifications to existing vertical market power screens. On September 20, 2006, PSE&G and Power submitted comments in this NOPR proceeding. The outcome of this proceeding
and its impact on PSEG, PSE&G, Power and Energy Holdings cannot be predicted at this time, but Power does not expect the new rules to disqualify its market-based rate authority. However, no assurances
can be given. 85
(18)
(19)
Page
92. (PSE&G and Power) BPU review of annual procurement process for BGS,
Docket No. EO06020119.
(20)
(21)
PSEG, PSE&G and Power PJM Schedule 12 Filing March 31, 2006 Form 10-Q, Page 78 and June 30, 2006 Form 10-Q, Page 85. On July 19, 2006, FERC consolidated PJM’s January 5, 2006 and May 4, 2006 filings that propose to allocate the costs of
new transmission projects that PJM has directed to be built through its Regional Transmission Expansion Plan (RTEP) process. These consolidated proceedings are currently in settlement before a FERC
Administrative Law Judge (ALJ). PSEG is actively participating in this proceeding, as the cost allocation methodology used by PJM may result in a disproportionate allocation of costs to load in the eastern
portion of PJM. PSEG, PSE&G and Power are unable to predict the outcome of this proceeding at this time. On July 21, 2006, PJM submitted to FERC a further proposal to allocate the costs of an additional group of new transmission projects that PJM has directed be built through its RTEP. The July 21,
2006 filing includes allocations for the $850 million, 200-mile 500 kV Loudon transmission line which runs from Allegheny Power’s service territory, through West Virginia to Northern Virginia, as well as
many other transmission projects in the PJM region. PJM has used the same allocation methodology to identify which load should pay for these new transmission projects through regulated transmission
rates. PSEG believes that this allocation methodology results in a disproportionate allocation of costs to load in the eastern portion of PJM. Motions to consolidate this proceeding with the filings made in
January and May are currently pending at FERC. Assuming continued pass-through of transmission charges to retail customers, neither Power nor PSE&G are expected to be impacted by the allocation of Schedule 12 charges. Regional through and out rates (RTOR) 2005 Form 10-K, Page 17, March 31, 2006 Form 10-Q, Page 78 and June 30, 2006 Form 10-Q, Page 86. A trial-type hearing, encompassing a review of the actual amount of lost revenues to be
recovered via the Seams Elimination Charge/Cost Adjustment/Assignment (SECA) mechanism, was held in May 2006. On August 10, 2006, the ALJ issued an initial decision finding that the rate design for
the recovery of SECA charges is flawed, and that the SECA rate charges are therefore unjust, unreasonable and unduly discriminatory. Exceptions to the initial decision were filed September 11, 2006 and
reply briefs to the exceptions taken were filed October 10, 2006. The FERC has not yet issued an order on review of the ALJ initial decision. In addition, in March 2006, PSE&G and Power entered into a
settlement with a limited group of parties in PJM, which settlement was certified to FERC, under which the parties have agreed to pay and collect reductions of SECA revenues. On October 12, 2006, the
limited settlement agreement was expanded to include additional parties. The FERC has not yet acted to approve either the March or the October SECA settlements. Due to the uncertainty of this
proceeding, PSE&G has continued to defer the collection of any SECA revenues on its books. At the present time, it is difficult to determine whether, and to what extent, the SECA initial decision, which is
currently being reviewed by FERC, will have an impact on PSEG, PSE&G and Power. PJM Reliability Pricing Model (RPM) 2005 Form 10-K, Page 17, March 31, 2006 Form 10-Q, Page 79 and June 30, 2006 Form 10-Q, Page 86. On August 31, 2005, PJM filed its RPM with FERC. The RPM constitutes a locational
installed capacity market design for the PJM region, including a forward auction for installed capacity priced according to a downward-sloping demand curve, recognition of locational value and a
transitional implementation of the market design. FERC issued an order on April 20, 2006 that accepted most of the core concepts of the RPM filing with an implementation date of June 1, 2007. The April
20, 2006 order set certain details of the filing for paper hearing and technical conference procedures including the slope of the demand curve and the mechanism for identification of the locational capacity
zones. Such hearing and technical conference procedures have now been completed. Also, commencing in June 2006, settlement discussions mediated by a FERC ALJ commenced at the request of certain
intervenors. A final settlement was filed with FERC on September 29, 2006 with a requested approval date of no later than December 22, 2006. FERC’s adoption of either the original PJM RPM
mechanism proposed in its August 2005 filing or the settlement proposal of September 2006 86
would be expected to have a favorable impact on generation facilities located in constrained locational zones. The final revenue impact of either of the two proposals on Power, particularly over an extended
time period, is difficult to quantify. In response to both PJM’s original filing, and the proposed settlement, PSE&G and Power have filed comments supporting the basic structural elements of the RPM
proposal but nonetheless have requested certain modifications which, in their view, would better promote the adequacy of generation reserves on a cost-effective basis. The April 20, 2006 order remains
subject to rehearing requests filed by several parties. Given the pending rehearing requests, the pending settlement agreement, and likelihood of eventual judicial appeals, PSEG, PSE&G and Power are
unable to predict the outcome of this proceeding. PJM Long-Term Transmission Rate Design 2005 Form 10-K, Page 17 and June 30, 2006 Form 10-Q, Page 86. On July 13, 2006, a FERC ALJ issued a decision concluding that the existing PJM modified zonal rate design for existing facilities
has been shown to be unjust and unreasonable, and should be replaced with a postage stamp rate design for such facilities to be effective April 1, 2006. To mitigate rate impacts, the ALJ has determined that
the rate design should be phased in, so that no customer receives greater than a 10% annual rate increase. The ALJ also determined that the existing process for allocating costs of new transmission projects
pursuant to Schedule 6 of PJM’s Operating Agreement and Schedule 12 of the PJM Tariff was just and reasonable. Briefs on exceptions to the ALJ’s initial decision and reply briefs have been filed in this
proceeding challenging the decision to find the existing rate design unjust and unreasonable, the appropriateness of imposing a postage stamp rate design, the decision as to the appropriateness of applying
the current Schedule 6 and Schedule 12 process for allocating costs of new transmission projects and the phase-in of the new rate design. FERC has not yet issued a decision on review of the ALJ’s initial
decision. Should FERC ultimately approve this postage stamp rate design on review of the ALJ’s initial decision, or adopt one or a combination of the alternative rate designs proposed, PSEG’s, PSE&G’s or
Power’s results of operations could be adversely impacted. It is not possible to predict the outcome of this proceeding at this time. FERC Order No. 888 Reform 2005 Form 10-K, Page 18 and June 30, 2006 Form 10-Q, Page 87. On May 18, 2006, FERC issued a NOPR seeking comments on whether reforms are needed to the protections that FERC
established in its Order No. 888 in order to prevent undue discrimination and preference in the provision of transmission service. FERC’s NOPR solicits input from the industry as to whether it should
revise the pro forma Open Access Transmission Tariff. Order No. 888 established this tariff to govern the terms and conditions under which transmission owners must provide transmission service to all
eligible customers. The NOPR addresses issues such as transmission planning, cost allocation issues for transmission projects and re-dispatch. Comments on the NOPR were filed in August 2006 and reply
comments were filed in September 2006. Moreover, a technical conference on these issues was held at FERC on October 12, 2006. FERC is expected to issue a Final Rule by the end of the year. Any
significant changes from the current Order 888 rules governing transmission access or transmission service may impact PSEG, PSE&G and Power, but it is difficult to predict the outcome of this proceeding at
this time. Locational Installed Capacity (LICAP) Market Settlement in New England 2005 Form 10-K, Page 18 and June 30, 2006 Form 10-Q, Page 87. On January 31, 2006, certain interested market participants in New England agreed to a settlement in principle of litigation
regarding the design of the region’s market for installed capacity, which would institute a transition period leading to the implementation of a new market design for capacity as early as 2010. Commencing
in December 2006, all generators in New England would begin to receive fixed capacity payments that escalate gradually over the transition period. RMR contracts, such as Power’s, would continue to be
effective until the implementation of the new market design. The new market design would consist of a forward auction for installed capacity that is intended to recognize the locational value of generators
on the system, and contains incentive mechanisms to encourage generator availability during generation shortages. During the transition period, these payments are expected to benefit Power’s Bridgeport
Harbor 2 plant. The final version of the settlement was filed with FERC on March 6, 2006 and was 87
approved by order dated June 16, 2006 finding that, as a package, the settlement represents a just and reasonable outcome. The settlement was contested by certain parties and it is anticipated that rehearing
of the June 16, 2006 order will be sought. PSEG and Power are unable to predict the outcome of this proceeding. Transmission Infrastructure On September 8, 2006, PJM filed with FERC a proposal that would significantly modify its regional transmission planning process for economic transmission planning. Currently, the PJM RTEP
identifies transmission that is needed to address reliability and operational performance needs of the PJM region, as well as historic unhedgeable congestion that exceeds certain thresholds and for which a
market response has not been forthcoming. The PJM proposal seeks to expand the economic portion of the RTEP by forecasting economic congestion over its transmission planning horizon, which, in 2006,
PJM modified from five to 15 years. PSE&G and Power filed a protest to the PJM proposal requesting that FERC reject PJM’s proposal or set it for hearing. If accepted without modification, the PJM
proposal may result in the establishment of a preference for rate-based transmission solutions to address congestion, as opposed to reliance on private investment and competitive non-transmission market
solutions. The outcome of this proceeding and the impact on PSEG, PSE&G and Power cannot be predicted at this time. On August 8, 2006, the U.S. Department of Energy (DOE) issued a National Electric Transmission Congestion Study (Congestion Study), as directed by Congress in the Energy Policy Act (EP Act).
This Congestion Study identified two areas in the United States as “critical congestion areas;” one of the areas is the region between New York and Washington, D.C. Under the EP Act, the DOE has the
ability to designate transmission corridors in these “critical congestion areas,” to which FERC back-stop transmission siting authority will attach. Thus, corridor designation may facilitate the construction of
rate-based transmission projects to address congestion in these corridors. The DOE has not yet designated any transmission corridors as a result of this Congestion Study but will likely do so by the end of
this year. PSE&G and Power filed comments to the Congestion Study, in which they contended that the Congestion Study contained several analytical flaws. PSEG, PSE&G and Power are unable to predict the
outcome of this proceeding at this time. Power RMR Status PJM 2005 Form 10-K, Page 18 and June 30, 2006 Form 10-Q, Page 88. Effective February 24, 2005, subject to refund and hearing, Power began to collect a monthly fixed payment of $3.3 million, net of
operating margins for the Sewaren 1, 2, 3 and 4 and Hudson 1 units. A detailed settlement was filed with FERC on September 23, 2005 that permits Power to recover annual fixed costs of approximately $19
million and $14.5 million for the Sewaren and Hudson units, respectively, plus reimbursements of Power’s expenditures in connection with certain construction at the units that are necessary to maintain
reliability, offset by certain revenues earned in PJM’s energy market. FERC accepted this settlement retroactive to February 24, 2005. On March 28, 2006, Power filed a refund report with FERC pursuant
to which Power refunded $11 million to PJM, although most of this refund related to the timing of payments under the settlement agreement and thus will be repaid to Power, with carrying charges, at a
later date. FERC did not issue a public notice requesting comments on the report and no party has made any objections or other comments with respect to the report. On October 2, 2006, Power provided
notice to PJM that it may be required to deactivate Hudson Unit 2 if an agreement is not reached with environmental regulators regarding the unit’s satisfaction of emissions reduction requirements that
would allow it to continue to operate after December 31, 2006. For additional information, see Note 5. Commitments and Contingencies of the Notes. Neptune Complaint Proceeding 2005 Form 10-K, Page 19 and June 30, 2006 Form 10-Q, Page 88. On December 21, 2004, Neptune filed a complaint with FERC against PJM. Neptune is directly interconnected to the 88
transmission system of FirstEnergy Corporation (FirstEnergy), but upgrades to the PSE&G transmission system are also required to move power across the grid. In its complaint, Neptune alleged that PJM
impermissibly conducted an interconnection re-study triggered by generator retirements in PJM, which had the effect of increasing Neptune’s cost exposure for network upgrades. On February 10, 2005,
FERC granted Neptune’s complaint against PJM and then denied rehearing on June 24, 2005. As a result of these orders, Neptune’s interconnection cost responsibility was capped at a level of
approximately $6 million, and recovery of the remaining $20 million in interconnection costs remains an issue, with potential allocation to PSE&G’s and FirstEnergy’s customers. On August 15, 2005, PSE&G sought judicial review of FERC’s orders in the U.S. Circuit Court of Appeals. Two additional petitioners also sought judicial review of these orders, and the BPU and Rate
Payer Advocate (RPA) have intervened in the case. Initial briefs and reply briefs in the case have been filed. The parties have also moved to hold the appeal in abeyance, as the costs at issue in this case are
now the subject of currently-pending settlement discussions in the PJM Schedule 12 Filing proceeding, discussed above. PSE&G cannot at this time predict the outcome of this appeal. PSE&G LDV Complaint Proceeding June 30, 2006 Form 10-Q, Page 89. On December 30, 2004, Jersey Central Power & Light Company (JCP&L) filed a complaint at FERC against the other four signatories to the Lower Delaware Valley
(LDV) Transmission System Agreement, including PSE&G. The LDV Agreement, governing the construction of, and investment in, certain 500 kV transmission facilities in New Jersey, was entered into by
the parties in 1977 and remains in effect until 2027. In the FERC complaint proceeding, JCP&L seeks to terminate its payment obligations to the other contract signatories. PSE&G receives approximately $2.7
million annually from JCP&L under the LDV Agreement and its related agreements, the term of which does not expire until 2027. On May 6, 2005, FERC issued an order dismissing JCP&L’s complaint.
Subsequently, in a rehearing order issued December 2, 2005, FERC set certain issues raised by JCP&L for hearing. The matter is now in litigation, with a hearing scheduled to take place in November 2006
and an initial decision to be rendered by the ALJ in March 2007. In this litigation, JCP&L is not only seeking to terminate its payment obligations but also to receive credit from PSE&G and the other LDV
Agreement parties for transmission facilities previously constructed by JCP&L in New Jersey; if the ALJ were to accept all of JCP&L’s crediting arguments, PSE&G would owe monies to JCP&L under the LDV
Agreement. PSE&G cannot predict the outcome of this proceeding at this time. NRC Power Nuclear Safety Issues 2005 Form 10-K, Page 20 and June 30, 2006 Form 10-Q, Page 89. In January 2004, the NRC issued a letter requesting Power to conduct a review of its Salem and Hope Creek nuclear generation
facilities to assess the workplace environment for raising and addressing safety issues. Power responded to the letter in February 2004 and had independent assessments of the work environment at both
facilities performed. The results of these assessments were provided to the NRC in May 2004. The assessments concluded that Salem and Hope Creek were safe for continued operations, but also identified
issues that needed to be addressed. At an NRC public meeting on June 16, 2004, Power outlined its action plan to address these issues, which focused on a safety-conscious work environment, the corrective action program and work
management. A letter documenting these plans and commitments was sent to the NRC on June 25, 2004. On July 30, 2004, the NRC provided a letter to Power indicating that it had completed its review.
The letter indicated that the NRC had not identified any safety violations and that it appeared that the PSEG action plan would address the key findings of both the NRC and Power assessments. On March
2, 2006, the NRC provided Power with its annual performance reviews of Salem and Hope Creek, 89
which detailed the NRC’s plan for enhanced oversight related to the work environment. The letter indicated the NRC plans to continue with this heightened oversight until Power has concluded that
substantial, sustainable progress has been made, and the NRC has completed a review that confirms Power’s conclusions. On August 31, 2006, the NRC provided Power with a letter, which cleared the
safety-conscious work environment issue at Salem and Hope Creek. The NRC has restored Salem and Hope Creek to normal oversight levels. State Regulation PSEG, PSE&G, Power and Energy Holdings PUHCA Repeal 2005 Form 10-K, Page 21, March 31, 2006 Form 10-Q, Page 80 and June 30, 2006 Form 10-Q, Page 90. The BPU has issued final regulations addressing the diversification activities of New Jersey
utilities and the companies owning such utilities. These new rules, which became effective October 2, 2006, impose a requirement that each New Jersey public utility and its holding company ensure that the
aggregate assets of all nonutility activities in the holding company system do not exceed a defined percentage of the aggregate assets of the utility and utility-related assets in the holding company system.
The rules broadly define utility-related activities to include such things as the production, generation, transmitting, delivering, storing, selling, marketing of natural gas, propane, electricity and other fuels to
wholesale or retail customers, energy management services and sale of energy appliances. Both PSE&G and PSEG currently satisfy these requirements and will continue to satisfy them based on the
companies’ current business plans. However, constant monitoring will be required to ensure that the regulation is satisfied or determine whether relief from the regulation is warranted. The BPU has not yet
acted on Phase II of its PUHCA rulemaking phase, which addresses broader issues such as corporate governance, access to books and records, and oversight of service agreements between utilities and their
affiliates. NJ Energy Master Plan The Governor of New Jersey has recently directed the BPU, in partnership with other New Jersey agencies, to develop an energy master plan. State law in New Jersey requires that an energy master
plan be developed every three years, the purpose of which is to ensure safe, secure and reasonably-priced energy supply, foster economic growth and development and protect the environment. In the
Governor’s directive regarding the energy master plan, the Governor established three specific goals: (1) reduce the State’s projected energy use by 20% by the year 2020; (2) supply 20% of the State’s
electricity needs with Class 1 renewable energy sources by 2020; and (3) emphasize energy efficiency, conservation and renewable energy resources to meet future increases in New Jersey electric demand
without increasing New Jersey’s reliance on non-renewable resources. PSEG is supportive and will be actively involved in the development of the plan. Public meetings on the energy master plan will take
place over the next few months, and a final plan is to be completed by October 2007. The outcome of this proceeding and its impact on PSEG, PSE&G and Power cannot be predicted at this time. PSE&G Electric Distribution Financial Review 2005 Form 10-K, Page 22, March 31, 2006 Form 10-Q, Page 81 and June 30, 2006 Form 10-Q, Page 90. Based on the Electric Base Rate Case approved in July 2003, PSE&G recorded a regulatory
liability in the second quarter of 2003 by reducing its depreciation reserve for its electric distribution assets by $155 million and amortized this liability from August 1, 2003 through December 31, 2005. The
$64 million annual amortization of this liability resulted in a reduction of Depreciation and Amortization expense. PSE&G filed for the elimination of the $64 million (based on 2003 test year sales volumes)
electric distribution rate credit effective January 1, 2006, subject to BPU approval, including a review of PSE&G’s earnings and other relevant financial information. Based on current sales volumes, the
amount approximates $69 million. 90
On October 27, 2006, PSE&G reached a settlement agreement in the Electric Distribution Financial Review. For additional information see Note 15. Subsequent Events. BGSS Filings 2005 Form 10-K, Page 2, March 31, 2006 Form 10-Q, Page 81 and June 30, 2006 Form 10-Q, Page 91. The parties to the 2005/2006 BGSS proceeding entered into a Stipulation in which the parties
agreed that the BGSS A hearing was held on June 29, 2006 regarding BGSS rates for the 2005/2006 period. Commodity Charge increases of September 1, 2005 and December 15, 2005 that were previously
approved by the BPU on a provisional basis should become final. The BPU approved the Stipulation. In addition, all the remaining gas contract issues were also resolved and an amended Gas Requirements
Contract was attached to the Stipulation and also approved by the BPU. The primary changes were the term was extended by five years, and the default provision was changed from three days to one day. PSE&G made its 2006/2007 BGSS filing on May 26, 2006. In this filing, PSE&G requested a reduction in annual BGSS gas revenues of approximately $19.7 million (excluding losses and New Jersey Sales
and Use Tax) or approximately a 1.0% decrease to be implemented for service rendered on and after October 1, 2006 or earlier. Additionally, PSE&G requested an increase in its Balancing Charge. The
combined impact of both changes for the class average residential heating customer is an increase in the winter monthly bills of approximately 0.1%; however, on an annual basis the impact is a decrease of
approximately 0.2%. The
parties entered into a Stipulation to make the filed rates effective October
1, 2006 on a provisional basis. However, since the time of the filing, prices
of gas futures have dropped significantly and as a result, additional BGSS data
has been requested by and provided to the BPU. Settlement discussions with the
BPU Staff have been completed and a new Stipulation has been executed by the
parties. This new Stipulation, which requires BPU approval, results in a decrease
in annual BGSS revenues of approximately $120 million, which is approximately
a 6% reduction in a typical residential gas customer’s bill. The Stipulation
did not include any change in the balancing charge, as requested. Gas Base Rate Case 2005 Form 10-K, Page 23, March 31, 2006 Form 10-Q, Page 81 and June 30, 2006 Form 10-Q, Page 91. On September 30, 2005, PSE&G filed a petition with the BPU seeking an overall 3.78%
increase in its gas base rates to cover the cost of gas delivery to be effective June 30, 2006. Approximately $55 million of the $133 million request is for an increase in book depreciation rates. On October 27, 2006, PSE&G reached a settlement agreement in the Gas Base Rate Case. For additional information see Note 15. Subsequent Events. CAS Cost Recovery Mechanism 2005 Form 10-K, Page 23, March 31, 2006 Form 10-Q, Page 82 and June 30, 2006 Form 10-Q, Page 91. The New Jersey Electric Discount and Energy Competition Act (EDECA) required that the
BPU provide electric and natural gas customers with the opportunity to choose a supplier for some or all electric or natural gas customer account services (CAS). In July 2004, PSE&G filed a petition with the
BPU to implement the CAS Cost Recovery Mechanism for both its electric and gas operations to recover $4 million of CAS costs and accumulated interest resulting from implementing PSE&G’s dual billing
for its delivery costs and for the third-party suppliers’ commodity charges as a result of customer migration from PSE&G. In September 2004, the case was transferred to the OAL as a contested case. A pre-
hearing conference was held on December 20, 2005 at which time a schedule was established. On April 7, 2006, a settlement agreement was reached and filed with the ALJ. On May 17, 2006, the BPU issued its Order approving the Initial Decision‑Settlement that fully resolved this matter. The Settlement will allow PSE&G to recover a total of $3.3 million of costs over a
one-year period. Recovery will begin as of the date of the next base rate change or January 1, 2007, whichever is earlier. 91
Power Connecticut Department of Public Utility Control (DPUC) To reduce the impact of federally-mandated congestion charges on Connecticut ratepayers, Connecticut has launched a procurement process to facilitate the development of incremental generation
capacity, as authorized by legislation which permits the DPUC to establish a competitive procurement process intended to encourage new supply-side and demand-side resources. Specifically, the DPUC is
required to develop and issue a request for proposals (RFP) to solicit the development of long-term projects, with local distribution companies serving as the counterparties to these contracts. The impact of
this RFP process on Power Connecticut’s assets is unclear at the present time. Connecticut Windfall Profits Tax 2005 Form 10-K, Page 24. The Connecticut General Assembly may hold a special legislative session in the fourth quarter of 2006 to consider comprehensive energy legislation. A proposal to impose a
‘windfall’ profits tax of between 20% and 50% on a power generator’s earnings in excess of 20% is also proposed for enactment and could be introduced and considered in the special session or in the
regular session commencing in January 2007. Revenues raised by such tax would be dedicated to financing the CEA and for rate relief. Neither PSEG nor Power is able to predict whether any of such
proposals will be enacted into law or their impact, if any, or whether similar initiatives may be considered in other jurisdictions. PSE&G and Power BGS Auction Review June 30, 2006 Form 10-Q, Page 90. In 2006, the BPU initiated a proceeding to review the annual BGS procurement process as well as the policy issues thereto for all of the New Jersey EDCs. In June
2006, the BPU ruled on certain issues regarding the acquisition of BGS for the period beginning in June 2007. The BPU agreed that a descending clock auction format should be used for the procurement of
BGS-FP supply for 2007. On
July 10, 2006, PSE&G filed the Joint EDC proposal for the procurement of
BGS for the period beginning June 1, 2007. This proposal includes a descending
clock auction format to be held in February 2007 for the procurement of all
BGS supply. On October 28, 2006, the BPU approved a descending clock auction
format for BGS-FP and BGS-CIEP supply for the period beginning June 1, 2007.
The BPU also approved auction rules and Supplier Master Agreements substantially
similar to those filed by the EDCs on July 10, 2006. The EDCs were ordered to
make a compliance filing with the BPU by November 3, 2006. Environmental Matters Power Carbon Dioxide (CO2) Emissions 2005 Form 10-K, Page 27, March 31, 2006 Form 10-Q, Page 82 and June 30, 2006 Form 10-Q, Page 92. Several states, primarily in the Northeastern U.S., are developing state-specific or regional
legislative initiatives to stimulate CO2 emissions reductions in the electric power industry. New York initiated the Regional Greenhouse Gas Initiative (RGGI) in April 2003. Currently, in the RGGI, seven
Northeastern states have signed a memorandum of understanding (MOU) intended to cap and reduce CO2 emissions from the electric power sector in the RGGI region. A final model rule was issued on
August 15, 2006 that embraces MOU commitments and makes recommendations for states to move forward. States are expected to enact legislation and/or regulation representing, at least, the minimum
requirements stipulated in the MOU. The NJDEP in 2005 finalized amendments to its regulations governing air pollution control that would designate CO2 as an air contaminant subject to regulation. The
RGGI program is scheduled to start in 2009. The outcome of this initiative cannot be determined at this time; however, adoption of stringent CO2 emissions reduction requirements in the Northeast could
materially impact Power’s operation of its fossil fuel-fired electric generating units. 92
PSE&G and Power Remedial Investigation/Feasibility Study March 31, 2006 Form 10-Q, page 82 and June 30, 2006 Form 10-Q, Page 92. On March 9, 2006, the U.S. Department of Environmental Protection Agency (EPA) sent PSE&G, Power and
approximately 157 other entities a notice that the EPA considered each of the entities to be a potentially responsible party (PRP) with respect to contamination in Berry’s Creek in Bergen County, New
Jersey and requesting that the PRPs perform a Remedial Investigation/Feasibility Study (RI/FS) on Berry’s Creek and the connected tributaries and wetlands. Berry’s Creek flows through approximately 6.5
miles of areas that have been used for a variety of industrial purposes and landfills. The EPA estimates that the study could be completed in approximately five years at a total cost of approximately $18
million. PSE&G and Power are unable to predict the outcome of this matter; however, the related costs are not expected to be material. Newark Bay Study Area On
August 24, 2006, the EPA sent PSE&G and three other entities a notice that
the EPA considered each of the entities to be a potentially responsible party
(PRP) with respect to contamination in the Newark Bay Study Area, which it defined
as Newark Bay and portions of the Hackensack River, the Arthur Kill, and the
Kill Van Kull. The notice letter requested that PSE&G participate and fund
the EPA-approved study in the Newark Bay Study Area and encouraged PSE&G
to contact Occidental Chemical Corporation (OCC) to discuss participating in
the RI/FS that OCC is conducting in the Newark Bay Study Area. EPA considers
the Newark Bay Study Area, along with the Passaic River Study Area, to be part
of the Diamond Alkali Superfund Site. The notice states EPA’s belief that
hazardous substances were released from sites owned by PSE&G and located
on the Hackensack River. The sites included two operating electric generating
stations (Hudson and Kearny Sites), and one former manufactured gas plant (MGP).
PSE&G’s costs to clean up former MGPs are recoverable from utility
customers through the societal benefits clause (SBC). The Hudson and Kearny
Sites were transferred to Power in August 2000. Power assumed any environmental
liabilities of PSE&G associated with the electric generating stations that
PSE&G transferred to it, including the Hudson and Kearny Sites. Power has
provided notice to insurers concerning this potential claim. PSE&G and Power
are unable to estimate the cost of the investigation at this time, but the costs
are likely to be material. Other PSEG Audit Fees The aggregate fees billed to PSEG and its subsidiaries by Deloitte & Touche for audit services rendered for the year ended December 31, 2005 totaled $8,501,094. The fees were incurred for audits of the
annual consolidated financial statements of PSEG and its subsidiaries, including the Annual Report on Form l0-K of PSEG and its subsidiaries, reviews of financial statements included in Quarterly Reports
on Form 10-Q of PSEG and its subsidiaries and for services rendered in connection with certain financing transactions and fees for accounting consultations related to the application of new accounting
standards and rules. Energy Holdings GWF June 30, 2006 Form 10-Q, Page 92. In April 2006, GWF Power Systems, L.P. and Hanford L.P., each a partnership 50% owned by Global, executed amendments to their respective power purchase
agreements to establish fixed price energy sales terms for a five-year period. The California Public Utilities Commission approved the amendments on July 20, 2006; the amendments became effective and
the five-year term commenced in August 2006. 93
A listing of exhibits being filed with this document is as follows: a. PSEG: Exhibit 12: Computation of Ratios of Earnings to Fixed Charges Exhibit 31: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 Exhibit 31.1: Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 Exhibit 32: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code Exhibit 32.1: Certification by Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code b. PSE&G: Exhibit 12.1: Computation of Ratios of Earnings to Fixed Charges Exhibit 12.2: Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements Exhibit 31.2: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 Exhibit 31.3: Certification by Robert E. Busch Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 Exhibit 32.2: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code Exhibit 32.3: Certification by Robert E. Busch Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code c. Power: Exhibit 12.3: Computation of Ratios of Earnings to Fixed Charges Exhibit 31.4: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 Exhibit 31.5: Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 Exhibit 32.4: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code Exhibit 32.5: Certification by Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code d. Energy Holdings: Exhibit 12.4: Computation of Ratios of Earnings to Fixed Charges Exhibit 31.6: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 Exhibit 31.7: Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934 Exhibit 32.6: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code Exhibit 32.7: Certification by Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code 94
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly
authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
PUBLIC SERVICE ENTERPRISE GROUP
INCORPORATED Date: November 1, 2006 95
(Registrant)
By:
Vice President and Controller
(Principal Accounting Officer)
SIGNATURE Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly
authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
PUBLIC SERVICE ELECTRIC AND
GAS COMPANY Date: November 1, 2006 96
(Registrant)
By:
Vice President and Controller
(Principal Accounting Officer)
SIGNATURE Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly
authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
PSEG POWER LLC Date: November 1, 2006 97
(Registrant)
By:
Vice President and Controller
(Principal Accounting Officer)
SIGNATURE Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly
authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
PSEG ENERGY HOLDINGS L.L.C. Date: November 1, 2006 98
(Registrant)
By:
Controller
(Principal Accounting Officer)