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 MARCH 31, 2007
OR
£ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
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Commission |
Registrants, State of Incorporation, |
I.R.S. Employer |
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001-09120 |
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED |
22-2625848 |
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001-00973 |
PUBLIC SERVICE ELECTRIC AND GAS COMPANY |
22-1212800 |
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000-49614 |
PSEG POWER LLC |
22-3663480 |
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000-32503 |
PSEG ENERGY HOLDINGS L.L.C. |
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):
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Public Service Enterprise Group Incorporated |
Large accelerated filer S |
Accelerated filer £ |
Non-accelerated filer £ |
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Public Service Electric and Gas Company |
Large accelerated filer £ |
Accelerated filer £ |
Non-accelerated filer S |
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PSEG Power LLC |
Large accelerated filer £ |
Accelerated filer £ |
Non-accelerated filer S |
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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 April 30, 2007, Public Service Enterprise Group Incorporated had outstanding 253,516,650 shares of its sole class of Common Stock, without par value.
As of April 30, 2007, 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
Page
ii Financial Statements
1
5
9
12
16
17
Note 3. Discontinued Operations, Dispositions and Impairments
19
21
21
31
34
34
35
36
37
39
40
42 Management’s Discussion and Analysis of Financial Condition and Results of Operations
44
44
48
54
60
60 Qualitative and Quantitative Disclosures About Market Risk
61 Controls and Procedures
65 Legal Proceedings
66 Submission of Matters to a Vote of Security Holders
68 Other Information
69 Exhibits
75
76 i
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:
•
regulatory issues that significantly impact operations; • 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 attract and retain management and other key employees; • changes in the electric industry, including changes to regional transmission organizations and 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; • 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; • ability to recover investments or service debt as a result of any of the risks or uncertainties mentioned herein; • acts of war or terrorism; ii
PSEG, PSE&G and Energy Holdings
•
adverse changes in rate regulation and/or ability to obtain adequate and timely rate relief;
PSEG, Power and Energy Holdings
inability to effectively manage portfolios of electric generation assets, gas supply contracts and electric and gas supply obligations; • inability to meet generation operating performance expectations; • energy transmission constraints or lack thereof; • adverse changes in the market for energy, capacity, natural gas, coal, nuclear fuel, 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; PSEG and Power
•
changes in regulation and safety and security measures at nuclear facilities; • ability to maintain nuclear operating performance at projected levels; PSEG and Energy Holdings
•
changes in foreign currency exchange rates; • deterioration in the credit of lessees and their ability to adequately service lease rentals; • ability to realize tax benefits and favorably resolve tax audit claims; • 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
•
PART I. FINANCIAL INFORMATION PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
For the Quarters Ended
March 31,
2007
2006
(Millions) OPERATING REVENUES
$
3,614
$
3,461 OPERATING EXPENSES Energy Costs
2,041
2,146 Operation and Maintenance
610
578 Depreciation and Amortization
196
201 Taxes Other Than Income Taxes
43
41 Total Operating Expenses
2,890
2,966 Income from Equity Method Investments
26
33 OPERATING INCOME
750
528 Other Income
72
50 Other Deductions
(37
)
(27
) Interest Expense
(187
)
(193
) Preferred Stock Dividends
(1
)
(1
) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
597
357 Income Tax Expense
(262
)
(149
) INCOME FROM CONTINUING OPERATIONS
335
208 Loss from Discontinued Operations, net of tax benefit of $4 and $5 in 2007 and 2006, respectively
(6
)
(5
) NET INCOME
$
329
$
203 WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS): BASIC
252,892
251,187 DILUTED
253,356
252,065 EARNINGS PER SHARE: BASIC INCOME FROM CONTINUING OPERATIONS
$
1.32
$
0.83 NET INCOME
$
1.30
$
0.81 DILUTED INCOME FROM CONTINUING OPERATIONS
$
1.32
$
0.83 NET INCOME
$
1.30
$
0.81 DIVIDENDS PAID PER SHARE OF COMMON STOCK
$
0.585
$
0.57 See Notes to Condensed Consolidated Financial Statements. 1
ITEM 1. FINANCIAL STATEMENTS
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
March 31,
December 31,
(Millions) ASSETS CURRENT ASSETS Cash and Cash Equivalents
$
483
$
141 Accounts Receivable, net of allowances of $60 and $52 in 2007 and 2006, respectively
1,806
1,368 Unbilled Revenues
260
328 Fuel
355
847 Materials and Supplies
297
290 Prepayments
54
72 Restricted Funds
46
79 Derivative Contracts
53
127 Assets of Discontinued Operations
325
325 Assets Held for Sale
42
40 Other
48
45 Total Current Assets
3,769
3,662 PROPERTY, PLANT AND EQUIPMENT
19,107
18,851 Less: Accumulated Depreciation and Amortization
(5,974
)
(5,849
) Net Property, Plant and Equipment
13,133
13,002 NONCURRENT ASSETS Regulatory Assets
5,288
5,694 Long-Term Investments
3,774
3,868 Nuclear Decommissioning Trust (NDT) Funds
1,324
1,256 Other Special Funds
154
147 Goodwill
534
539 Intangibles
49
46 Derivative Contracts
37
55 Other
300
301 Total Noncurrent Assets
11,460
11,906 TOTAL ASSETS
$
28,362
$
28,570 See Notes to Condensed Consolidated Financial Statements. 2
CONDENSED CONSOLIDATED BALANCE SHEETS
2007
2006
(Unaudited)
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
March 31,
December 31,
(Millions) LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year
$
739
$
849 Commercial Paper and Loans
277
381 Accounts Payable
1,013
964 Derivative Contracts
414
335 Accrued Interest
185
124 Accrued Taxes
225
152 Clean Energy Program
123
120 Other
508
481 Total Current Liabilities
3,484
3,406 NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC)
4,079
4,462 Regulatory Liabilities
448
646 Asset Retirement Obligations
517
509 Other Postretirement Benefit (OPEB) Costs
1,091
1,089 Accrued Pension Costs
330
327 Clean Energy Program
105
133 Environmental Costs
416
421 Derivative Contracts
200
204 Long-Term Accrued Taxes
496
— Other
173
176 Total Noncurrent Liabilities
7,855
7,967 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) CAPITALIZATION LONG-TERM DEBT Long-Term Debt
7,638
7,636 Securitization Debt
1,668
1,708 Project Level, Non-Recourse Debt
822
840 Debt Supporting Trust Preferred Securities
186
186 Total Long-Term Debt
10,314
10,370 SUBSIDIARIES’ PREFERRED SECURITIES Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2007 and 2006—795,234 shares
80
80 COMMON STOCKHOLDERS’ EQUITY Common Stock, no par, authorized 500,000,000 shares; issued; 2007—266,576,508 shares; 2006—266,372,440 shares
4,683
4,661 Treasury Stock, at cost; 2007—13,189,987 shares; 2006—13,727,032 shares
(499
)
(516
) Retained Earnings
2,717
2,710 Accumulated Other Comprehensive Loss
(272
)
(108
) Total Common Stockholders’ Equity
6,629
6,747 Total Capitalization
17,023
17,197 TOTAL LIABILITIES AND CAPITALIZATION
$
28,362
$
28,570 See Notes to Condensed Consolidated Financial Statements. 3
CONDENSED CONSOLIDATED BALANCE SHEETS
2007
2006
(Unaudited)
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
For The Three
Months Ended
2007
2006
(Millions) CASH FLOWS FROM OPERATING ACTIVITIES Net Income
$
329
$
203 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization
196
205 Amortization of Nuclear Fuel
25
25 Provision for Deferred Income Taxes (Other than Leases) and ITC
(13
)
3 Non-Cash Employee Benefit Plan Costs
46
59 Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes
(15
)
(22
) Gain on Sale of Investments
(16
)
— Undistributed Losses (Earnings) from Affiliates
31
(29
) Foreign Currency Transaction Loss (Gain)
1
(1
) Unrealized Losses on Energy Contracts and Other Derivatives
34
21 (Under) Over Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs
(47
)
49 Under Recovery of Societal Benefits Charge (SBC)
(1
)
(19
) Net Realized Gains and Income from NDT Funds
(19
)
(18
) Net Change in Certain Current Assets and Liabilities
450
524 Employee Benefit Plan Funding and Related Payments
(21
)
(35
) Investment Income and Dividend Distributions from Partnerships
11
1 Other
(35
)
(56
) Net Cash Provided By Operating Activities
956
910 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment
(275
)
(240
) Proceeds from the Sale of Investments and Return of Capital from Partnerships
7
2 Proceeds from NDT Funds Sales
501
300 Investment in NDT Funds
(511
)
(305
) Restricted Funds
34
(17
) NDT Funds Interest and Dividends
12
10 Other
(1
)
17 Net Cash Used In Investing Activities
(233
)
(233
) CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Commercial Paper and Loans
(104
)
54 Issuance of Common Stock
33
17 Redemptions of Long-Term Debt
(113
)
(457
) Repayment of Non-Recourse Debt
(16
)
(12
) Redemption of Securitization Debt
(38
)
(36
) Redemption of Debt Underlying Trust Securities
—
(154
) Cash Dividends Paid on Common Stock
(148
)
(143
) Other
5
(15
) Net Cash Used In Financing Activities
(381
)
(746
) Effect of Exchange Rate Change
—
(1
) Net Increase (Decrease) in Cash and Cash Equivalents
342
(70
) Cash and Cash Equivalents at Beginning of Period
141
288 Cash and Cash Equivalents at End of Period
$
483
$
218 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid
$
85
$
25 Interest Paid, Net of Amounts Capitalized
$
126
$
134 See Notes to Condensed Consolidated Financial Statements. 4
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Ended March 31,
(Unaudited)
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
For The Quarters
2007
2006
(Millions) OPERATING REVENUES
$
2,486
$
2,293 OPERATING EXPENSES Energy Costs
1,665
1,574 Operation and Maintenance
325
301 Depreciation and Amortization
145
152 Taxes Other Than Income Taxes
43
41 Total Operating Expenses
2,178
2,068 OPERATING INCOME
308
225 Other Income
5
4 Other Deductions
(1
)
(1
) Interest Expense
(81
)
(85
) INCOME BEFORE INCOME TAXES
231
143 Income Tax Expense
(99
)
(65
) NET INCOME
132
78 Preferred Stock Dividends
(1
)
(1
) EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE
$
131
$
77 See disclosures regarding Public Service Electric and Gas Company 5
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Ended
March 31,
(Unaudited)
GROUP INCORPORATED
included in the Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
March 31,
December 31,
(Millions) ASSETS CURRENT ASSETS Cash and Cash Equivalents
$
45
$
28 Accounts Receivable, net of allowances of $55 in 2007 and $46 in 2006
1,142
805 Unbilled Revenues
260
328 Materials and Supplies
57
50 Prepayments
16
14 Restricted Funds
13
12 Other
44
38 Total Current Assets
1,577
1,275 PROPERTY, PLANT AND EQUIPMENT
11,193
11,061 Less: Accumulated Depreciation and Amortization
(3,853
)
(3,794
) Net Property, Plant and Equipment
7,340
7,267 NONCURRENT ASSETS Regulatory Assets
5,288
5,694 Long-Term Investments
150
149 Other Special Funds
54
53 Other
115
115 Total Noncurrent Assets
5,607
6,011 TOTAL ASSETS
$
14,524
$
14,553 See disclosures regarding Public Service Electric and Gas Company 6
CONDENSED CONSOLIDATED BALANCE SHEETS
2007
2006
(Unaudited)
included in the Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
March 31,
December 31,
(Millions) LIABILITIES AND CAPITALIZATION CURRENT LIABILITIES Long-Term Debt Due Within One Year
$
173
$
284 Commercial Paper and Loans
269
31 Accounts Payable
261
254 Accounts Payable—Affiliated Companies, net
503
645 Accrued Interest
43
55 Clean Energy Program
123
120 Derivative Contracts
15
2 Other
398
322 Total Current Liabilities
1,785
1,713 NONCURRENT LIABILITIES Deferred Income Taxes and ITC
2,494
2,517 Other Postretirement Benefit (OPEB) Costs
897
898 Accrued Pension Costs
133
133 Regulatory Liabilities
448
646 Clean Energy Program
105
133 Environmental Costs
363
367 Asset Retirement Obligations
223
221 Derivative Contracts
27
18 Long-Term Accrued Taxes Due to Affiliate
51
— Other
6
6 Total Noncurrent Liabilities
4,747
4,939 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) CAPITALIZATION LONG-TERM DEBT Long-Term Debt
3,003
3,003 Securitization Debt
1,668
1,708 Total Long-Term Debt
4,671
4,711 PREFERRED SECURITIES Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2007 and 2006—795,234 shares
80
80 COMMON STOCKHOLDER’S EQUITY Common Stock; 150,000,000 shares authorized, 132,450,344 shares issued and outstanding
892
892 Contributed Capital
170
170 Basis Adjustment
986
986 Retained Earnings
1,192
1,061 Accumulated Other Comprehensive Income
1
1 Total Common Stockholder’s Equity
3,241
3,110 Total Capitalization
7,992
7,901 TOTAL LIABILITIES AND CAPITALIZATION
$
14,524
$
14,553 See disclosures regarding Public Service Electric and Gas Company 7
CONDENSED CONSOLIDATED BALANCE SHEETS
2007
2006
(Unaudited)
included in the Notes to Condensed Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
For the Quarters
Ended
2007
2006
(Millions) CASH FLOWS FROM OPERATING ACTIVITIES Net Income
$
132
$
78 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization
145
152 Provision for Deferred Income Taxes and ITC
(24
)
(25
) Non-Cash Employee Benefit Plan Costs
35
42 Non-Cash Interest Expense
1
— Employee Benefit Plan Funding and Related Payments
(16
)
(13
) Over Recovery of Electric Energy Costs (BGS and NTC)
4
19 (Under)/Over Recovery of Gas Costs
(51
)
30 Under Recovery of SBC
(1
)
(19
) Other Non-Cash Charges
(1
)
(1
) Net Changes in Certain Current Assets and Liabilities: Accounts Receivable and Unbilled Revenues
(269
)
82 Materials and Supplies
(7
)
— Prepayments
(4
)
35 Accrued Taxes
41
22 Accrued Interest
(11
)
(16
) Accounts Payable
7
(34
) Accounts Receivable/Payable-Affiliated Companies, net
59
(52
) Other Current Assets and Liabilities
27
(21
) Other
(6
)
(12
) Net Cash Provided By Operating Activities
61
267 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment
(130
)
(108
) Net Cash Used In Investing Activities
(130
)
(108
) CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Debt
238
— Redemption of Securitization Debt
(38
)
(36
) Redemption of Long-Term Debt
(113
)
(148
) Preferred Stock Dividends
(1
)
(1
) Net Cash Provided by (Used In) Financing Activities
86
(185
) Net Increase (Decrease) In Cash and Cash Equivalents
17
(26
) Cash and Cash Equivalents at Beginning of Period
28
159 Cash and Cash Equivalents at End of Period
$
45
$
133 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid
$
49
$
(4
) Interest Paid, Net of Amounts Capitalized
$
102
$
92 See disclosures regarding Public Service Electric and Gas Company 8
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
March 31,
(Unaudited)
included in the Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC
For the Quarters
Ended
2007
2006
(Millions) OPERATING REVENUES
$
2,149
$
1,967 OPERATING EXPENSES Energy Costs
1,488
1,487 Operation and Maintenance
238
232 Depreciation and Amortization
34
31 Total Operating Expenses
1,760
1,750 OPERATING INCOME
389
217 Other Income
51
41 Other Deductions
(29
)
(19
) Interest Expense
(37
)
(32
) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
374
207 Income Tax Expense
(155
)
(86
) INCOME FROM CONTINUING OPERATIONS
219
121 Loss from Discontinued Operations, net of tax benefit of $4 and $6 in 2007 and 2006, respectively
(6
)
(9
) EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
$
213
$
112 See disclosures regarding PSEG Power LLC included in the 9
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
March 31,
(Unaudited)
Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC
March 31,
December 31,
(Millions) ASSETS CURRENT ASSETS Cash and Cash Equivalents
$
7
$
13 Accounts Receivable
535
430 Accounts Receivable - Affiliated Companies, net
251
495 Short-Term Loan to Affiliate
525
— Fuel
354
846 Materials and Supplies
204
202 Energy Trading Contracts
50
55 Derivative Contracts
1
56 Assets of Discontinued Operations
325
325 Assets Held for Sale
40
40 Other
23
26 Total Current Assets
2,315
2,488 PROPERTY, PLANT AND EQUIPMENT
5,969
5,868 Less: Accumulated Depreciation and Amortization
(1,696
)
(1,638
) Net Property, Plant and Equipment
4,273
4,230 NONCURRENT ASSETS Deferred Income Taxes and Investment Tax Credits (ITC)
39
— Nuclear Decommissioning Trust (NDT) Funds
1,324
1,256 Goodwill
16
16 Other Intangibles
38
35 Other Special Funds
43
42 Energy Trading Contracts
10
10 Derivative Contracts
19
19 Other
51
50 Total Noncurrent Assets
1,540
1,428 TOTAL ASSETS
$
8,128
$
8,146 LIABILITIES AND MEMBER’S EQUITY CURRENT LIABILITIES Accounts Payable
$
623
$
589 Short-Term Loan from Affiliate
—
54 Energy Trading Contracts
66
222 Derivative Contracts
311
90 Accrued Interest
80
34 Other
96
95 Total Current Liabilities
1,176
1,084 NONCURRENT LIABILITIES Deferred Income Taxes and Investment Tax Credits (ITC)
—
48 Asset Retirement Obligations
292
287 Other Postretirement Benefit (OPEB) Costs
139
138 Energy Trading Contracts
5
19 Derivative Contracts
157
151 Accrued Pension Costs
107
106 Environmental Costs
53
54 Long-Term Accrued Taxes due to Affiliate
22
— Other
16
18 Total Noncurrent Liabilities
791
821 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) LONG-TERM DEBT Total Long-Term Debt
2,818
2,818 MEMBER’S EQUITY Contributed Capital
2,000
2,000 Basis Adjustment
(986
)
(986
) Retained Earnings
2,661
2,586 Accumulated Other Comprehensive Loss
(332
)
(177
) Total Member’s Equity
3,343
3,423 TOTAL LIABILITIES AND MEMBER’S EQUITY
$
8,128
$
8,146 See disclosures regarding PSEG Power LLC included in the 10
CONDENSED CONSOLIDATED BALANCE SHEETS
2007
2006
(Unaudited)
Notes to Condensed Consolidated Financial Statements.
PSEG POWER LLC
For The Three
Months Ended
2007
2006
(Millions) CASH FLOWS FROM OPERATING ACTIVITIES Net Income
$
213
$
112 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization
34
35 Amortization of Nuclear Fuel
25
25 Interest Accretion on Asset Retirement Obligations
6
8 Provision for Deferred Income Taxes and ITC
26
24 Unrealized Losses on Energy Contracts and Other Derivatives
4
21 Non-Cash Employee Benefit Plan Costs
7
11 Net Realized Gains and Income from NDT Funds
(19
)
(18
) Net Change in Certain Current Assets and Liabilities: Fuel, Materials and Supplies
490
413 Accounts Receivable
(105
)
187 Accrued Interest
46
55 Accounts Payable
57
(292
) Accounts Receivable/Payable-Affiliated Companies, net
72
145 Other Current Assets and Liabilities
4
18 Employee Benefit Plan Funding and Related Payments
(1
)
(16
) Other
(35
)
(46
) Net Cash Provided By Operating Activities
824
682 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment
(126
)
(118
) Proceeds from NDT Funds Sales
501
300 NDT Funds Interest and Dividends
12
10 Investment in NDT Funds
(511
)
(305
) Short-Term Loan - Affiliated Company, net
(525
)
(380
) Other
(2
)
10 Net Cash Used In Investing Activities
(651
)
(483
) CASH FLOWS FROM FINANCING ACTIVITIES Cash Dividend Paid
(125
)
— Short-Term Loan—Affiliated Company, net
(54
)
(202
) Net Cash Used In Financing Activities
(179
)
(202
) Net Decrease in Cash and Cash Equivalents
(6
)
(3
) Cash and Cash Equivalents at Beginning of Period
13
8 Cash and Cash Equivalents at End of Period
$
7
$
5 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid
$
24
$
18 Interest Paid, Net of Amounts Capitalized
$
3
$
2 See disclosures regarding PSEG Power LLC included in the 11
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
March 31,
(Unaudited)
Notes to Condensed Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C.
For The
Quarters
Ended
2007
2006
(Unaudited) OPERATING REVENUES Electric Generation and Distribution Revenues
$
201
$
263 Income from Leveraged and Operating Leases
33
39 Other
20
10 Total Operating Revenues
254
312 OPERATING EXPENSES Energy Costs
161
194 Operation and Maintenance
53
49 Depreciation and Amortization
14
12 Total Operating Expenses
228
255 Income from Equity Method Investments
26
33 OPERATING INCOME
52
90 Other Income
16
7 Other Deductions
(2
)
(7
) Interest Expense
(43
)
(50
) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES
23
40 Income Tax Expense
(20
)
(12
) INCOME FROM CONTINUING OPERATIONS
3
28 Income from Discontinued Operations, net of tax expense of $1 in 2006
—
4 EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
$
3
$
32 See disclosures regarding PSEG Energy Holdings L.L.C. included in the 12
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
March 31,
Notes to Condensed Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C.
March 31,
December 31,
(Unaudited) ASSETS CURRENT ASSETS Cash and Cash Equivalents
$
65
$
98 Accounts Receivable: Trade-net of allowances of $5 and $6 in 2007 and 2006, respectively
111
103 Other Accounts Receivable
18
29 Affiliated Companies
33
— Notes Receivable: Affiliated Companies
25
28 Inventory
35
41 Restricted Funds
33
67 Assets Held for Sale
2
— Derivative Contracts
2
14 Other
7
8 Total Current Assets
331
388 PROPERTY, PLANT AND EQUIPMENT
1,726
1,706 Less: Accumulated Depreciation and Amortization
(310
)
(307
) Net Property, Plant and Equipment
1,416
1,399 NONCURRENT ASSETS Leveraged Leases, net
2,746
2,810 Corporate Joint Ventures and Partnership Interests
836
868 Goodwill
518
523 Intangibles
11
11 Derivative Contracts
8
26 Other
139
139 Total Noncurrent Assets
4,258
4,377 TOTAL ASSETS
$
6,005
$
6,164 See disclosures regarding PSEG Energy Holdings L.L.C. included in the 13
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions)
2007
2006
Notes to Condensed Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C.
March 31,
December 31,
(Unaudited) LIABILITIES AND MEMBER’S EQUITY CURRENT LIABILITIES Long-Term Debt Due Within One Year
$
43
$
42 Short-Term Borrowings
8
— Accounts Payable: Trade
67
54 Affiliated Companies
2
12 Derivative Contracts
17
16 Accrued Interest
44
27 Other
63
72 Total Current Liabilities
244
223 NONCURRENT LIABILITIES Deferred Income Taxes and Investment and Energy Tax Credits
1,653
1,925 Derivative Contracts
8
11 Long-Term Accrued Taxes due to Affiliate
424
— Other
103
102 Total Noncurrent Liabilities
2,188
2,038 COMMITMENTS AND CONTINGENT LIABILITIES (See Note 5) MINORITY INTERESTS
26
26 LONG-TERM DEBT Project Level, Non-Recourse Debt
822
840 Senior Notes
1,149
1,149 Total Long-Term Debt
1,971
1,989 MEMBER’S EQUITY Ordinary Unit
1,048
1,193 Retained Earnings
434
592 Accumulated Other Comprehensive Income
94
103 Total Member’s Equity
1,576
1,888 TOTAL LIABILITIES AND MEMBER’S EQUITY
$
6,005
$
6,164 See disclosures regarding PSEG Energy Holdings L.L.C. included in the 14
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions)
2007
2006
Notes to Condensed Consolidated Financial Statements.
PSEG ENERGY HOLDINGS L.L.C.
2007
2006
For The Quarters
Ended
(Unaudited) CASH FLOWS FROM OPERATING ACTIVITIES Net Income
$
3
$
32 Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: Depreciation and Amortization
14
13 Demand Side Management Amortization
—
1 Deferred Income Taxes (Other than Leases)
(14
)
4 Leveraged Lease Income, Adjusted for Rents Received and Deferred Income Taxes
(15
)
(22
) Undistributed Losses (Earnings) from Affiliates
31
(29
) Gain on Sale of Investments
(16
)
(2
) Unrealized Gain on Investments
—
(1
) Foreign Currency Transaction Loss (Gain)
1
(1
) Change in Fair Value of Derivative Financial Instruments
30
1 Net Changes in Certain Current Assets and Liabilities: Accounts Receivable
13
25 Inventory
5
3 Accounts Payable
21
(29
) Other Current Assets and Liabilities
7
4 Investment Income and Dividend Distributions from Partnerships
11
1 Other
—
1 Net Cash Provided By Operating Activities
91
1 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment
(16
)
(14
) Proceeds from Sale of Property
—
1 Proceeds from the Sale of Investments
7
2 Short-Term Loan Receivable - Affiliated Company, net
3
351 Restricted Funds
34
(17
) Other
1
1 Net Cash Provided By Investing Activities
29
324 CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Borrowings
8
— Repayment of Non-Recourse Long-Term Debt
(16
)
(12
) Repayment of Senior Notes
—
(309
) Return of Contributed Capital
(145
)
— Other
—
(1
) Net Cash Used In Financing Activities
(153
)
(322
) Effect of Exchange Rate Change
—
(1
) Net (Decrease) Increase In Cash and Cash Equivalents
(33
)
2 Cash and Cash Equivalents at Beginning of Period
98
68 Cash and Cash Equivalents at End of Period
$
65
$
70 Supplemental Disclosure of Cash Flow Information: Income Taxes Paid
$
1
$
2 Interest Paid, Net of Amounts Capitalized
$
23
$
26 See disclosures regarding PSEG Energy Holdings L.L.C. included in the 15
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
March 31,
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). 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 New Jersey Board of Public Utilities (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 certain Fossil subsidiaries are also subject to state regulation, 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 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 and general services to PSEG and its subsidiaries. These include accounting, treasury, risk management, planning, information technology, tax, law,
corporate secretarial, human resources, investor relations, corporate communications and certain other 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 16
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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, 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, 2006. Reclassifications PSEG, PSE&G, Power and Energy Holdings Certain reclassifications have been made to the prior quarter financial statements to conform to the current quarter presentation. The reclassifications relate primarily to PSE&G’s determination, during
the fourth quarter of 2006, that the revenues and expenses related to one of its contracts that had been recorded on a gross basis would more appropriately be recorded on a net basis in Operating Revenues
based upon the provisions of EITF 99-19, “Reporting Revenue Gross as a Principal versus Net as an Agent”. Therefore, prior amounts have been reclassified, resulting in a reduction of $57 million in both
Operating Revenues and Energy Costs for the quarter ended March 31, 2006 for PSEG and PSE&G, with no impact on Operating Income. Note 2. Recent Accounting Standards The following accounting standards were issued by the Financial Accounting Standards Board (FASB), but have not yet been adopted by PSEG, PSE&G, Power and Energy Holdings. Statement of Financial Accounting Standards (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 also nullifies the guidance in footnote 3 of Emerging Issues Task Force (EITF) Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3). The guidance in footnote 3 applies to derivative instruments measured at fair value at initial recognition, and it
precludes immediate recognition in earnings of an unrealized gain or loss, measured as the difference between the transaction price and the fair value of the instrument at initial recognition, if the fair value
of the instrument is determined using significant unobservable inputs. Under EITF 02-3, an entity cannot recognize an unrealized gain or loss at inception of a derivative instrument unless the fair value of
that instrument is obtained from a quoted market price in an active market or is otherwise evidenced by comparison to other observable current market transactions or based on a valuation technique
incorporating observable market data. SFAS 157 requires that the principles of fair value measurement apply for derivatives and other financial instruments at initial recognition and in all subsequent
periods. SFAS 157 is effective for financial statements issued for fiscal years beginning after November 15, 2007; however, earlier application is encouraged. PSEG, PSE&G, Power and Energy Holdings are
currently 17
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS assessing the potential impact of SFAS 157 on their respective consolidated financial positions and results of operations. SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159) PSEG, PSE&G, Power and Energy Holdings In February 2007, the FASB issued SFAS 159, which permits entities to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair
value. An entity will report unrealized gains and losses on items where the fair value option has been elected in earnings at each subsequent reporting date. The objective is to improve financial reporting by
providing entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions.
The decision about whether to elect the fair value option is applied instrument by instrument, with a few exceptions; the decision is irrevocable; and the decision is required to be applied to entire
instruments and not to portions of instruments. The statement requires disclosures that facilitate comparisons (a) between entities that choose different measurement attributes for similar assets and liabilities and (b) between assets and liabilities in
the financial statements of an entity that selects different measurement attributes for similar assets and liabilities. SFAS 159 is effective for financial statements issued for fiscal years beginning after November 15, 2007. Upon implementation, an entity shall report the effect of the first remeasurement to fair value as
a cumulative effect adjustment to the opening balance of Retained Earnings. PSEG, PSE&G, Power and Energy Holdings are currently assessing the potential impact of SFAS 159 on their respective
consolidated financial positions and results of operations. The following new accounting standards were adopted by PSEG, PSE&G, Power and Energy Holdings during 2007. FASB Interpretation No. 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 reflect expected future tax consequences of such positions presuming the tax authorities’ full knowledge of the position
and all relevant facts. FIN 48 permits recognition of the benefit of tax positions only when it is “more likely-than-not” that the position is sustainable based on the merits of the position. It further limits the
amount of tax benefit to be recognized to the largest amount of benefit that is greater than 50% likely of being realized. FIN 48 also requires explicit disclosures about uncertainties in income tax positions,
including a detailed roll-forward of unrecognized tax benefits taken that do not qualify for financial statement recognition. FIN 48 was effective January 1, 2007. In general, companies record the change in net assets that resulted from the application of FIN 48 as an adjustment to Retained Earnings. However, for PSE&G,
because any charges to income arising from the adoption of FIN 48 would be recoverable in future rates, the offset to any incremental PSE&G liability is recorded as a Regulatory Asset rather than Retained
Earnings. The following table presents the impact at January 1, 2007 on the Condensed Consolidated Balance Sheets for PSEG and its subsidiaries as a result of implementing FIN 48:
PSE&G
Power
Energy
PSEG
Balance Sheet
(Millions) Increase to Long Term Accrued Taxes
$
20
$
21
$
355
$
396 Decrease to Accumulated Deferred Income Tax Liability
$
9
$
7
$
246
$
262 Increase to Regulatory Assets
$
11
$
—
$
—
$
11 Decrease to Retained Earnings
$
—
$
14
$
109
$
123 18
(UNAUDITED)
Holdings
Consolidated
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The impact to earnings resulting from the adoption of FIN 48 for the quarter ended March 31, 2007 was an after-tax decrease of $6 million for PSEG, including $1 million for Power and $5 million for
Energy Holdings. There was no impact on earnings for PSE&G. For additional information relating to the impacts of FIN 48, see Note 11. Income Taxes. FASB Staff 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 addressed 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 13, “Accounting for Leases,” stating that a change in the timing of the above referenced cash flows must be reviewed at least annually or more
frequently, if events or circumstances indicate a change in timing is probable. 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 was adopted January 1, 2007. The cumulative effect of applying the provisions of this FSP is reported as an adjustment to the beginning balance of Retained Earnings as of the
date of adoption. As a result of implementing FSP 13-2, upon adoption PSEG and Energy Holdings each recognized a reduction in Investment in Leveraged Leases of $73 million, a reduction in Deferred
Income Taxes of $22 million and a reduction in Retained Earnings of $51 million. The impact to earnings resulting from the adoption of FSP 13-2 for the quarter ended March 31, 2007 was an after-tax decrease of $3 million for PSEG and Energy Holdings. Note 3. Discontinued Operations, Dispositions and Impairments Discontinued Operations Power Lawrenceburg Energy Center (Lawrenceburg) On December 29, 2006, Power entered into an agreement to sell its natural gas-fired Lawrenceburg facility located in Lawrenceburg, Indiana to AEP Generating Company, a subsidiary of American
Electric Power Company, Inc. (AEP). The sale price for the facility and inventory is $325 million. The proceeds, together with anticipated reduction in tax liability, are expected to be approximately $425 million and will be used to retire
debt. The transaction will result in an after-tax charge to PSEG’s and Power’s earnings of approximately $208 million, or about $0.82 cents per share of PSEG common stock, which was reflected as a charge
in Discontinued Operations in the fourth quarter of 2006. Power has received the required regulatory approvals for the sale and anticipates that the transaction will close in the second quarter of 2007. Lawrenceburg’s operating results for the quarters ended March 31, 2007 and 2006, which were reclassified to Discontinued Operations, are summarized below:
Quarters Ended
2007
2006
(Millions) Operating Revenues
$
—
$
— Loss Before Income Taxes
$
(10
)
$
(15
) Net Loss
$
(6
)
$
(9
) 19
(UNAUDITED)
March 31,
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS The carrying amounts of the assets of Lawrenceburg as of March 31, 2007 and December 31, 2006 are summarized in the following table:
As of
As of
(Millions) Current Assets
$
10
$
10 Noncurrent Assets
315
315 Total Assets of Discontinued Operations
$
325
$
325 Energy Holdings Elektrocieplownia Chorzow Elcho Sp. Z o.o. (Elcho) and Elektrownia Skawina SA (Skawina) On May 29, 2006, Global completed the sale of its interest in two coal-fired plants in Poland, Elcho and Skawina. Proceeds, net of transaction costs, were $476 million, resulting in a gain of $227 million
net of tax expense of $142 million. 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 March 31, 2006 are summarized below:
Quarter Ended
Elcho
Skawina
(Millions) Operating Revenues
$
30
$
33 Income Before Income Taxes
$
3
$
2 Net Income
$
3
$
1 Dispositions Power In December 2006, Power recorded a pre-tax impairment loss of $44 million to write down four turbines to their estimated realizable value and reclassified them to Assets Held for Sale on Power’s
Condensed Consolidated Balance Sheet. In April 2007, Power sold the four turbines to a third party and received proceeds of approximately $40 million, which approximates the recorded book value. Energy Holdings Global Thermal Energy Development Partnership, L.P. (Tracy Biomass) On December 22, 2006, Global entered into an agreement to sell its 34.5% interest in Tracy Biomass for approximately $7 million. The sale closed on January 26, 2007 and resulted in a 2007 pre-tax
gain of approximately $7 million ($6 million after-tax). Impairment Energy Holdings Venezuela PSEG has indirect ownership interests in two generating facilities in Maracay and Cagua, Venezuela that have a total capacity of 120 MW. The projects are owned and operated by Turboven, an entity
which is jointly-owned by Global (50%) and Corporacion Industrial de Energia (CIE). Global also has a 9% indirect interest in TGM through a partnership with CIE. As of March 31, 2007, the book value
of these investments was approximately $35 million. During Global’s year-end review of its equity method investments, management concluded that due to the current political situation in Venezuela, it is probable that Global would not be able to
recover its 20
(UNAUDITED)
March 31, 2007
December 31, 2006
March 31, 2006
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS capitalized costs associated with its investments in Venezuela. Therefore, Global recorded a pre-tax impairment loss of approximately $7 million to write down these investments in the fourth quarter of
2006. In January 2007, the Venezuelan government announced its intention to nationalize certain sectors of Venezuelan industry and commerce, including certain foreign-owned energy and communications
companies. In a subsequent press release, Turboven was named as one of the companies that Venezuela intended to nationalize. Since these announcements, Venezuela has proceeded to nationalize certain
companies; however, Global has not received any further official communication from the government of Venezuela regarding Turboven. 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 and upon payment of performance units. The following table shows the effect of these stock options and performance units on the weighted average number of shares outstanding
used in calculating diluted EPS:
Quarters Ended March 31,
2007
2006
Basic
Diluted
Basic
Diluted EPS Numerator: Earnings (Millions) Continuing Operations
$
335
$
335
$
208
$
208 Discontinued Operations
(6
)
(6
)
(5
)
(5
) Net Income
$
329
$
329
$
203
$
203 EPS Denominator (Thousands): Weighted Average Common Shares Outstanding
252,892
252,892
251,187
251,187 Effect of Stock Options
—
390
—
787 Effect of Stock Performance Units
—
74
—
91 Total Shares
252,892
253,356
251,187
252,065 EPS: Continuing Operations
$
1.32
$
1.32
$
0.83
$
0.83 Discontinued Operations
(0.02
)
(0.02
)
(0.02
)
(0.02
) Net Income
$
1.30
$
1.30
$
0.81
$
0.81 Dividend payments on common stock for the quarter ended March 31, 2007 were $0.585 per share and totaled approximately $148 million. Dividend payments on common stock for the quarter ended
March 31, 2006 were $0.57 per share and totaled approximately $143 million. Note 5. Commitments and Contingent Liabilities Guaranteed Obligations Power Power contracts for electricity, natural gas, oil, coal, pipeline capacity, transportation and emission allowances and engages in risk management activities through ER&T. These activities primarily involve
the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are executed with both numerous
counterparties and brokers. Counterparties and brokers may require guarantees, cash or cash related instruments to be deposited on these transactions as described below. 21
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Power has unconditionally guaranteed payments by its subsidiaries, ER&T and PSEG Power New York Inc. (Power New York) in commodity-related transactions to support current exposure, interest
and other costs on sums due and payable in the ordinary course of business. These payment guarantees are provided to counterparties in order to obtain credit. Under these agreements, guarantees 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 March 31, 2007 and
December 31, 2006 was approximately $1.6 billion. 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 them 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 receivable and accounts payable and
the forward value on open positions, less any margins posted. The current exposure from such liabilities was $532 million and $518 million as of March 31, 2007 and December 31, 2006, respectively. Power is subject to counterparty 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.. As of March 31, 2007, Power
had posted margin of approximately $66 million, primarily in the form of letters of credit, and received margin of approximately $57 million to satisfy collateral obligations and support various contractual
and environmental obligations. As of December 31, 2006, Power had posted margin of approximately $40 million, primarily in the form of letters of credit, and received margin of approximately $86 million,
including approximately $82 million in the form of letters of credit. 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 March 31, 2007 and December 31, 2006, Power had deposited margin of
approximately $164 million and $89 million, respectively. Exchange-traded transactions that are margined and monitored separately from physical trading activity may not be subject to change in the event
of a downgrade to Power’s rating. In the event of a deterioration of Power’s credit rating to below investment grade, which would represent a two level downgrade from its current ratings, many of these agreements allow the
counterparty to demand that ER&T provide further performance assurance. As of March 31, 2007, 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 $664 million. Power
believes that it has sufficient liquidity to post such collateral, if necessary. 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. In 2006, Global sold its investments in Poland. As of March 31, 2007 and December 31, 2006, Global was still obligated for the $6 million equity commitment guarantee at Skawina. The guarantee
expires in August 2007. If payments are required, such payments are indemnified by the purchaser in accordance with the purchase agreement. Global also has a contingent guarantee expiring in April 2011 related to debt service obligations associated with Chilquinta Energia S.A., an energy distribution company in Chile in which Global owns
50%. As of March 31, 2007 and December 31, 2006, the contingent guarantee was approximately $25 million. 22
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 March 31, 2007
and December 31, 2006, there were $14 million of such bonds outstanding, which are related to uncompleted construction projects. As of March 31, 2007 and December 31, 2006, there was an additional $2
million of performance guarantees related to Energy Technologies. As of March 31, 2007 and December 31, 2006, Energy Holdings and/or Global have various other guarantees amounting to $28 million and $30 million, respectively. 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 their 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 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 65 other
PRPs, have 23
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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. In 2006, the EPA 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 has engaged in discussions with the EPA regarding the offer and approximately 70 PRPs, including PSE&G and Power, have
agreed to assume responsibility for the study pursuant to an Administrative Order on Consent and to divide the associated costs among themselves according to a mutually agreed-upon formula. 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 sites 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. The Remediation Program is periodically reviewed, and the estimated costs are revised by PSE&G based
on regulatory requirements, experience with the program and available remediation technologies. Since the inception of the Remediation Program in 1988 through March 31, 2007, PSE&G had expenditures
of approximately $390 million. During the fourth quarter of 2006, 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 $798 million and $838 million, including amounts spent to date. No amount within the range was considered to be most likely. Therefore,
$408 million was accrued at March 31, 2007, which represents the difference between the low end of the total program cost estimate of $798 million and the total incurred costs through March 31, 2007 of
$390 million. Of this amount, approximately $45 million was recorded in Other Current Liabilities and $363 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 $408 million Regulatory Asset was recorded. Costs for the MGP Remediation Program were approximately $42 million for 2006. PSE&G anticipates spending $47 million in 2007, $50 million in 2008, and an average of approximately $40 million per
year each year thereafter through 2016. 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, 24
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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. Power also agreed to spend at least $6 million on supplemental environmental projects and pay a $1 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 subsequently notified the EPA and the NJDEP that it was 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. On November 30, 2006, Power reached an agreement with the EPA and NJDEP on an amendment to its 2002 agreement
intended to achieve the emissions reductions targets of this agreement while providing more time to assess the feasibility of installing additional advanced emissions controls at Hudson. The amended agreement with the EPA and the NJDEP, which is pending final approval, would allow Power to continue operating Hudson and extend for four years the deadline for installing
environmental controls beyond the previous December 31, 2006 deadline. Power will be required to undertake a number of technology projects (SCRs, scrubbers, baghouses, carbon injection), plant
modifications and operating procedure changes at Hudson and Mercer designed to meet targeted reductions in emissions of NOx, SO2, particulate matter and mercury. In addition, Power has agreed to
notify the EPA and NJDEP by the end of 2007 whether it will install the additional emissions controls at Hudson by the end of 2010, or plan for the orderly shut down of the unit. Under the program to date, Power has installed SCRs at Mercer at a cost of approximately $114 million. The cost of implementing the balance of the amended agreement at Mercer and Hudson is
estimated at approximately $500 million for Mercer and at $600 million to $750 million for Hudson and will be incurred in the 2007-2010 timeframe. As part of the agreement, Fossil has agreed to purchase
and retire emissions allowances, contribute approximately $3 million for programs to reduce particulate emissions from diesel engines in New Jersey and pay a $6 million civil penalty. In addition, in March
2007, Fossil entered into an engineering, procurement and construction contract with a third party contractor to complete all back-end technology requirements for the Mercer station, as referenced above. As a result of the agreement, Power increased its environmental reserves by approximately $15 million to account for civil penalties associated with the amendment to the agreement and other costs.
PSEG and Power recorded the charge in Other Deductions on their respective Condensed Consolidated Statements of Operations in the fourth quarter of 2006. Mercury Regulation New Jersey and Connecticut have adopted standards for the reduction of emissions of mercury from coal-fired electric generating units. In February 2007, Pennsylvania also issued new requirements for
the reduction of mercury emissions from coal-fired power plants. Connecticut 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. With respect to Power’s New Jersey facilities, the other half of the reductions that are required to be achieved by December 15, 2007 will be achieved through the installation of
carbon injection technology and baghouses as part of Power’s multi-pollutant reduction agreement with the NJDEP, which resulted from the amended 2002 agreement that resolved issues arising out of the
PSD and the NSR air pollution control programs at the Hudson, Mercer and Bergen facilities, discussed above. 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 25
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS costs for each project are between $150 million and $200 million. The Mercer expenditures are included in the PSD/NSR discussion above. Connecticut has released proposed revisions to mercury regulations that encompass “Permit Requirements for Mercury Emissions from Coal-Fired Electric Generating Units”. On March 13, 2007, the
Connecticut Department of Environmental Protection (CTDEP) released its hearing report on the “Permit Requirements from Mercury Emissions from Coal-Fired Electric Generating Units”. On February
17, 2007, Pennsylvania finalized its “State-specific” requirements to reduce mercury emissions from coal-fired electric generating units. As written, the regulations would not materially affect the costs
already identified in Power’s capital expenditures forecast. New Jersey Industrial Site Recovery Act (ISRA) Potential environmental liabilities related to subsurface contamination at certain generating stations have been identified. In the second quarter of 1999, in anticipation of the transfer of PSE&G’s
generation-related assets to Power, a study was conducted pursuant to ISRA, which applies to the sale of certain assets. Power had a $51 million liability as of March 31, 2007 and December 31, 2006, 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, expiring in July 2006, allowing for the continued operation of Salem with
its existing cooling water intake system. A renewal application prepared in accordance with Federal Water Pollution Control Act (FWPCA) Section 316(b) and the Phase II 316(b) rule was filed in February
2006 with the NJDEP, which allows the station to continue operating under its existing NJPDES permit until a new permit is issued. Power’s application to renew Salem’s NJPDES permit demonstrates that
the station satisfies FWPCA Section 316(b) and meets the Phase II 316(b) rule’s performance standards for reduction of impingement and entrainment through the station’s existing cooling water intake
technology and operations plus implemented restoration measures. The application further demonstrates that even without the benefits of restoration, the station meets the Phase II 316(b) rule’s site-specific
determination standards, both on a comparison of the costs and benefits of new intake technology as well as a comparison of the costs to implement the technology at the facility to the cost estimates
prepared by the EPA. The U.S. Court of Appeals for the Second Circuit issued a decision after Power filed its application that rejected the use of restoration and the site-specific cost-benefit test under the
Phase II 316(b) rule. The Second Circuit Court and the United States Supreme Court have granted requests by the EPA and the industry petitioners for additional time to appeal the Second Circuit Court’s
decision. If NJDEP were to require the installation of structures at the Salem facility to reduce cooling water intake flow commensurate with closed cycle cooling as a result of the unfavorable decision in
the Phase II litigation, the costs would be material. Power’s application to renew the permit estimated that the costs associated with cooling towers for Salem are approximately $1 billion, of which Power’s
share would be approximately $575 million. If NJDEP and the CTDEP were to require installation of closed-cycle cooling or its equivalent at Power’s five once-through cooled facilities, compliance with
that requirement could have a significant impact on the facilities. These costs are not included in Power’s currently forecasted capital expenditures. Energy Holdings Bioenergie S.p.A. (Bioenergie) In May 2006, Global became the majority shareholder of Prisma 2000 S.p.A. In March 2007, the shareholders of Prisma 2000 S.p.A. agreed to change the company name to Bioenergie. Bioenergie holds
100% of the stock of San Marco Bioenergie S.p.A (San Marco), owner of a 20 MW biomass generation facility in Italy. Global also assumed operational responsibility for the facility in May 2006, which was
previously operated by Carlo Gavazzi Green Power pursuant to a Services Agreement with a Global subsidiary. Global’s total investment in Bioenergie is approximately $80 million. 26
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS In August 2006, Global became aware that the Italian government was conducting a criminal investigation regarding allegations of violations of the facility’s air permit. The scope of the investigation
was subsequently expanded to include alleged violations of the facility’s waste recycling and waste storage permits. The alleged violations include exceedances of permit limits for regulated pollutants,
manipulation of the facility’s continuous emission monitoring system, false reporting and the use of fuels not authorized by the permit. The Italian government has named five individuals as targets of the criminal investigation, including three former San Marco employees (including the former Managing Director and former plant and
operations managers) and two former members of the facility’s Board of Directors. While San Marco has not been named as a target, there is a potential risk that it could be so named. In December 2006
and January 2007, the facility was served with orders that prohibit it from conducting operations (Sequestration Orders) to prevent recurring violations and the destruction of evidence. Counsel for San
Marco has advised the Prosecuting Attorney that it will fully cooperate with the ongoing investigation and will implement the corrective actions required to prevent recurrence of the violations. On April 26, 2007, the Prosecutor issued an order lifting the Sequestration Orders and returning control of the plant to San Marco. It is anticipated that the facility will resume commercial operations in
the summer of 2007. Electroandes S.A. (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 $9 million through March 31, 2007. Electroandes believes it has valid legal defenses to these claims, and has filed an appeal with SUNAT with
respect to which it has not yet received a response; however, no assurances can be given regarding the outcome of this matter. In March 2007, Global announced that it is exploring a potential sale of
Electroandes. Luz del Sur S.A.A. (LDS) In January 2007, SUNAT filed two tax assessments against LDS totaling approximately $18 million, of which Global’s share would be approximately $7 million based on its 38% interest in LDS. The
assessments relate to deductions LDS claimed beginning in 2000 for certain operating fees it paid to International Technical Operators under a technical services agreement, for certain bad debt deductions
and certain other matters. The above assessments include interest and penalties claimed by SUNAT. LDS believes that most of such deductions were appropriate and filed an appeal in February 2007. LDS
has obtained a legal opinion that it should be successful in contesting these material items/disallowances, however, no assurances can be given. New Generation and Development Power Power has contracts with outside parties to purchase upgraded turbines for Salem Unit 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 upgrade 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 of capacity. Power’s expenditures to date
approximate $184 million (including Interest Capitalized During Construction (IDC) of $20 million) with an aggregate estimated share of total costs for these projects of $207 million (including IDC of $23
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. 27
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS) PSE&G and Power PSE&G is required to obtain all electric supply requirements through the annual New Jersey BGS auctions for customers who do not purchase electric supply from third-party suppliers. PSE&G enters into
the Supplier Master Agreement (SMA) with the winners of these BGS auctions within three business days following 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
Term Ending
May
2007(a)
May
2008(b)
May
2009(c)
May
2010(d)
34 months
36 months
36 months
36 months Load (MW)
2,840
2,840
2,882
2,758 $ per kWh
$
0.05515
$
0.06541
$
0.10251
$
0.09888
(a)
Prices set in the February 2004 BGS auction. (b) Prices set in the February 2005 BGS auction. (c) Prices set in the February 2006 BGS auction. (d) Prices set in the February 2007 BGS auction, which becomes effective on June 1, 2007 when the agreements for the 34-month (May 2007) BGS-FP supply agreements expire. 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 above. In addition to the BGS-related contracts, Power enters into firm supply contracts with EDCs, as well as other firm sales and commitments. PSE&G has a full requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. The contract extends through March 31, 2012, and year-to-year thereafter. Power has
entered into hedges for a portion of these 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. Minimum Fuel Purchase Requirements Power Coal and Oil Power purchases coal and oil for certain of its fossil generation stations through various long-term commitments. The coal purchase commitments through 2009 amount to approximately 70% of its
average anticipated coal needs, including transportation. These commitments total approximately $659 million. Nuclear Fuel Power has several long-term purchase contracts for the supply of nuclear fuel for the Salem and Hope Creek Nuclear Generating Stations. Power has inventory and commitments to purchase sufficient
quantities of uranium (concentrates and uranium hexafluoride) to meet 100% of its total estimated requirements 28
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS through 2011. Additionally, Power has commitments covering approximately 55% of its estimated requirements for 2012 and 15% from 2013 through 2016. These commitments, based on current market
prices, total approximately $577 million ($428 million Power’s estimated share). Power’s policy is to maintain certain levels of concentrates and uranium hexafluoride in inventory and to make periodic
purchases to support such levels. As such, the commitments referred to above include estimated quantities to be purchased that are in excess of contractual minimum quantities. Power also has commitments that provide 100% of its uranium enrichment requirements through 2010 that total approximately $200 million ($147 million Power’s estimated share). Power has commitments for the fabrication of fuel assemblies for reloads required through 2011 for Salem and through 2012 for Hope Creek that total approximately $123 million ($93 million Power’s
estimated share). Natural Gas 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 March 31, 2007, the total minimum requirements under these contracts were approximately $1.1 billion through 2016. These purchase obligations are consistent with Power’s strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts. Energy Holdings The Texas generation facilities have entered into gas supply agreements for their anticipated fuel requirements to satisfy obligations under their forward energy sales contracts. The plants had fuel
purchase commitments totaling $106 million to support all of their contracted energy sales. Operating Services Contract (OSC) Power On January 17, 2005, Nuclear entered into an OSC with Exelon Generation LLC (Exelon) relating to the operation of the Hope Creek and Salem nuclear generating stations. The OSC requires Exelon
to provide key personnel to oversee daily plant operations at the Hope Creek and Salem nuclear generating stations and to implement a management model that Exelon has used to manage 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 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. On October 27, 2006, Nuclear informed Exelon that it was electing to
continue the OSC for up to two years beyond the initial January 2007 period. In December 2006, Power announced its plans to resume direct management of the Salem and Hope Creek nuclear generating stations before the expiration of the OSC. As part of this plan, on January
1, 2007, the senior management team at Salem and Hope Creek, which consisted of three senior executives from Exelon, became employees of Power. Power has continued to recruit additional employees
to build its organizational structure. Power is analyzing its various options and expects to implement a plan during the second quarter to fully resume functions that Exelon currently performs, which would
put Power in a position to terminate the OSC by the end of 2007. 29
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 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. 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 for PSE&G, 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 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, an outstanding Treasury regulation project could overturn the holding in the PLR if the Treasury were to alter a position set out in certain 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 a 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 audits of deferred balances, which are under various adjustment clauses. A draft Deferral Audit—Phase II report relating to the 12-month period ended
July 31, 2003 was released by the consultant to the BPU in April 2005. The draft report addresses the SBC, Market Transition Charge (MTC) and Non-Utility Generation (NUG) deferred balances. The
BPU released the report on May 13, 2005. While the consultant to the BPU found that the 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 $130 million. On January 31, 2007, PSE&G requested that the matter be transmitted to the Office of Administrative Law for the development of an evidentiary record and an initial decision. The BPU granted the
request on February 7, 2007. 30
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 this proceeding. New Jersey Clean Energy Program PSE&G 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 sum of PSE&G’s electric
and gas funding requirement was $37 million and $30 million for the three months ended March 31, 2007 and 2006, respectively. The remaining liability has been recorded at a discounted present value with
an offsetting Regulatory Asset, since the costs associated with this program are expected to be recovered from PSE&G ratepayers through the SBC. The liability for the funding requirement as of March 31,
2007 and December 31, 2006 was $228 million and $253 million, respectively. Leveraged Lease Investments PSEG and Energy Holdings On November 16, 2006, the IRS issued a report with respect to its audit of PSEG’s corporate tax returns for tax years 1997 through 2000, which disallowed all deductions associated with certain of
Resources’ lease transactions that are similar to a type that the IRS publicly announced its intention to challenge. In addition, the IRS imposed a 20% penalty for substantial understatement of tax liability.
In February 2007, PSEG filed a protest to the Office of Appeals of the IRS. As of March 31, 2007 and December 31, 2006, Resources’ total gross investment in such transactions was approximately $1.4
billion and $1.5 billion, respectively. If all deductions associated with these lease transactions, entered into by PSEG between 1997 and 2002, 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 will aggressively contest the IRS’s disallowance. PSEG believes that it is more likely than not that it will prevail with respect to the IRS’s challenge,
although no assurances can be given. If the IRS’s disallowance of tax benefits associated with all of these lease transactions was sustained, approximately $796 million of PSEG’s deferred tax liabilities that have been recorded under
leveraged lease accounting through March 31, 2007 would become currently payable. In addition, current interest would be charged of approximately $132 million after-tax, and penalties of $159 million
may become payable. Energy Holdings’ management has assessed the probability of various outcomes to this matter and recorded reserves in accordance with FIN 48. For additional information and guidance for leveraged leases, see Note 2. Recent Accounting Standards. 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, 31
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS 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 Commodity Contracts Power Power actively transacts in energy and energy-related products, including electricity, natural gas, electric capacity, firm transmission rights (FTRs), coal, oil and emission allowances in the spot, forward
and futures markets, primarily in the Northeastern and Mid Atlantic United States. 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, futures and FTRs. During the quarter ended March 31, 2007, higher market prices for
electricity have resulted in additional unrealized losses on many of these contracts leading to an increase in Accumulated Other Comprehensive Loss (OCL). Power marks its derivative energy-related
contracts to market in accordance with 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 and forward prices,
as applicable, to interpolate certain prices. The effect of using such modeling techniques is not material to Power’s financial results. 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 March
31, 2007, the fair value of these hedges was $(449) million and resulted in $(267) million after-tax recorded in OCL. As of December 31, 2006, the fair value of these hedges was $(166) million. These hedges,
along with realized losses on hedges of $(19) million retained in OCL, resulted in a $(108) million after-tax balance in OCL. The increase of $159 million in OCL during the quarter ended March 31, 2007
was caused mainly by higher electricity market prices. During the 12 months ending March 31, 2008, $186 million after-tax of net unrealized losses on these commodity derivatives is expected to be
reclassified to earnings. Approximately $85 million of after-tax unrealized losses on these commodity derivatives in OCL is expected to be reclassified to earnings for the 12 months ending March 31, 2009.
Ineffectiveness associated with these hedges, as defined in SFAS 133, was $(2) million at March 31, 2007. The expiration date of the longest dated cash flow hedge is in 2010. 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 March 31, 2007 was less than $(1) million. The net fair value of these instruments as of
December 31, 2006 was $1 million. Energy Holdings Other Derivatives The Texas generation facilities enter into electricity forward and capacity sale contracts to sell their 2,000 MW capacity for portions of the current calendar year, with the balance sold into the daily spot
market. The 32
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Texas generation facilities also enter 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 the Texas generation facilities, 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 $9 million and $38 million as of March 31, 2007 and December 31, 2006, respectively. 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 March 31, 2007 and December 31, 2006,
the fair value of the hedge was $(7) million and $(9) 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 March 31, 2007, the fair value of these cash flow hedges was $(5) million, consisting of $(4) million and $(1) million at PSE&G and Energy Holdings,
respectively. As of December 31, 2006, the fair value of these cash flow hedges was $(4) million, primarily at PSE&G. The $(4) million at PSE&G as of both March 31, 2007 and December 31, 2006 is not
included in Accumulated Other Comprehensive Income/Loss, as it is deferred as a Regulatory Asset and is expected to be recovered from PSE&G’s customers. During the next 12 months, approximately $1
million of unrealized losses (net of taxes) on interest rate derivatives in OCL is expected to be reclassified at PSEG. As of March 31, 2007, there was no hedge ineffectiveness associated with these hedges. 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
changes in the Peruvian Nuevo Sol and the Chilean Peso and to a lesser extent, the Euro. Changes in valuation of these currencies can impact the value of Global’s investments, results of operations,
financial condition and cash flows. Global has attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust for changes in foreign exchange rates. Global may also
use foreign currency forward, swap and option agreements to manage risk related to certain foreign currency fluctuations. 33
(UNAUDITED)
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Although the Chilean Peso and the Peruvian Nuevo Sol had originally depreciated relative to the U.S. Dollar after Global’s initial investments, the currencies have appreciated significantly over the
past few years. The net cumulative foreign currency revaluations have increased the total amount of Energy Holdings’ Member’s Equity by $124 million as of March 31, 2007. 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 in the U.S. Dollar to Chilean Peso exchange rate. The fair value of the cross-currency swaps was $(22) million and $(25) million as of March 31, 2007 and December 31, 2006, respectively.
The change in fair value of the majority of the swaps is recorded in Cumulative Translation Adjustment within OCL. As a result, Energy Holdings’ Member’s Equity was reduced by $22 million as of March
31, 2007. Note 7. Comprehensive Income, Net of Tax
PSE&G
Power(A)
Energy
Other
Consolidated
(Millions) For the Quarter Ended March 31, 2007: Net Income (Loss)
$
132
$
213
$
3
$
(19
)
$
329 Other Comprehensive Loss
—
(155
)
(9
)
—
(164
) Comprehensive Income (Loss)
$
132
$
58
$
(6
)
$
(19
)
$
165 For the Quarter Ended March 31, 2006: Net Income (Loss)
$
78
$
112
$
32
$
(19
)
$
203 Other Comprehensive Income
—
133
2
1
136 Comprehensive Income (Loss)
$
78
$
245
$
34
$
(18
)
$
339
(A)
Changes at Power primarily relate to changes in SFAS 133 unrealized gains and losses on derivative contracts that qualify for hedge accounting in 2007 and 2006, combined with unrealized gains in the
NDT Fund in 2006. (B) Changes at Energy Holdings primarily relate to foreign currency translation adjustments in 2007 and 2006 and unrealized gains on derivative contracts in 2006. (C) Other primarily consists of activity at PSEG (as parent company), Services and intercompany eliminations. Note 8. Changes in Capitalization PSEG On April 13, 2007, PSEG called for redemption on May 15, 2007, the outstanding $375 million of its Floating Rate Notes Due 2008 at 100% of the principal amount. For the quarter ended March 31, 2007, PSEG issued 393,355 shares of its common stock in connection with settling stock options for approximately $29 million. For the quarter ended March 31, 2007, PSEG issued approximately 204,068 shares of its common stock under its Dividend Reinvestment Program and its Employee Stock Purchase Program for
approximately $17 million. PSE&G On January 2, 2007, PSE&G repaid at maturity $113 million of its 6.25% Series WW First and Refunding Mortgage Bonds. For the quarter ended March 31, 2007, Transition Funding repaid approximately $38 million of its transition bonds. 34
(UNAUDITED)
Holdings(B)
Total
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS Power In March 2007, Power paid a cash dividend to PSEG of $125 million. Energy Holdings In March 2007, Energy Holdings made a cash distribution to PSEG of $145 million in the form of a return of capital. During the first three months of 2007, Energy Holdings’ subsidiaries repaid approximately $16 million of non-recourse debt, including $14 million by Global, primarily related to the Texas generation
facilities, $1 million by Resources and $1 million by EGDC. Note 9. Other Income and Deductions
PSE&G
Power
Energy
Other(A)
Consolidated
(Millions) Other Income: For the Quarter Ended March 31, 2007: Interest and Dividend Income
$
3
$
5
$
3
$
—
$
11 NDT Fund Realized Gains
—
34
—
—
34 NDT Interest and Dividend Income
—
12
—
—
12 Change in Derivative Fair Value
—
—
1
—
1 Arbitration Award (Konya-Ilgin)
—
—
9
—
9 Other
2
—
3
—
5 Total Other Income
$
5
$
51
$
16
$
—
$
72 For the Quarter Ended March 31, 2006: Interest and Dividend Income
$
3
$
4
$
2
$
(2
)
$
7 NDT Fund Realized Gains
—
27
—
—
27 NDT Interest and Dividend Income
—
10
—
—
10 Foreign Currency Gains
—
—
3
—
3 Change in Derivative Fair Value
—
—
1
—
1 Other
1
—
1
—
2 Total Other Income
$
4
$
41
$
7
$
(2
)
$
50
PSE&G
Power
Energy
Other(A)
Consolidated
(Millions) Other Deductions: For the Quarter Ended March 31, 2007: Donations
$
1
$
—
$
—
$
5
$
6 NDT Fund Realized Losses and Expenses
—
17
—
—
17 Foreign Currency Losses
—
—
1
—
1 Loss on Disposition of Assets
—
1
—
—
1 Other-Than-Temporary Impairment of Investments
—
10
—
—
10 Other
—
1
1
—
2 Total Other Deductions
$
1
$
29
$
2
$
5
$
37 For the Quarter Ended March 31, 2006: Donations
$
1
$
—
$
—
$
—
$
1 NDT Fund Realized Losses and Expenses
—
19
—
—
19 Foreign Currency Losses
—
—
2
—
2 Change in Derivative Fair Value
—
—
2
—
2 Other
—
—
3
—
3 Total Other Deductions
$
1
$
19
$
7
$
—
$
27
(A)
Other consists of reclassifications for minority interests in PSEG’s consolidated results of operations and intercompany eliminations at PSEG (as parent company).
35
(UNAUDITED)
Holdings
Total
Holdings
Total
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) Note 10. 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. 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.
Pension Benefits
OPEB
Quarters Ended
Quarters Ended
2007
2006
2007
2006
(Millions) Components of Net Periodic Benefit Costs: Service Cost
$
21
$
21
$
4
$
5 Interest Cost
54
53
18
17 Expected Return on Plan Assets
(72
)
(67
)
(4
)
(3
) Amortization of Net Transition Obligation
—
—
7
7 Prior Service Cost
3
3
3
3 Loss
5
13
2
2 Net Periodic Benefit Cost
11
23
30
31 Effect of Regulatory Asset
—
—
5
5 Total Benefit Costs
$
11
$
23
$
35
$
36 PSE&G, Power, Energy Holdings and Services Pension costs and OPEB costs for PSE&G, Power, Energy Holdings and Services are detailed as follows:
Pension Benefits
OPEB
Quarters Ended
Quarters Ended
2007
2006
2007
2006
(Millions) PSE&G
$
5
$
12
$
30
$
30 Power
3
7
4
4 Energy Holdings
—
—
—
— Services
3
4
1
2 Total PSEG Consolidated Benefit Costs
$
11
$
23
$
35
$
36 36
March 31,
March 31,
March 31,
March 31,
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) An analysis of the tax provision expense is as follows:
PSE&G
Power
Energy
Other (A)
Consolidated
(Millions) For the Quarter Ended March 31, 2007: Income (Loss) Before Income Taxes
$
231
$
374
$
23
$
(31
)
$
597 Tax Computed at the Statutory Rate
$
81
$
131
$
8
$
(11
)
$
209 Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments: State Income Taxes after Federal Benefit
16
23
(1
)
(1
)
37 Rate Differential of Foreign Operations
—
—
9
—
9 Reserve for Tax Contingencies
—
1
5
—
6 Other
2
—
(1
)
—
1 Total Income Tax Expense (Benefit)
$
99
$
155
$
20
$
(12
)
$
262 Effective Income Tax Rate
42.9
%
41.4
%
87.0
%(B)
38.7
%
43.9
% For the Quarter Ended March 31, 2006: Income (Loss) Before Income Taxes
$
143
$
207
$
40
$
(33
)
$
357 Tax Computed at the Statutory Rate
$
50
$
73
$
14
$
(12
)
$
125 Increase (Decrease) Attributable to Flow Through of Certain Tax Adjustments: State Income Taxes after Federal Benefit
11
11
(2
)
(2
)
18 Plant Related Items
3
—
—
—
3 Other
1
2
—
—
3 Total Income Tax Expense (Benefit)
$
65
$
86
$
12
$
(14
)
$
149 Effective Income Tax Rate
45.5
%
41.5
%
30.0
%
42.4
%
41.7
%
(A)
PSEG’s other activities include amounts applicable to PSEG (as parent corporation) that primarily relate to financing and certain administrative and general costs. (B) Reflects interim period distortion due to asset sales and other one-time adjustments. 37
Holdings
Total
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) PSEG, PSE&G, Power and Energy Holdings adopted FIN 48 effective January 1, 2007, which prescribes a model for how a company should recognize, measure, present and disclose in its financial
statements uncertain tax positions that it has taken or expects to take on a tax return. For additional information, see Note 2. Recent Accounting Standards. Upon adoption, PSEG, PSE&G, Power and
Energy Holdings recorded the following amounts related to their respective uncertain tax positions:
PSE&G
Power
Energy
Other(B)
Consolidated Unrecognized Tax Benefits(A)
$
49
$
21
$
408
$
1
$
479 Accumulated Deferred Income Taxes associated with Unrecognized Tax Benefits
(9
)
(7
)
(246
)
—
(262
) Regulatory Asset-Unrecognized Tax Benefits
(11
)
—
—
—
(11
) Unrecognized Tax Benefits that, if recognized, would impact the effective tax rate(A)
$
29
$
14
$
162
$
1
$
206 Interest and Penalties Accrued
$
5
$
3
$
81
$
—
$
89
(A)
Includes interest and penalties (B) PSEG’s other activities include amounts applicable to PSEG (as parent corporation) that primarily relate to financing and certain administrative and general costs. There were no material changes to the amounts above during the quarter ended March 31, 2007 and no significant increases or decreases in unrecognized tax benefits are reasonably possible to occur
within the next 12 months. PSEG, PSE&G, Power and Energy Holdings include all accrued interest and penalties, required to be recorded under FIN 48, as income tax expense. Income tax years for PSEG, PSE&G, Power and Energy Holdings that remain subject to examination by material jurisdictions, where an examination has not already concluded, are as follows:
PSE&G
Power
Energy
Consolidated United States Federal
2001-2006
2001-2006
2001-2006
2001-2006 New Jersey
2001-2006
N/A
1997-2006
1997-2006 Pennsylvania
2003-2006
N/A
2003-2006
2003-2006 Connecticut
N/A
N/A
N/A
2003-2006 Texas
N/A
N/A
2006
2006 California
N/A
N/A
2002-2006
2002-2006 Indiana
N/A
N/A
N/A
2003-2006 Ohio
N/A
N/A
N/A
2003-2005 Foreign Chile
N/A
N/A
2004-2006
2004-2006 Peru
N/A
N/A
2002-2006
2002-2006 38
Holdings
Total
Holdings
Total
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) Note 12. Financial Information by Business Segments Information related to the segments of PSEG and its subsidiaries is detailed below:
PSE&G
Power
Energy Holdings
Other(B)
Consolidated
Resources
Global
Other(A)
(Millions) For the Quarter Ended March 31, 2007: Total Operating Revenues
$
2,486
$
2,149
$
44
$
208
$
2
$
(1,275
)
$
3,614 Income (Loss) From Continuing Operations
132
219
17
(13
)
(1
)
(19
)
335 Loss from Discontinued Operations, net of tax
—
(6
)
—
—
—
—
(6
) Net Income (Loss)
132
213
17
(13
)
(1
)
(19
)
329 Preferred Securities Dividends
(1
)
—
—
—
—
1
— Segment Earnings (Loss)
131
213
17
(13
)
(1
)
(18
)
329 Gross Additions to Long-Lived Assets
130
126
—
16
—
3
275 As of March 31, 2007: Total Assets
$
14,524
$
8,128
$
2,904
$
3,004
$
97
$
(295
)
$
28,362 Investments in Equity Method Subsidiaries
$
—
$
16
$
8
$
786
$
—
$
—
$
810 For the Quarter Ended March 31, 2006: Total Operating Revenues
$
2,293
$
1,967
$
47
$
263
$
2
$
(1,111
)
$
3,461 Income (Loss) From Continuing Operations
78
121
20
9
(1
)
(19
)
208 Income (Loss) from Discontinued Operations, net of tax
—
(9
)
—
4
—
—
(5
) Net Income (Loss)
78
112
20
13
(1
)
(19
)
203 Preferred Securities Dividends
(1
)
—
—
—
—
1
— Segment Earnings (Loss)
77
112
20
13
(1
)
(18
)
203 Gross Additions to Long-Lived Assets
108
118
—
13
1
—
240 As of December 31, 2006: Total Assets
$
14,553
$
8,146
$
2,969
$
3,095
$
100
$
(293
)
$
28,570 Investments in Equity Method Subsidiaries
$
—
$
16
$
5
$
817
$
—
$
—
$
838
(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. (B) PSEG’s other activities include amounts applicable to PSEG (as parent corporation), 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 corporation. 39
Total
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) Note 13. Related-Party Transactions The majority of the following discussion relates to intercompany transactions. These transactions were recognized on each company’s stand-alone financial statements and were eliminated during the
consolidation process in accordance with GAAP when preparing PSEG’s Condensed Consolidated Financial Statements. 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 2012
and year-to-year thereafter. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process. The amounts which Power charged to PSE&G for BGS and BGSS are presented below:
Power’s Billings for
2007
2006
(Millions) BGS
$
218
$
101 BGSS
$
1,049
$
1,003 As of March 31, 2007 and December 31, 2006, Power had net receivables from PSE&G of approximately $379 million and $370 million, respectively, primarily related to the BGS and BGSS contracts. In
addition, as of March 31, 2007 and December 31, 2006, PSE&G had a payable to Power of approximately $5 million and $174 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:
Services’ Billings for the
Payable to Services as of
March 31,
December 31,
2007
2006
(Millions) PSE&G
$
49
$
55
$
32
$
41 Power
$
33
$
37
$
18
$
21 Energy Holdings
$
5
$
5
$
2
$
2 PSE&G, Power and Energy Holdings believe that the costs of services provided by Services approximate market value for such services. 40
the Quarters Ended
March 31,
Quarters Ended
March 31,
2007
2006
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) 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:
(Payable to) Receivable
March 31,
December 31,
(Millions) PSE&G
$
(89
)
$
(63
) Power
$
(122
)
$
(28
) Energy Holdings
$
30
$
(10
) As a result of the adoption of FIN 48, PSE&G, Power and Energy Holdings each recorded payables to PSEG related to uncertain tax positions. See Note 2. Recent Accounting Standards. Such amounts
as of March 31, 2007 were as follows:
Payable to PSEG
(Millions) PSE&G
$
51 Power
$
22 Energy Holdings
$
424 Affiliate Loans and Advances PSEG and Power As of March 31, 2007, Power had a demand note receivable of $525 million due from PSEG. As of December 31, 2006, Power had a demand note payable to PSEG of approximately $54 million for
short-term funding needs. PSEG and Energy Holdings As of March 31, 2007 and December 31, 2006, Energy Holdings had a demand note receivable due from PSEG of $25 million and $28 million, respectively. These notes reflect the investment of Energy
Holdings’ excess cash with PSEG. PSE&G and Services As of each of March 31, 2007 and December 31, 2006, 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 March 31, 2007 and December 31, 2006, 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. 41
from PSEG as of
2007
2006
as of
March 31,
2007
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) Other PSEG and PSE&G As of March 31, 2007 and December 31, 2006, PSE&G had net receivables from PSEG of approximately $2 million and $3 million, respectively, related to amounts that PSEG had collected on PSE&G’s
behalf. PSEG and Power As of March 31, 2007 and December 31, 2006, Power had net receivables from PSEG of approximately $6 million and $1 million, respectively, related to amounts that PSEG had collected on Power’s
behalf. PSEG and Energy Holdings As of March 31, 2007, Energy Holdings had net receivables from PSEG of approximately $2 million, primarily for interest due on the demand note receivable from PSEG. Energy Holdings and PSE&G As of each of March 31, 2007 and December 31, 2006, Energy Holdings had a receivable of approximately $1 million related to efficiency incentive initiatives performed for PSE&G’s customers. Energy
Holdings recorded revenues for such services of approximately $1 million and $4 million for the quarters ended March 31, 2007 and 2006, respectively. 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.
Power
Guarantor
Other
Consolidating
Consolidated
(Millions) For the Quarter Ended March 31, 2007: Operating Revenues
$
—
$
2,401
$
27
$
(279
)
$
2,149 Operating Expenses
—
2,014
24
(278
)
1,760 Operating Income
—
387
3
(1
)
389 Equity Earnings (Losses) of Subsidiaries
217
(12
)
—
(205
)
— Other Income
49
66
—
(64
)
51 Other Deductions
—
(29
)
—
—
(29
) Interest Expense
(54
)
(35
)
(11
)
63
(37
) Income Taxes
1
(160
)
3
1
(155
) Loss from Discontinued Operations, net of tax
—
—
(6
)
—
(6
) Net Income (Loss)
$
213
$
217
$
(11
)
$
(206
)
$
213 For the Quarter Ended March 31, 2007: Net Cash Provided By (Used In) Operating Activities
$
61
$
801
$
(17
)
$
(21
)
$
824 Net Cash Provided By (Used In) Investing Activities
$
64
$
114
$
(14
)
$
(815
)
$
(651
) Net Cash (Used In) Provided By Financing Activities
$
(125
)
$
(921
)
$
31
$
836
$
(179
) 42
Subsidiaries
Subsidiaries
Adjustments
Total
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Power
Guarantor
Other
Consolidating
Consolidated
(Millions) For the Quarter Ended March 31, 2006: Operating Revenues
$
—
$
2,194
$
33
$
(260
)
$
1,967 Operating Expenses
—
1,977
33
(260
)
1,750 Operating Income
—
217
—
—
217 Equity Earnings (Losses) of Subsidiaries
113
(11
)
—
(102
)
— Other Income
40
45
—
(44
)
41 Other Deductions
—
(19
)
—
—
(19
) Interest Expense
(43
)
(14
)
(19
)
44
(32
) Income Taxes
2
(95
)
7
—
(86
) Loss from Discontinued Operations, net of tax
—
—
(9
)
—
(9
) Net Income (Loss)
$
112
$
123
$
(21
)
$
(102
)
$
112 For the Quarter Ended March 31, 2006: Net Cash Provided By (Used In) Operating Activities
$
810
$
(605
)
$
(3
)
$
480
$
682 Net Cash (Used In) Provided By Investing Activities
$
(810
)
$
588
$
3
$
(264
)
$
(483
) Net Cash Provided By (Used In) Financing Activities
$
—
$
13
$
—
$
(215
)
$
(202
) As of March 31, 2007: Current Assets
$
2,830
$
2,817
$
545
$
(3,877
)
$
2,315 Property, Plant and Equipment, net
150
3,261
862
—
4,273 Investment in Subsidiaries
3,396
189
—
(3,585
)
— Noncurrent Assets
180
1,581
73
(294
)
1,540 Total Assets
$
6,556
$
7,848
$
1,480
$
(7,756
)
$
8,128 Current Liabilities
$
118
$
3,656
$
1,280
$
(3,878
)
$
1,176 Noncurrent Liabilities
277
796
11
(293
)
791 Long-Term Debt
2,818
—
—
—
2,818 Member’s Equity
3,343
3,396
189
(3,585
)
3,343 Total Liabilities and Member’s Equity
$
6,556
$
7,848
$
1,480
$
(7,756
)
$
8,128 As of December 31, 2006: Current Assets
$
1,982
$
3,416
$
531
$
(3,441
)
$
2,488 Property, Plant and Equipment, net
150
3,226
854
—
4,230 Investment in Subsidiaries
4,287
201
—
(4,488
)
— Noncurrent Assets
173
1,398
79
(222
)
1,428 Total Assets
$
6,592
$
8,241
$
1,464
$
(8,151
)
$
8,146 Current Liabilities
$
97
$
3,179
$
1,251
$
(3,443
)
$
1,084 Noncurrent Liabilities
253
776
12
(220
)
821 Long-Term Debt
2,818
—
—
—
2,818 Member’s Equity
3,424
4,286
201
(4,488
)
3,423 Total Liabilities and Member’s Equity
$
6,592
$
8,241
$
1,464
$
(8,151
)
$
8,146 43
Subsidiaries
Subsidiaries
Adjustments
Total
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 2006 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 other representations whatsoever as to any other company. OVERVIEW OF 2007 AND FUTURE OUTLOOK PSEG, PSE&G, Power and Energy Holdings 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 discussion relates to the markets in which PSEG’s subsidiaries compete, the corporate strategy for the conduct of PSEG’s businesses within these markets, significant events that
have occurred during the first quarter of 2007 and future outlook for PSE&G, Power and Energy Holdings, as well as the key factors that will drive the future performance of these businesses. 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, the earnings of PSE&G are largely determined by the regulation of its rates by those agencies. On November 9, 2006, PSE&G reached settlement agreements in the Gas Base Rate Case and
Electric Distribution Financial Review, which were approved by the BPU. The settlement in the Gas Base Rate Case provides for an annual increase in gas revenues of $40 million, 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. The electric settlement authorizes a reduction in the former excess depreciation rate credit to $22 million, resulting in additional revenue to PSE&G of approximately $47
million annually based on current sales volumes. Overview and Future Outlook In February 2007, the BPU approved the results of New Jersey’s annual Basic Generation Service (BGS)-Fixed Price (FP) and BGS-Commercial and Industrial Energy Price (CIEP) auctions and PSE&G
successfully secured contracts to provide the electricity requirements for the majority of its customers’ needs. PSE&G believes that the decisions in November 2006 for both gas and electric base rates position it to earn reasonable returns on investment in the future. The full year impact of these decisions
combined with an anticipated return to more normal weather conditions is expected to improve PSE&G’s margins for 2007 and beyond. 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. 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. FERC’s recent ruling regarding PJM transmission rate design is also
expected to have a positive impact as PSE&G’s current transmission rate structure will remain in place. Since PSE&G earns no margin on the 44
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 in the Northeast and Mid Atlantic U.S. 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 produce low-cost
energy through efficient operations of its nuclear, coal and gas-fired generation facilities, balance its generation production, fuel requirements and supply obligations through energy portfolio management
and pursue disciplined growth. 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 Basic Gas Supply Service
(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. In recent years, the prices at which
transactions are entered into for future delivery of these products, as evidenced through the market for forward contracts at points such as PJM Interconnection, L.L.C. (PJM) West, have escalated
considerably over historical prices. Broad market price increases such as these are expected to have a positive effect on Power’s results. Historically, Power’s nuclear and coal-fired facilities have produced
over 50% and 25% of Power’s production, respectively. With the vast majority of its power sourced from these lower-cost units, the rise in electric prices is anticipated to yield higher near-term margins for
Power. Over a longer-term horizon, if these higher prices are sustained at levels reflective of what the current forward markets indicate, it would yield an attractive environment for Power to contract the
sale of its anticipated output, allowing for potentially sustained higher profitability than recognized in prior years. These prices also increase the cost of replacement power, thereby placing incremental risk
on the operations of the generating units to produce these products. 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 exposure to market changes as well as provide some protection in the event of
unexpected generation outages. Power seeks to sell a portion of its anticipated low-cost nuclear and coal-fired generation over a multi-year forward horizon, normally over a period of approximately two to three years. By contrast,
Power takes a more opportunistic approach in hedging its anticipated natural gas-fired generation. The generation from these units is less predictable, as these units are generally dispatched only when
aggregate market demand has exceeded the supply provided by lower-cost units. The natural gas-fired units generally provide a lower contribution to the margin of Power than either the nuclear or coal
units. Power will generally purchase natural gas as gas-fired generation is required to supply forward sale commitments. 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, some of Power’s existing
contractual obligations, entered into during lower-priced periods, are anticipated to result 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. Overview and Future Outlook During the first quarter of 2007, Power continued to benefit from strong energy markets and sustained improvement in the performance of its generating facilities. The resulting improvement in margins
allowed Power to make a dividend payment to PSEG of $125 million in March 2007. Going forward, Power expects 45
margin improvements to continue in 2007 as higher prices for its nuclear and coal-fired generation output are realized due to the rolling nature of its forward hedge positions and the expiration of older
power contracts. In PJM, the Reliability Pricing Model (RPM) will provide generators with capacity payments for the reliability provided by their respective facilities. The Forward Capacity Market (FCM) settlement in
NEPOOL provides for similar reliability-based capacity payments. FERC has approved the market changes in each of these markets, with the anticipated start date for RPM set for June 1, 2007 and FCM
transition period having begun on December 1, 2006. Power believes that this redesign in capacity markets will lead to changes in the value of the majority of its generating capacity and could result in
incremental margin of $125 million to $175 million in 2007, with higher increases in future years as the full year impact is realized and existing capacity contracts expire. On April 13, 2007, PJM announced the results of its first base residual auction for the 2007-2008 delivery year. The price for the Eastern Mid Atlantic Area Council (MAAC) zone, received by
generation assets located within this zone, including those of Power, cleared at $197.67/MW-day ($72/kW-yr). The auction clearing price, received by generation assets, including those of Power, located in
PJM but not within Eastern or Southwest MAAC zones was $40.80/MW-day ($15/kW-yr). The capacity price that will be charged to load serving entities for obligations in the Eastern MAAC zone is
$177.51/MW-day ($65/kW-yr). These prices will be in effect for the June 2007 to May 2008 PJM planning year. On a prospective basis, many factors will affect the pricing for capacity in PJM, including but
not limited to, changes in demand, changes in available generating capacity (including retirements, additions, derates, forced outage rates, etc.), transmission capability between zones and market design
criteria used in creating the administratively determined demand curve mechanism. Management cannot predict what pricing will result from future auctions. Power completed the sale of four turbines to a third party in April 2007 and received proceeds of $40 million, which approximates the recorded book value. Power also expects to close on the sale of
the Lawrenceburg facility in the second quarter of 2007, the proceeds of which are expected to support future dividends to PSEG and contribute to reducing PSEG’s debt. PSEG has called for redemption
on May 15, 2007, the outstanding $375 million of its Senior Floating Rate Notes Due 2008. A key factor in Power’s ability to achieve its objectives is its ability 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 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. Power
could also be impacted by a number of market and regulatory events, including but not limited to, the lack of consistent rules in markets outside of PJM, rate-regulated utility ownership of generation and
other regulatory actions favoring non-competitive markets, and regulatory policies favoring the construction of west-to-east rate based transmission that may result in increased imports of western
generation into New Jersey. 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
generation companies, and Resources, which primarily invests in energy-related leveraged leases. Global Global owns investments in power producers and distributors that own and operate electric generation and distribution facilities in select domestic and international markets. Global’s earnings are primarily derived from its investments in the United States, Chile and Peru. Approximately 69% of Global’s investments are in Chile and Peru, with another 23% in the United
States. Other modest-sized investments in Italy, India and Venezuela comprise the remaining 8% of Global’s portfolio. As such, Global’s success will depend on continued strong energy markets in Texas
and the 46
economic and efficient operation of its electric distribution companies in Chile and Peru, including its ability to achieve reasonable rates and meet expected growth in demand. The success of Global’s
foreign investments will also depend on stable political, regulatory and economic policies, including foreign currency exchange rates and interest rates, particularly for Chile and Peru. Energy Holdings continues to review Global’s portfolio, with a focus on optimizing operations at its distribution companies to improve earnings and increase value and will consider opportunistic
monetizations, as appropriate, based on valuations and potential alternate uses of capital. In March 2007, Global announced that it is exploring a potential sale of Electroandes S.A. (Electroandes), its
hydro-electric generation and transmission company in Peru, and would evaluate offers to decide if proceeds from a sale might be better used for other opportunities. Resources Resources primarily has invested in energy-related leveraged leases. Resources is focused on maintaining its current investment portfolio and does not expect to make any new investments. Overview and Future Outlook Energy Holdings expects decreased margins at Global in 2007 primarily relating to the anticipated absence of mark-to-market (MTM) gains at the Texas generation facilities and anticipated
maintenance outages at the Texas generation facilities. Also contributing to the expected decrease at Energy Holdings are higher taxes, the impact of adopting Financial Accounting Standards Board
(FASB) Interpretation No. (FIN) 48, “Accounting for Uncertainty in Income Taxes—an Interpretation of FASB Statement 109” (FIN 48) and related standards and lower earnings due to asset sales. During the first quarter of 2007, Energy Holdings made a cash distribution to PSEG of $145 million in the form of a return of capital. Energy Holdings faces risks related to the tax treatment of uncertain tax positions which will be impacted by new accounting guidance under FIN 48 and FASB Staff Position 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” (FAS 13-2), both of which were effective as of January
1, 2007. Based on its evaluation of this new guidance, Energy Holdings recorded a reduction to opening 2007 Retained Earnings of approximately $160 million. In addition, this new guidance will have an
impact on Energy Holdings’ future earnings, including an anticipated earnings after-tax reduction of $32 million in 2007, which represents the majority of the anticipated impact on PSEG. In addition,
Energy Holdings faces risks related to the resolution of tax audit claims associated with Resources’ leveraged lease transactions. See Note 2. Recent Accounting Standards and Note 5. Commitments and
Contingent Liabilities of the Notes for further discussion. 47
The results for PSEG, PSE&G, Power and Energy Holdings for the quarters ended March 31, 2007 and 2006 are presented below:
Earnings (Losses)
2007
2006 PSE&G
$
132
$
78 Power
219
121 Energy Holdings: Global
(13
)
9 Resources
17
20 Other (A)
(1
)
(1
) Total Energy Holdings
3
28 Other (B)
(19
)
(19
) PSEG Income from Continuing Operations
335
208 Loss from Discontinued Operations (C)
(6
)
(5
) PSEG Net Income
$
329
$
203
(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. (B) Other activities include non-segment amounts of PSEG (as parent company) and intercompany eliminations. Specific amounts include preferred securities dividends for PSE&G in 2007 and 2006, merger
expenses in 2006, interest on certain financing transactions and certain other administrative and general expenses at PSEG (as parent company) in 2007 and 2006. (C) Includes Discontinued Operations of Lawrenceburg in 2007 and 2006 and Skawina and Elcho in 2006. See Note 3. Discontinued Operations, Dispositions and Impairments of the Notes. As shown in the table above, PSEG had Income from Continuing Operations of $335 million, or $1.32 per share for the quarter ended March 31, 2007, as compared to $208 million, or $0.83 per share
for the same quarter in 2006. PSEG’s Net Income for the quarter ended March 31, 2007 was $329 million, or $1.30 per share, as compared to Net Income of $203 million, or $0.81 per share for the first
quarter of 2006. The quarter over quarter changes in PSEG’s Income from Continuing Operations and Net Income primarily relate to changes in Net Income for PSE&G, Power and Energy Holdings,
discussed below. 48
Quarters Ended
March 31,
PSEG
For the Quarters
Increase
%
2007
2006
(Millions) Operating Revenues
$
3,614
$
3,461
$
153
4 Energy Costs
$
2,041
$
2,146
$
(105
)
(5
) Operation and Maintenance
$
610
$
578
$
32
6 Depreciation and Amortization
$
196
$
201
$
(5
)
(2
) Income from Equity Method Investments
$
26
$
33
$
(7
)
(21
) Other Income and Deductions
$
35
$
23
$
12
52 Interest Expense
$
(187
)
$
(193
)
$
(6
)
(3
) Income Tax Expense
$
(262
)
$
(149
)
$
113
76 Loss from Discontinued Operations, net of tax
$
(6
)
$
(5
)
$
1
20 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. PSE&G For the quarter ended March 31, 2007, PSE&G had Net Income of $132 million, an increase of $54 million as compared to the quarter ended March 31, 2006. This increase was primarily due to increased
volumes due to weather and price increases resulting from the electric and gas base rate cases settled in November 2006. For the quarter as compared to the same period in 2006, gas delivery volumes
increased 9% and electric delivery volumes increased 2%. The weather was the primary cause of the increase as degree days increased 14%. The quarter-over-quarter detail for the variances is discussed below:
For the Quarters
Increase
%
2007
2006
(Millions) Operating Revenues
$
2,486
$
2,293
$
193
8 Energy Costs
$
1,665
$
1,574
$
91
6 Operation and Maintenance
$
325
$
301
$
24
8 Depreciation and Amortization
$
145
$
152
$
(7
)
(5
) Other Income and Other Deductions
$
4
$
3
$
1
33 Interest Expense
$
(81
)
$
(85
)
$
(4
)
(5
) Income Tax Expense
$
(99
)
$
(65
)
$
34
52 Operating Revenues PSE&G has three sources of revenue: commodity revenues from the sales of energy to customers and in the 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. PSE&G makes no margin on gas commodity sales as the costs are passed through to customers. The difference between the gas costs paid under the requirements contract for residential customers and
the revenues received from residential customers is deferred and collected from or returned to customers in future periods. Gas commodity prices fluctuate monthly for commercial and industrial 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. PSE&G makes no margin on electric commodity sales as the costs are passed through to customers. PSE&G secures its electric commodity through the annual BGS auction. Electric commodity supply
prices are set based on the results of these auctions for residential and smaller industrial and commercial customers, 49
Ended March 31,
(Decrease)
Ended March 31,
(Decrease)
and are translated into seasonally-adjusted fixed rates. Electric supply for larger industrial and commercial customers is provided at a rate principally based on the hourly PJM real-time energy price.
Customers may obtain their electric supply through either the BGS default electric supply service or through competitive third-party electric suppliers, and the majority of the customers subject to hourly
pricing are currently receiving electric supply from third-party suppliers. Any differences between amounts paid by PSE&G to BGS suppliers for electric commodity, and the amounts of electric commodity
revenue collected from customers is deferred and collected or returned to customers in subsequent months. The $193 million increase for the quarter ended March 31, 2007, as compared to the same period in 2006, was due to increases of $99 million in delivery revenues and $91 million in commodity
revenues, described below and $3 million in other operating revenues, primarily related to appliance service contracts. Commodity The $91 million increase in commodity revenues for the quarter ended March 31, 2007, as compared to 2006, was due to an increase in electric commodity revenues of $120 million offset by a decrease
of $29 million in gas commodity revenues. The increase in electric revenues was primarily due to $129 million in higher BGS and NGC revenues (higher auction prices of $117 million and increased sales of
$12 million) offset by $9 million in lower Non-Utility Generation (NUG) revenues, primarily due to lower volumes. The $29 million decrease in gas revenues was primarily due to $114 million in lower
BGSS prices offset by $85 million in higher volumes due to weather. Delivery The $99 million increase in delivery revenues for the quarter ended March 31, 2007, as compared to 2006, was due to a $69 million increase in gas and a $30 million increase in electric revenues. The gas
increase was due to $27 million in higher volumes primarily due to weather, $19 million due to rate relief effective November 9, 2006 and $18 million due to the Societal Benefits Clause (SBC) rate increases
November 1, 2006 and March 9, 2007. The electric increase was due primarily to $11 million from a rate increase effective November 9, 2006 and $3 million for increased SBC rates, $16 million in higher
volumes and demands primarily due to weather. PSE&G retains no margins from SBC collections as the revenues are offset in operating expenses below. Operating Expenses Energy Costs The $91 million increase for the quarter ended March 31, 2007, as compared to the same period in 2006, was comprised of increases of $121 million in electric costs offset by a decrease of $30 million in
gas costs. The increase in electric costs was primarily caused by a $123 million or 30% increase in prices. The gas decrease is due to $113 million or 3% lower prices offset by $82 million in higher volumes
due to weather. Operation and Maintenance The $24 million increase for the quarter ended March 31, 2007, as compared to the same period in 2006, was due primarily to increased SBC expenses, resulting from rate increases in November 2006
and March 2007. Depreciation and Amortization The $7 million decrease for the quarter ended March 31, 2007, as compared to the same period in 2006, was due primarily to decreases of $9 million due to revised plant depreciation rates and $3
million due to lower cost of removal rates resulting from the November 2006 rate case. This was offset by increases of $3 million due to amortization of regulatory assets and $2 million due to additional
plant in service. Interest Expense The $4 million decrease for the quarter ended March 31, 2007, as compared to the same period in 2006, due primarily to lower amounts of long-term and securitization debt outstanding. 50
Income Taxes The $34 million increase for the quarter ended March 31, 2007, as compared to the same period in 2006, was primarily due to increased taxes of $35 million on higher pre-tax income offset by $1 million
in various tax adjustments. Power For the quarter ended March 31, 2007, Power had Net Income of $213 million, an increase of $101 million as compared to the same period in the prior year. The primary reasons for the increase were
higher prices realized as a result of recontracting combined with higher sales volumes and lower generation costs. Improved margins and higher sales volumes under the BGSS contract due to a colder
winter heating season and fuel pricing in 2007 also contributed to the increase. The quarter-over-quarter detail for the variances is discussed below:
For the Quarters
Increase
%
2007
2006
(Millions) Operating Revenues
$
2,149
$
1,967
$
182
9 Energy Costs
$
1,488
$
1,487
$
1
— Operation and Maintenance
$
238
$
232
$
6
3 Depreciation and Amortization
$
34
$
31
$
3
10 Other Income and Deductions
$
22
$
22
$
—
— Interest Expense
$
(37
)
$
(32
)
$
5
16 Income Tax Expense
$
(155
)
$
(86
)
$
69
80 Loss from Discontinued Operations, net of tax
$
(6
)
$
(9
)
$
(3
)
(33
) Operating Revenues The $182 million increase for the quarter ended March 31, 2007, as compared to the same period in 2006, was due to increases of $94 million in generation revenues and $102 million in gas supply
revenues partially offset by a decrease of $14 million in trading revenues. Generation Generation revenues increased $94 million for the quarter ended March 31, 2007, as compared to the same period in 2006, primarily due to higher revenues of approximately $71 million from higher
prices on BGS fixed-price contracts, partially offset by reduced load being served under the BGS contracts and $24 million from increased sales volumes at the Bethlehem Energy Center. Gas Supply Gas supply revenues increased $102 million for the quarter ended March 31, 2007, as compared to the same period in 2006, principally due to higher sales volumes under the BGSS contract largely due
to colder average temperatures in the 2007 winter heating season. Trading Revenues Trading revenues decreased $14 million for the quarter ended March 31, 2007, as compared to the same period in 2006, due primarily to the absence in 2007 of $15 million of realized gains in 2006 from
sales of excess 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. 51
Ended March 31,
(Decrease)
Energy Costs increased approximately $1 million for the quarter ended March 31, 2007, as compared to the same period in 2006, primarily due to an increase in gas costs of $37 million, reflecting a
higher volume of gas purchased at lower prices to satisfy Power’s BGSS obligations partially offset by a decrease in sales prices charged to other gas distributors for gas and pipeline capacity. Generation
costs decreased $36 million, reflecting lower pool prices and lower load obligations somewhat offset by higher prices and volumes of fossil fuel. Operation and Maintenance Operation and Maintenance expense increased $6 million for the quarter ended March 31, 2007, as compared to the same period in 2006, primarily due to maintenance costs related to projects at
certain fossil stations, mainly Hudson and Mercer. Depreciation and Amortization The $3 million increase for the quarter ended March 31, 2007, as compared to the same period in 2006, was primarily due to the Linden facility being placed into service in May 2006. Other Income and Deductions Other Income and Deductions remained flat for the quarter ended March 31, 2007, as compared to the same period in 2006, as an increase in other income primarily attributable to a $9 million increase
in realized gains, interest and dividend income related to the Nuclear Decommissioning Trust (NDT) Funds was offset principally by a $10 million other-than-temporary impairment of certain NDT Funds
securities. Interest Expense Interest Expense increased $5 million for the quarter ended March 31, 2007, as compared to the same period in 2006, due primarily to lower capitalized interest costs of $15 million in 2007 related to
commencement of operations of the Linden facility in May 2006 partially offset by a reduction in interest expense of $9 million due to the maturity on April 15, 2006 of $500 million of 6.875% Senior Notes. Income Taxes Income Taxes increased $69 million for the quarter ended March 31, 2007, as compared to the same period in 2006, primarily due to higher pre-tax income. Loss from Discontinued Operations, net of tax On December 29, 2006, Power entered into an agreement to sell its Lawrenceburg generation facility for approximately $325 million and recognized an estimated loss on disposal of $208 million, net of
tax, in December 2006, for the initial write-down of its carrying amount of Lawrenceburg to its fair value less cost to sell. The transaction is anticipated to close in the second quarter of 2007. Losses from
Discontinued Operations were $6 million and $9 million the quarters ended March 31, 2007 and 2006, respectively. Energy Holdings For the quarter ended March 31, 2007, Energy Holdings had Net Income of $3 million, a decrease of $29 million as compared to the same period in 2006. The decrease was primarily due to lower
income from the Texas generation facilities due to the recognition of MTM losses of $29 million in 2007 as compared to $6 million in 2006 and a scheduled maintenance outage at the Guadalupe plant, the
adoption of certain accounting pronouncements in 2007 and the absence of equity earnings from Rio Grande Energia (RGE), which was sold in June 2006. Also contributing to the variance was a loss at
Prisma 2000 S.p.A. in 2007 because it was prohibited from conducting operations at the San Marco Facility as a result of legal proceedings regarding alleged violations of the facility’s air permit. In March
2007, the shareholders of Prisma 2000 S.p.A. agreed to change the company name to Bioenergie S.p.A. (Bioenergie). Global anticipates that the facility will resume commercial operations in the summer of
2007. These reductions were partially offset by improved operations at Sociedad Austral de Electricidad S.A. (SAESA), a gain on the sale of the Tracy project and an arbitration award received relating to
the Konya-Ilgin dispute. See Note 5. 52
Commitments and Contingent Liabilities of the Notes for additional information regarding Bioenergie. See Part II. Other Information, Item 1. Legal Proceedings for additional information regarding the
Konya-Ilgin dispute. The quarter-over-quarter detail for the variances is discussed below including the consolidation of Bioenergie in May 2006 and the related effects of the shutdown:
For the Quarters
Increase
%
2007
2006
(Millions) Operating Revenues
$
254
$
312
$
(58
)
(19
) Energy Costs
$
161
$
194
$
(33
)
(17
) Operation and Maintenance
$
53
$
49
$
4
8 Depreciation and Amortization
$
14
$
12
$
2
17 Income from Equity Method Investments
$
26
$
33
$
(7
)
(21
) Other Income and Deductions
$
14
$
—
$
14
N/A Interest Expense
$
(43
)
$
(50
)
$
(7
)
(14
) Income Tax Expense
$
(20
)
$
(12
)
$
8
67 Income from Discontinued Operations, net of tax
$
—
$
4
$
(4
)
(100
) The classification of the results of Global’s investments on Energy Holdings’ Condensed Consolidated Financial Statements is dependent upon Global’s ownership percentage in the underlying
investment which determines whether the investment is consolidated into Energy Holdings’ Condensed Consolidated Financial Statements or if it is accounted for under the equity method of accounting.
Global’s investments in Texas generation facilities, SAESA and Electroandes and Bioenergie are consolidated. As a result, the revenues, expenses, assets and liabilities of those investments are reflected on
Energy Holdings’ Condensed Consolidated Financial Statements. Global’s investments in Chilquinta Energia S.A. (Chilquinta), Luz del Sur S.A.A. (LDS), GWF Power Systems, L.P., GWF Energy LLC,
Kalaeloa Partners, L.P. (Kalaeloa) and several other smaller investments are accounted for under the equity method or cost method of accounting, as appropriate. Therefore, Energy Holdings only records
its share of the net income from these projects as Income from Equity Method Investments on its Condensed Consolidated Statements of Operations. Operating Revenues The $58 million decrease for the quarter ended March 31, 2007, as compared to the same period in 2006, was due to lower revenues at Global of $55 million, which was primarily the net result of
decreased revenues consisting of a $76 million decrease at the Texas generation facilities mainly due to a reduction in average price per MWh and unrealized MTM losses on contracts in 2007 as opposed to
unrealized MTM gains in 2006; and a $3 million decrease at Electroandes due to scheduled maintenance closing of one of its four hydro-electric generating plants. These decreases were partially offset by a
$21 million increase at SAESA due to increased tariff rates and energy sales volume and a $7 million increase due to a gain on sale of Global’s 34.5% interest in Tracy Biomass in January 2007. In addition, there were lower leveraged lease revenues at Resources of $3 million primarily due to the adoption of FIN 48 and FAS 13-2 and decreased Demand Side Management revenue due to
contract expirations, partially offset by a gain on settlement of its investment in a collateralized bond fund. Operating Expenses Energy Costs The $33 million decrease for the quarter ended March 31, 2007, as compared to the same period in 2006, was primarily due to a $49 million decrease at the Texas generation facilities primarily due to
MTM unrealized gains on gas contracts in 2007 as opposed to unrealized MTM losses in 2006, offset by a $16 million increase at SAESA due to higher energy purchase price and volume. Operation and Maintenance The $4 million increase for the quarter ended March 31, 2007, as compared to the same period in 2006, was primarily due to a $7 million increase at the Texas generation facilities due to a scheduled
maintenance 53
Ended March 31,
(Decrease)
outage at the Guadalupe plant and a $2 million increase due to the consolidation of Bioenergie in May 2006, partially offset by a $4 million decrease due to lower corporate assessments. Depreciation and Amortization The $2 million increase for the quarter ended March 31, 2007, as compared to the same period in 2006, was primarily due to the consolidation of Bioenergie in May 2006. Income from Equity Method Investments The $7 million decrease for the quarter ended March 31, 2007, as compared to the same period in 2006, was primarily due to the sale of RGE in June 2006. Other Income and Deductions The $14 million increase for the quarter ended March 31, 2007, as compared to the same period in 2006, was primarily due to a $9 million pre-tax gain in 2007 from the award against the Turkish
Government related to an arbitration proceeding regarding the construction of a power plant in the Konya-Ilgin region of Turkey and a $2 million dividend received from Global’s investment in PPN Power
Generating Company Limited in India. Interest Expense The $7 million decrease for the quarter ended March 31, 2007, as compared to the same period in 2006, was primarily due to a decrease in debt outstanding. Income Taxes The $8 million increase for the quarter ended March 31, 2007, as compared to the same period in 2006, was primarily due to assets sales and the Konya-Ilgin settlement, higher effective tax rate due to
timing and the adoption of FIN 48. Income from Discontinued Operations, net of tax In May 2006, Energy Holdings completed the sale of its interest in two coal-fired plants in Poland, Elcho and Skawina. Income from Discontinued Operations related to Elcho and Skawina for the
quarter ended March 31, 2006 was $4 million net of tax. See Note 3. Discontinued Operations, Dispositions and Impairments 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 quarter ended March 31, 2007, PSEG’s operating cash flow increased by approximately $46 million from $910 million to $956 million, as compared to the same period in 2006, due to changes
from its subsidiaries as discussed below. Excess cash is currently being used to reduce debt and beginning in mid-2008, it is expected that excess cash will be available for new investments and/or
repurchasing shares. PSE&G PSE&G’s operating cash flow decreased approximately $206 million from $267 million to $61 million for the quarter ended March 31, 2007, as compared to the same period in 2006, primarily due to the
change in customer receivables. Billed revenues grew $193 million while collections declined $158 million, largely due 54
to warmer than normal weather conditions in late 2006 and January 2007. Offsetting the increase in customer receivables was a $200 million increase in accounts payable and current liabilities. Power Power’s operating cash flow increased approximately $142 million from $682 million to $824 million for the quarter ended March 31, 2007, as compared to the same period in 2006, primarily due to
higher net income of $101 million, and working capital changes driven by an increase of $349 million in accounts payable due mainly to energy and fuel purchases and a decrease of $77 million in inventories
due to higher gas sendouts partially offset by an increase in customer receivables of $365 million largely attributable to increased revenues. Energy Holdings Energy Holdings’ operating cash flow increased approximately $90 million from $1 million to $91 million for the quarter ended March 31, 2007, as compared to the same period in 2006. The increase
was mainly attributable to higher distributions from equity method investments in Global’s GWF and Hanford projects and Resources’ limited partnerships. Common Stock Dividends Dividend payments on common stock for the quarters ended March 31, 2007 and 2006 were $0.585 and $0.57 per share, respectively, and totaled approximately $148 million and $143 million,
respectively. Future dividends declared will be dependent upon PSEG’s future earnings, cash flows, financial requirements, alternative investment opportunities and other factors. Improved earnings would
cause PSEG’s dividend payout ratio to decline, providing PSEG the flexibility to raise its dividend at a rate higher than its prior dividend increases. On April 17, 2007, PSEG’s Board of Directors approved
a common stock dividend of $0.585 per share for the second quarter of 2007, reflecting an indicated annual dividend rate of $2.34 per share. Short-Term Liquidity PSEG, PSE&G, Power and Energy Holdings As of March 31, 2007, PSEG and its subsidiaries had a total of approximately $3.7 billion of committed credit facilities with approximately $3.3 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. As of March 31, 2007, PSEG
had no loans outstanding under its uncommitted facility and PSE&G had $48 million of loans outstanding under its uncommitted facility. 55
Company
Expiration
Total
Primary
Usage
Available
(Millions) PSEG: 5-year Credit Facility
Dec 2011
$
1,000
CP Support/Funding/
$
1
(C)
$
999 Uncommitted Bilateral Agreement
N/A
N/A
Funding
$
—
$
N/A PSE&G: 5-year Credit Facility
June 2011
$
600
CP Support/Funding/
$
222
$
378 Uncommitted Bilateral Agreement
N/A
N/A
Funding
$
48
$
N/A PSEG and Power: Bilateral Credit Facility(A)
June 2007
$
200
Funding/Letters of
$
10
(C)
$
190 Power: 5-year Credit Facility
Dec 2011
$
1,600
Funding/Letters of
$
20
(C)
$
1,580 Bilateral Credit Facility
March 2010
$
100
Funding/Letters of
Credit
$
26
(C)
$
74 Energy Holdings: 5-year Credit Facility(B)
June 2010
$
150
Funding/Letters of
$
27
(D)
$
123
(A)
PSEG/Power joint and several co-borrower facility. (B) Energy Holdings/Global/Resources joint and several co-borrower facility. (C) These amounts relate to letters of credit outstanding. (D) Includes $19 million relating to letters of credit outstanding. PSEG and PSE&G PSEG and PSE&G believe sufficient liquidity exists to fund their short-term cash needs. Power As of March 31, 2007, Power had loaned $525 million to PSEG in the form of an intercompany loan. During the quarter ending March 31, 2007, Power’s required margin postings for sales contracts entered into in the normal course of business increased slightly. 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. 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. 56
Date
Facility
Purpose
as of
March 31,
2007
Liquidity
as of
March 31,
2007
Letters of Credit
Letters of Credit
Credit
Credit
Credit
Energy Holdings Energy Holdings and its subsidiaries had $65 million in cash, including $6 million invested offshore as of March 31, 2007. In addition, as of March 31, 2007, Energy Holdings had an outstanding demand
loan receivable from PSEG of $25 million. See External Financings—Energy Holdings below for Energy Holdings’ additional use of its excess cash. External Financings PSEG On April 13, 2007, PSEG called for redemption on May 15, 2007 the outstanding $375 million of its Floating Rate Notes Due 2008 at 100% of the principal amount. For the quarter ended March 31, 2007, PSEG issued 393,355 shares of its common stock in connection with settling stock options for approximately $16 million. For the quarter ended March 31, 2007, PSEG issued 204,068 shares of its common stock under its Dividend Reinvestment Program and its Employee Stock Purchase Program for approximately $17
million. PSE&G On January 2, 2007, PSE&G repaid at maturity $113 million of its 6.25% Series WW First and Refunding Mortgage Bonds. For the quarter ended March 31, 2007, PSE&G Transition Funding LLC (Transition Funding) repaid approximately $38 million of its transition bonds. Power In March 2007, Power paid a cash dividend to PSEG of $125 million. Energy Holdings In March 2007, Energy Holdings made a cash distribution to PSEG of $145 million in the form of a return of capital. During the first quarter of 2007, Energy Holdings’ subsidiaries repaid approximately $16 million of non-recourse debt, including $14 million by Global, primarily related to the Texas generation
facilities, $1 million by Resources and $1 million by EGDC. Debt Covenants PSEG, PSE&G, Power and Energy Holdings PSEG’s, PSE&G’s, Power’s and Energy Holdings’ respective credit agreements may 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 financial performance or
liquidity measures. The debt underlying the preferred securities of PSEG, which is presented in Long-Term Debt in accordance with FIN 46 “Consolidation of Variable Interest Entities,” is not included as
debt when calculating these ratios, as provided for in the various credit agreements. Energy Holdings’ credit agreement also contains customary provisions under which the lender could refuse to advance loans in the event of a material adverse change in the borrower’s business or
financial condition. 57
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 not related to collateral postings for commodity/energy contracts and similar instruments) to total capitalization (including preferred securities
outstanding and excluding any impacts for Accumulated Other Comprehensive Income adjustments related to marking energy contracts to market and equity reductions from the funded status of pensions
or benefit plans associated with SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans”) covenant. This covenant requires that such ratio not be more than
70.0%. As of March 31, 2007, PSEG’s ratio of debt to capitalization (as defined above) was 50.7%. 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 such ratio will not be more than 65.0%. As of March 31, 2007, PSE&G’s ratio of long-term debt to total capitalization (as defined above) was 47.5%. 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 March 31, 2007, PSE&G’s Mortgage coverage ratio was 4.8 to 1 and the
Mortgage would permit up to approximately $2.1 billion aggregate principal amount of new Mortgage Bonds to be issued against previous additions and improvements. Power Financial covenants contained in Power’s credit facility include a ratio of debt to total capitalization covenant. 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 such ratio will not exceed 65.0%. As of March 31,
2007, Power’s ratio of debt to total capitalization (as defined above) was 37.5%. Energy Holdings Energy Holdings’ bank 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 March 31, 2007, Energy Holdings’ coverage of this covenant was 3.63. Additionally, the bank revolving credit agreement has a covenant requiring that Energy Holdings maintain a
ratio of net debt (recourse debt offset by funds loaned to PSEG) to EBITDA of less than 5.25. As of March 31, 2007, Energy Holdings’ ratio under this covenant was 2.63. 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. Energy Holdings’ indenture with respect to its senior notes does not permit liens securing indebtedness in excess of 10% of consolidated net tangible assets as calculated under the terms of the
indenture. The terms of Energy Holdings’ Senior Notes allow the holders to demand repayment if a transaction or series of related transactions causes the assets of Resources to be reduced by 20% or more
and as a direct result there is a downgrade of ratings. 58
Credit Ratings PSEG, PSE&G, Power and Energy Holdings The credit ratings of PSEG and its subsidiaries are shown in the table below. 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.
Moody’s (A)
S&P (B)
Fitch (C) PSEG: Outlook
Neg
Neg
Pos Preferred Securities
Baa3
BB+
BBB– Commercial Paper
P2
A3
F2 Senior Unsecured Debt
Baa2
BBB–
BBB PSE&G: Outlook
Neg
Neg
Stable Mortgage Bonds
A3
A–
A Preferred Securities
Baa3
BB+
BBB+ Commercial Paper
P2
A3
F2 Power: Outlook
Stable
Neg
Pos Senior Notes
Baa1
BBB
BBB Energy Holdings: Outlook
Neg
Neg
Neg Senior Notes
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. Other Comprehensive Income PSEG, Power and Energy Holdings For the quarter ended March 31, 2007, PSEG, Power and Energy Holdings had Other Comprehensive Losses of $164 million, $155 million and $9 million, respectively, due primarily to an increase in
the net unrealized losses on derivatives accounted for as hedges in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133) at Power and foreign
currency translation adjustments at Energy Holdings. During the quarter ended March 31, 2007, Power’s Accumulated Other Comprehensive Loss increased from $177 million to $332 million. The primary cause 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 quarter ended March 31, 2007, higher market prices for electricity resulted in additional unrealized
losses on many of those contracts. As of March 31, 2007, Energy Holdings had Accumulated Other Comprehensive Income of $94 million. The primary reason for the decrease, as compared to the Accumulated Other Comprehensive
Income of $103 million as of December 31, 2006, was currency fluctuations at SAESA and Chilquinta Energia S.A. 59
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 materially 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, 2006. PSE&G During the quarter ended March 31, 2007, PSE&G made approximately $130 million of capital expenditures, primarily for reliability of transmission and distribution systems. The $130 million does not
include expenditures for cost of removal, net of salvage, of approximately $8 million, which are included in operating cash flows. Power During the quarter ended March 31, 2007, Power made approximately $123 million of capital expenditures (excluding $3 million for nuclear fuel), primarily related to various projects at Fossil and
Nuclear. Energy Holdings During the quarter ended March 31, 2007, Energy Holdings made approximately $16 million of capital expenditures, primarily related to upgrades and expansions of SAESA’s transmission and
distribution systems and expenditures at Electroandes. PSEG, PSE&G, Power and Energy Holdings For information related to recent accounting matters, see Note 2. Recent Accounting Standards of the Notes. 60
QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK 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. 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,
2006. Commodity Contracts The availability and price of energy commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies,
market rules and other events. As part of its overall risk management strategy to reduce price risk due to 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, Hedging and Trading 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 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 Income/Loss, 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. In addition, Power has non-asset based trading activities. 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. 61
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. Reduced trading activities by Power during 2006 and 2007 have resulted in less trading risk. As of March 31, 2007, trading VaR was less than $1 million. As of December 31, 2006, trading VaR was
immaterial. For the Quarter Ended March 31, 2007
Trading
Non-Trading
(Millions) 95% Confidence Level, One-Day Holding Period, One-Tailed: Period End
$
—
$
28 Average for the Period
$
—
$
37 High
$
1
$
64 Low
$
—
$
26 99% Confidence Level, One-Day Holding Period, Two-Tailed: Period End
$
—
$
44 Average for the Period
$
—
$
58 High
$
1
$
100 Low
$
—
$
41 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. Financial Risk Management Activities 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
ended March 31, 2007. 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. 62
VaR
MTM VaR
Operating Revenues
Normal
Trading
Total
(Millions) MTM Activities: Unrealized MTM Gains (Losses) Changes in Fair Value of Open Position
$
5
$
(2
)
$
3 Realization at Settlement of Contracts
(9
)
1
(8
) Total Change in Unrealized Fair Value
(4
)
(1
)
(5
) Realized Net Settlement of Transactions Subject to MTM
9
(1
)
8 Net MTM Gains
5
(2
)
3 Accrual Activities: Accrual Activities—Revenue, Including Hedge Reclassifications
2,146
—
2,146 Total Operating Revenues
$
2,151
$
(2
)
$
2,149
(A)
Includes derivative contracts that Power enters into to hedge anticipated exposures related to its owned and contracted generation supply, all asset backed transactions (ABT) and hedging activities, but
excludes owned and contracted generation assets.
The following table indicates Power’s energy trading assets and liabilities, as well as Power’s hedging activity related to ABTs and derivative instruments that qualify for hedge accounting under SFAS
133. 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. Energy Contract Net Assets/Liabilities
Normal
Trading
Total
(Millions) MTM Energy Assets Current Assets
$
19
$
24
$
43 Noncurrent Assets
20
4
24 Total MTM Energy Assets
39
28
67 MTM Energy Liabilities Current Liabilities
$
(335
)
$
(34
)
$
(369
) Noncurrent Liabilities
(156
)
(2
)
(158
) Total MTM Energy Liabilities
(491
)
(36
)
(527
) Total MTM Energy Contract Net Liabilities
$
(452
)
$
(8
)
$
(460
) 63
For the Quarter Ended March 31, 2007
Operations and
Hedging(A)
As of March 31, 2007
Operations and
Hedging
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
Maturities within
2007
2008
2009-
Total
(Millions) Trading
$
(10
)
$
2
$
—
$
(8
) Normal Operations and Hedging
(200
)
(252
)
—
(452
) Total Net Unrealized Losses on MTM Contracts
$
(210
)
$
(250
)
$
—
$
(460
) 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 Accumulated Other Comprehensive Loss (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
Accumulated
Portion Expected
(Millions) Commodities
$
(267
)
$
(186
) Interest Rates
(2
)
— Net Cash Flow Hedge Loss Included in Accumulated Other Comprehensive Loss
$
(269
)
$
(186
) Power Credit Risk The following table provides information on Power’s credit exposure, net of collateral, as of March 31, 2007. 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. 64
As of March 31, 2007
2011
As of March 31, 2007
Other
Comprehensive
Loss
to be Reclassified
in next 12 months
Schedule of Credit Risk Exposure on Energy Contracts Net Assets Rating
Current
Securities
Net
Number of
Net Exposure of
(Millions)
(Millions) Investment Grade—External Rating
$
393
$
53
$
393
1
(A)
$
311 Non-Investment Grade—External Rating
—
—
—
—
— Investment Grade—No External Rating
—
—
—
—
— Non-Investment Grade—No External Rating
6
—
6
—
— Total
$
399
$
53
$
399
1
$
311
(A)
Counterparty is PSE&G.
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 March 31, 2007, Power had 121 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 March 31, 2007 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.
There have been no changes in internal control over financial reporting that occurred during the first quarter of 2007 that have materially affected, or are reasonably likely to materially affect, each
registrant’s internal control over financial reporting. 65
As of March 31, 2007
Exposure
Held
as Collateral
Exposure
Counterparties
>10%
Counterparties
>10%
Certain information reported under Item 3 of Part I of the 2006 Annual Report on Form 10-K is updated below. PSE&G Electric Discount and Energy Competition Act (Competition Act) On April 23, 2007, PSE&G and Transition Funding were served with a copy of a purported class action complaint (Complaint) challenging the constitutional validity of certain provisions of New Jersey’s
Competition Act, seeking injunctive relief against continued collection from PSE&G’s electric customers of the transition bond charge (TBC) of PSE&G Transition Funding, as well as recovery of TBC
amounts previously collected. Notice of the filing of the Complaint was also provided to New Jersey’s Attorney General. Under New Jersey law, the Competition Act, enacted in 1999, is
presumed constitutional. Preliminary review indicates the claim is without merit. PSE&G and Transition Funding will vigorously defend the matter. Con Edison 2006 Form 10-K, Page 46. In November 2001, Consolidated Edison Company of New York, Inc. (Con Edison) filed a complaint against PSE&G, PJM and NYISO with FERC asserting a failure to
comply with agreements between PSE&G and Con Edison covering 1,000 MW of transmission. PSE&G denied the allegations set forth in the complaint. An Initial Decision issued by an ALJ in April 2002
upheld PSE&G’s claim in part but also accepted Con Edison’s contentions in part. In December 2002, FERC issued an order modifying the Initial Decision and remanding a number of issues to the ALJ for
additional hearings, including issues related to the development of protocols to implement the findings of the order and regarding Phase II of the complaint. The ALJ issued an Initial Decision on the Phase
II issues in June 2003 and in August 2004, FERC issued its decision on Phase II issues. While those decisions were largely favorable to PSE&G, PSE&G sought rehearing as to certain issues, as did Con Edison.
On April 19, 2007, the FERC rejected the rehearing requests of both Con Edison and PSE&G, while granting PSE&G’s requested clarification that 400 MW of the 1000 MW at issue will have higher priority
over other non-firm transactions only if Con Ed agrees to pay congestion costs. Con Edison may appeal the FERC’s rulings on both Phase I and Phase II issues to the Court of Appeals; thus, it is difficult to
predict the final outcome of this proceeding at this time. The August 2004 order required that PJM, NYISO, Con Edison and PSE&G meet for the purpose of developing operational protocols to implement FERC’s directives. On February 18, 2005, NYISO,
PJM and PSE&G submitted a joint compliance filing pursuant to FERC’s August 2004 decision. FERC approved the joint proposals on May 18, 2005 and they took effect on July 1, 2005. In subsequent filings
to FERC regarding the efficacy of these protocols, Con Edison continued to claim that the obligations under the agreements as interpreted by the FERC’s orders were not being met. In December 30, 2005
and January 19, 2007 filings with FERC, Con Edison claimed to have incurred $111 million in damages, and requested FERC to require refunds of this amount. On April 19, 2007, however, the FERC
issued an order rejecting Con Edison’s claim for a refund. FERC also rejected Con Edison’s request for interim remedies and directed that no further informational filings regarding the protocols would be
required. The April 19, 2007 order remains subject to rehearing. Since Con Edison may seek rehearing of this order, the final outcome of this proceeding cannot be predicted. Energy Holdings Turkey 2006 Form 10-K, Page 47. From 1995 through 2001, Global and its partners expended approximately $12 million towards the construction of a power plant in the Konya-Ilgin region of Turkey. In
2001, Turkey passed legislation that deprived Global of rights and fair and equitable treatment and expropriated Global’s Concession Contract for the power plant project, despite the Turkish Government’s
obligation to compensate Global for its costs under the existing contract and Turkish law. In 2002, Global initiated arbitration before 66
the International Centre for Settlement of International Disputes (ICSID) seeking return of costs, lost profits, interest and attorney fees. ICSID rendered its decision in January 2007 requiring the Turkish
Government to pay Global and its partners a total of approximately $19 million for sunk costs, interest and arbitration fees. After paying deferred legal fees, Global received a net payment of approximately
$9 million pre-tax ($5 million after-tax) in March 2007, for its share of the arbitration award. 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 23. (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. (2) Page 24. (PSE&G) PSE&G’s MGP Remediation Program instituted by NJDEP’s Coal Gasification Facility Sites letter dated March 25, 1988. (3) Page 26. (Power) Power’s Petition for Review filed in the United States Court of Appeals for the District of Columbia Circuit on July 30, 2004 challenging the final rule of the United States
Environmental Protection Agency entitled “National Pollutant Discharge Elimination System—Final Regulations to Establish Requirements for Cooling Water Intake Structures at Phase II
Existing Facilities,” now transferred to and venued in the United States Court of Appeals for the Second Circuit with Docket No. 04-6696-ag. (4) Page 26. (Energy Holdings) Italian government investigation regarding allegations of violations of Bioenergie S.p.A’s air permit for the San Marco facility. (5) Page 30. (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. (6) Page 70. (PSEG, PSE&G and Power) FERC ruling dated April 19, 2007 regarding Schedule 12 cost allocation. Docket No. ER06-1271-003 (7) Page 70. (PSEG, PSE&G and Power) FERC proceeding relating to PJM Long-Term Transmission Rate Design, Docket No. EL05-121-000. (8) Page 73. (PSEG, PSE&G and Power) 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. (9) Page 73. (PSE&G) PSE&G’s BGSS Commodity filing with the BPU on May 28, 2004, Docket No. GR04050390. (10) Page 74. (PSE&G) Remediation Adjustment Clause filing with the BPU on February 13, 2007, Docket No. ER07020104. 67
(1)
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS PSEG PSEG’s Annual Meeting of Stockholders was held on April 17, 2007. Proxies for the meeting were solicited pursuant to Regulation 14A under the Securities Act of 1934. There was no solicitation of
proxies in opposition to management’s nominees as listed in the proxy statement and all of management’s nominees were elected to the Board of Directors. Management’s other proposals were also
approved by the stockholders. Details of the voting are provided below:
Votes For
Votes Withheld Proposal 1: Election of Directors Class I–Term expiring in 2009 Ernest H. Drew
212,423,786
7,644,660 Class II–Terms expiring in 2010 William V. Hickey
216,162,290
3,906,156 Ralph Izzo
215,776,495
4,291,951 Richard J. Swift
215,600,264
4,468,182
Votes For
Votes
Abstentions
Proposal 2: Amendment to the Certificate of Incorporation to increase authorized Common Stock from 500 million shares to 1 billion shares
186,335,586
31,202,536
2,530,302
Proposal 3: Approval of the 2007 Equity Compensation Plan for Outside Directors
156,447,238
23,618,163
3,516,215
Proposal 4: Amendment to the Certificate of Incorporation to eliminate classification of the Board of Directors
202,881,678
13,600,629
3,586,133
Proposal 5: Amendment to the Certificate of Incorporation to eliminate cumulative voting
143,763,143
36,249,473
3,569,098
Proposal 6: Amendment to the Certificate of Incorporation to eliminate preemptive rights
162,440,150
17,772,626
3,368,942
Proposal 7: Ratification of Appointment of Deloitte & Touche LLP as Independent Auditor
215,721,598
2,256,311
2,088,724 68
Against
Certain information reported under the 2006 Annual Report on Form 10-K is updated below. Additionally, certain information is provided for new matters that have arisen subsequent to the filing of
the 2006 Annual Report on Form 10-K. References are to the related pages on the Form 10-K as printed and distributed. Federal Regulation Compliance PSEG, PSE&G, Power and Energy Holdings Reliability Standards 2006 Form 10-K, Page 14. The Energy Policy Act (EP Act) required FERC to empower a single, national Electric Reliability Organization (ERO) to develop and enforce national and regional
reliability standards for the U.S. bulk power system. FERC has designated the North American Electric Reliability Corporation (NERC) as this ERO. NERC has filed with FERC delegation agreements
that would in turn delegate, to a significant degree, the enforcement of such reliability standards to eight regional reliability councils approved by NERC, such as Reliability First. Thus, the relationship
between NERC and the regional reliability councils (responsible for reliability standards compliance within a particular geographic region) is a contractual one. PSE&G’s transmission assets, and most of
Power’s generation assets, are located within the geographic scope of Reliability First, and PSEG’s remaining domestic assets, including the New York, Connecticut, Texas and California generating assets,
are within the scope of other regional reliability councils such as Northeast Power Coordinating Council, Electric Reliability Council of Texas, Inc., and Western Electricity Coordinating Council. After being designated as an ERO, NERC asked FERC to approve a set of proposed mandatory Reliability Standards, many of which mirrored existing, voluntary standards. On March 15, 2007, FERC
issued a Final Rule, which approved 83 of the 107 filed standards; the other 24 standards remain pending. Compliance with these 83 standards (Standards), enforcement of which will largely be delegated to
the regional reliability councils such as Reliability First, is mandatory and sanctions may attach for non-compliance. Pursuant to the EP Act, FERC has the ability to impose penalties of up to $1 million a
day for violations of these Standards. Compliance with these Standards will be required by the commencement of the 2007 summer peak season. These Standards are applicable to transmission owners and
generation owners, and thus PSEG, PSE&G, Power and Energy Holdings (or their subsidiaries) will be obligated to comply with the Standards. PSEG, PSE&G, Power and Energy Holdings are currently
evaluating all of the requirements imposed by the Standards and are preparing to ensure that they will be in compliance by the FERC-required date. It should be noted in this regard that PSE&G’s local
control center (LCC) was the first control center voluntarily audited by NERC in January 2006 with respect to LCC readiness. NERC concluded in this audit that PSE&G has adequate facilities, processes,
plans, procedures, tools, and trained personnel to effectively operate as an LCC within PJM and found no significant operational problems. FERC Standards of Conduct 2006 Form 10-K, Page 15. On January 18, 2007, FERC issued a Notice of Proposed Rulemaking (NOPR), which proposes to make certain changes to its Standards of Conduct applicable to both
electric and natural gas transmission providers. The NOPR was issued in response to a decision by the United States Court of Appeals of the District of Columbia, which vacated FERC’s existing Standards
of Conduct as they applied to natural gas pipelines. The NOPR, however, proposes changes to the Standards of Conduct for both natural gas and electric providers. Some of the proposed changes include
modifying the definition of Energy Affiliate and thereby changing the scope of applicability of the Standards of Conduct, changing the regulations with respect to the permissible tasks of “shared”
employees (employees that may be shared by both the Transmission Provider and the Energy Affiliates) and modifying the information disclosure regulations. PSE&G is currently subject to FERC’s
Standards of Conduct as a Transmission Provider and subsidiaries of Power and Energy Holdings are subject to the Standards of Conduct as Energy Affiliates. PSEG, PSE&G, Power and Energy Holdings
may be impacted by FERC’s proposed changes and therefore filed comments to the NOPR with FERC on March 30, 2007. FERC is expected to issue a Final Rule in this proceeding within the next several
months. The outcome of this proceeding cannot be predicted at this time. 69
Transmission Rates and Cost Allocation PSEG, PSE&G and Power PJM Schedule 12 Cost Allocation for Regional Transmission Expansion Planning (RTEP) Projects 2006 Form 10-K, Page 15. On January 5, 2006, PJM proposed cost allocation recommendations for new transmission projects pursuant to Schedule 6 of its FERC-approved Operating Agreement and
Schedule 12 of its Open Access Transmission Tariff (Tariff). PJM identified the “Responsible Customers” that would be required to pay for certain transmission upgrades approved through PJM’s Regional
Transmission Expansion Planning (RTEP) process and the percentage of the project cost that would be allocated to such Responsible Customers. This was the first filing by PJM pursuant to these new cost
allocation mechanisms and it included (i) large cost allocations to eastern load as a result of proposed construction in the western and southern portions of PJM and (ii) allocations to merchant transmission
projects such as Neptune Regional Transmission System, LLC (“Neptune”). On May 26, 2006, FERC issued an order that accepted and suspended PJM’s cost allocation filing, made the filing effective
subject to refund as of May 30, 2006 and established a hearing and settlement judicial procedure. In addition, on May 4, 2006, PJM made a second RTEP cost allocation filing at FERC, addressing cost allocations to Responsible Customers associated with additional RTEP projects. PSE&G protested
the filing, objecting to, among other things, PJM’s netting of cost impacts within a PJM zone to allocate RTEP costs and PJM’s failure to consider the impact of certain adjustments in determining zonal cost
allocation. 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 RTEP
process. 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. This proceeding was consolidated with the other two PJM cost allocation filings and was then the subject of settlement proceedings before an ALJ.
Settlement discussions terminated in November 2006 and, on November 7, 2006, the proceedings were set for hearing, and were then held in abeyance by FERC pending its issuance of a decision on long-
term transmission rate design. On April 19, 2007, the FERC issued a decision with respect to cost allocation, finding PJM’s current Schedule 12 to be inadequate and directing PJM to re-file a more detailed methodology. FERC also
directed resumption of the hearing regarding the proper cost allocation for RTEP projects and established a separate proceeding to address the allocation of costs for “economic” projects (those not being
built to remedy a reliability criteria violation). The FERC also expanded the scope of the hearing to fully examine PJM’s methodology for allocating costs for reliability projects and to address issues that
PSE&G considers significant, such as “electrically cohesive” areas (i.e. areas of congestion). The expansion of the scope of the hearing will now provide PSE&G an opportunity to present its most significant
arguments on cost allocation. In addition, as a result of the April 19 FERC order on long-term rate design discussed below, cost allocation issues have been minimized to a large extent since Schedule 12 will now only apply to cost
allocations for facilities below the 500 kV voltage threshold. Thus, the 500 kV Loudon line project discussed above, a significant portion of the costs of which were to be borne by PSE&G’s customers, will no
longer be subject to Schedule 12 cost allocation and the costs of the project will now be socialized, resulting in a much smaller cost allocation to PSE&G customers. Because the cost allocation hearing,
however, has not yet commenced, and because the FERC’s order on long-term rate design is subject to rehearing, PSE&G is not able to predict a final outcome regarding RTEP project cost allocations at this
time. PJM Long-Term Transmission Rate Design 2006 Form 10-K, Page 16. On May 31, 2005, FERC issued an order addressing the recovery of costs for transmission upgrades designated through PJM’s RTEP process. Among other matters, FERC’s
order responded to a proposal to continue PJM’s current modified zonal rate design for existing transmission facilities, under which transmission customers pay rates for existing transmission within the
particular transmission zone in which they take service. FERC concluded that the existing rate design may not be just and reasonable and it established a hearing to examine the justness and reasonableness
of continuing PJM’s modified zonal rate design. Certain entities filed proposals with FERC on September 30, 2005 for alternative rate designs for the PJM region. PSE&G, as part of a coalition of potentially
affected PJM transmission 70
owners, filed answering testimony on November 22, 2005 that supported continuation of the zonal rate design in PJM. A hearing was held in April 2006 and on July 13, 2006, a FERC ALJ issued a decision concluding that the existing PJM modified zonal rate design for existing facilities had been shown to be unjust and
unreasonable, and should be replaced with a postage stamp rate design (single “postage stamp” rate paid by all transmission customers in PJM) for such facilities to be effective April 1, 2006. To mitigate
rate impacts, the ALJ 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 were 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. On April 19, 2007, FERC issued an order reversing the ALJ’s decision and finding that there was no basis upon which to conclude that the zonal rate design was unjust and unreasonable. The April 19
order also held that (1) for new facilities at the voltage level of 500 kV or higher, 100% of the costs of these new transmission facilities will be socialized to all PJM customers; (2) for new facilities at a
voltage level below 500 kV, costs will be allocated on a “cost causation” basis through the PJM Schedule 12 (“beneficiary pays”) methodology, the details of which will be examined in a hearing as discussed
under Schedule 12 cost allocation above; and (3) for existing facilities, costs will continue to be allocated using PJM’s current zonal rate design. This rate design order is a positive outcome for PSE&G, which had argued for continuation of the zonal rate design, as PSE&G’s current rate structure will remain in place. The order also minimizes cost
allocation to PSE&G’s customers through socialization of the costs of new 500 kV facilities in PJM. The April 19, 2007 order is subject to rehearing; thus, it is difficult to predict a final outcome of this
proceeding at this time. Market Power 2006 Form 10-K, Page 17. Under FERC regulations, public utilities may sell power at cost-based rates or apply to FERC for authority to sell at market-based rates (MBR). FERC requires that holders
of MBR tariffs file an update, on a triennial basis, demonstrating that they continue to lack market power. On November 30, 2006, PSE&G and ER&T filed their respective triennial updated market power
reports with FERC, which were accepted by FERC on February 28, 2007. PSE&G’s and ER&T’s next market power report is due March 1, 2010. FERC Order 888/890 On May 18, 2006, FERC issued a NOPR seeking comments from the industry on whether reforms are needed to the protections that FERC established in its previously-issued Order 888 to prevent
undue discrimination and preference in the provision of transmission service. These reforms would be reflected in revisions to FERC’s pro forma Open Access Transmission Tariff, which has been
incorporated into the tariffs of Transmission Providers and governs the terms and conditions under which transmission owners must provide transmission service to all eligible customers. On February 16,
2007, FERC issued Final Rule 890 in this proceeding. The Final Rule covers many transmission-related topics and emphasizes the issues of transmission planning and cost allocation associated with the
construction of transmission projects. On March 19, 2007, PSE&G filed a Request for Rehearing and Clarification of the Final Rule, arguing that FERC, among other things, erred in appearing to mandate
Transmission Provider planning for economic transmission projects and in establishing cost allocation principles for these projects. The final outcome of this proceeding and the resulting impact on PSEG,
PSE&G and Power cannot be determined at this time. PJM Strategic Initiative 2006 Form 10-K, Page 20. In the fourth quarter of 2006, PJM launched a “strategic initiative” to more specifically define its role in the evolving wholesale energy markets. As part of this initiative,
PJM sought comments from its members, including PSE&G, on a number of items, including whether PJM should consider splitting its wholesale market operations from its transmission grid operations and
whether PJM should consider changes to its current corporate governance structure. On April 2, 2007, PJM issued a Strategic Report, which has not yet been approved by the PJM Board of Managers,
addressing PJM’s vision 71
for the future on the topics of network services operations, markets administration, market monitoring and governance. In the report, PJM has pulled back from its idea of splitting market and grid
operations but continues to consider whether there is a need to modify aspects of its current market and governance structure, such as by offering new forward products, implementing a smart grid, changing
the structure of its market monitoring program, improving generation dispatch, resolving seams issues with the New York Independent System Operator, and implementing certain governance changes.
PSEG filed comments to the Strategic Report on April 24, 2007 and will actively participate in discussions concerning the scope, impact and implementation of the PJM Strategic Initiative. The final
outcome of this proceeding and the resulting impact on PSEG, PSE&G and Power cannot be determined at this time. Power PJM Reliability Pricing Model (RPM) 2006 Form 10-K, Page 18. 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 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. PSE&G and Power filed comments to the settlement supporting the basic structural elements of the RPM proposal but nonetheless requesting certain modifications which, in their
view, would better promote the adequacy of generation reserves on a cost-effective basis. On December 22, 2006, FERC issued an order approving the September 29 settlement, with certain conditions.
FERC’s approval of this settlement is expected to have a favorable impact on generation facilities located in constrained locational zones. The final revenue impact on Power of the settlement approved in
the December 22, 2006 FERC order could result in incremental margin of $125 million to $175 million in 2007, with higher increases in future years as the full year impact is realized and existing capacity
contracts expire. The April 20, 2006 order remains subject to rehearing requests filed by several parties. Moreover, on January 22, 2007, PSEG as well as other parties to the proceeding filed for rehearing of
the December 22, 2006 order. Given the pending rehearing requests and the likelihood of eventual judicial appeals, PSEG, PSE&G and Power are unable to predict the outcome of this proceeding. On April 13, 2007, PJM announced the results of its first base residual auction for the 2007-2008 delivery year. For additional information, see Item 2. Management’s Discussion and Analysis of
Financial Condition and Results of Operations—Power—Overview and Future Outlook. Transmission Infrastructure PSEG, PSE&G and Power DOE Congestion Study 2006 Form 10-K, Page 19. On August 8, 2006, the DOE issued a National Electric Transmission Congestion Study (Congestion Study), as directed by Congress in the EP Act. This Congestion Study
identified two areas in the U.S. 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 transmission projects to address
congestion in these corridors. On April 26, 2007, the DOE issued a report which proposed the Mid-Atlantic Area National Corridor as a draft corridor designation covering most of PJM and bounded by Ohio in the west and the
Atlantic shoreline in the east. Specifically, it appears that the proposed corridor will encompass all of New Jersey, as well as portions of West Virginia, Pennsylvania, Maryland, Virginia, the District of
Columbia, Delaware, Ohio and New York. This corridor has been proposed in draft form only, and parties will have an opportunity to comment on the designation. Thus, the precise scope and route of the
corridor may change. 72
Public meetings will also be held in May to discuss DOE’s proposal. PSE&G and Power are currently analyzing the potential impacts of the proposed corridor designation upon their respective operations. LDV Complaint Proceeding 2006 Form 10-K, Page 19. On December 30, 2004, Jersey Central Power & Light Company (JCP&L) filed a complaint at FERC against the other four signatories, including PSE&G, to the Lower Delaware
Valley (LDV) Transmission System Agreement, which expires in 2027 and governs the construction of, and investment in, certain 500 kV transmission facilities in New Jersey. In the complaint proceeding,
JCP&L sought to terminate its payment obligations to PSE&G and the other contract signatories—specifically, JCP&L pays PSE&G approximately $2.7 million annually under the LDV Agreement and its related
agreements. In the proceeding, JCP&L also sought to receive credit from PSE&G and the other LDV Agreement parties for transmission facilities previously constructed by JCP&L in New Jersey. A hearing was
conducted in this proceeding in November 2006, and on March 8, 2007, a FERC Administrative Law Judge (ALJ) issued a decision which ruled against JCP&L on all issues presented in the case. Thus,
pursuant to the ALJ decision, JCP&L’s payment obligations have not been terminated or reduced, and JCP&L has received no credit for certain transmission facilities it constructed. JCP&L has appealed the
ALJ’s decision to FERC and thus the final outcome of this proceeding cannot be predicted at this time. State Regulation PSEG, PSE&G, Power and Energy Holdings New Jersey Energy Master Plan 2006 Form 10-K, Page 22. The Governor of New Jersey has recently directed the BPU, in partnership with other New Jersey agencies, to develop an Energy Master Plan (EMP). State law in New
Jersey requires that an EMP 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 EMP, 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 certain 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. In November 2006, PSE&G submitted a number of strategies designed to improve efficiencies in customer use and increase the
level of renewable generation. During January and February 2007, PSE&G has been actively involved in the broad-based constituent working groups created to develop specific strategies to achieve the goals
and objectives. Public meetings on the EMP will continue through the third quarter of 2007, and a final plan is expected 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. On April 19, 2007, PSE&G filed a plan with the BPU designed to spur investment in solar power in New Jersey and meet energy goals under the EMP. Under the plan, PSE&G would invest approximately
$100 million over the next two years to help finance the installation of solar systems throughout its service area. If approved by the BPU, the initiative could begin by the end of 2007 and support 30 MW of
solar power in the following two years, fulfilling approximately 50% of the BPU’s Renewal Portfolio Standard (RPS) requirements in PSE&G’s service area for 2009 and 2010. PSE&G BGSS Filings 2006 Form 10-K, Page 23. The parties to the 2005/2006 BGSS proceeding entered into a Stipulation in which the parties agreed that the BGSS 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. The written Order has been received and the Amendment to the Gas Contract has been executed. PSE&G made its 2006/2007 BGSS filing on May 26, 2006. A Stipulation of the parties was approved by the BPU and resulted in a decrease in annual BGSS revenues of approximately $120 million, which
is 73
approximately a 6% reduction in a typical residential gas customer’s bill. The new BGSS rate became effective on November 9, 2006. The Stipulation did not include any change in the Balancing Charge. The parties entered into a second Stipulation, which addresses the Balancing Charge only. The BPU Staff recommended a lower Balancing Charge than proposed by the Company and received
agreement from Rate Counsel. The parties executed the Stipulation for the lower rate and BPU approval was received on January 17, 2007. A third Stipulation of the parties, which makes both the BGSS Charge and the Balancing Charge final, is in the process of being completed. This Stipulation also contains an increase in the Gas
Reservation Charge which is applicable to gas volumes used for electric generation. It is expected that the BPU will approve this Stipulation. Remediation Adjustment Clause (RAC) Filing 2006 Form 10-K, Page 23. PSE&G is engaged in a program to address potential environmental concerns regarding its former Manufactured Gas Plant (MGP) properties in cooperation with and under
the supervision of NJDEP. The costs of the program are recovered through the Remediation Adjustment Clause (RAC). The RAC addresses costs in annual periods ending July 31st of each year. The
expenditures in each RAC period are recovered over seven years. The costs of the program, including interest, are deferred and amortized as collected in revenues. In February 2007, PSE&G submitted its RAC-13 and RAC-14 filings with the BPU. In these filings, PSE&G seeks an order finding that the $71 million of RAC program costs incurred during the two-year
period, August 1, 2004 through July 31, 2006, are reasonable and are available for recovery. If the costs are approved as filed, the annual requirement for the RAC program will decline from $36 million to
$18 million effective July 1, 2007. The decline is primarily the result of an overcollection over the past two years. Amortization of the program costs is equal to revenues with no impact on Net Income. On April 18, 2007, the BPU transferred the case to the Office of Administrative Law (OAL) for its initial decision. A procedural schedule has been established to start the discovery process. Societal Benefits Clause (SBC) Filing 2006 Form 10-K, Page 24. On August 12, 2005, PSE&G filed a motion with the BPU seeking approval of changes in its electric and gas SBC rates and its electric non-utility generation transition charge
(NTC) rates. For electric customers, the rates proposed were designed to recover approximately $106 million in SBC revenues offset by lower NTC rates of $93 million beginning January 1, 2006. For gas,
the rates proposed were designed to recover approximately $10 million in SBC revenues. In 2006, PSE&G filed updates to its filing, modifying its requested changes to electric SBC/NTC rates and gas SBC
rates. Public hearings were held and settlement discussions resulted in the Administrative Law Judge (ALJ) signing the Initial Decision—Settlement on January 31, 2007. The BPU approved the settlement
March 6, 2007 and new rates became effective March 9, 2007, resulting in an annual increase of approximately $16 million in electric SBC/NTC revenues and $12 million in gas SBC revenues. Gas Purchasing Strategies Audit 2006 Form 10-K, Page 24. In January 2007, the BPU has issued an RFP to solicit bid proposals to engage a contractor to perform an analysis of the gas purchasing practices and hedging strategies of
the four New Jersey gas distribution companies (GDCs), including PSE&G. The primary focus will be to examine and compare the financial and physical hedging policies and practices of each GDC and to
provide recommendations for improvements to these policies and practices. The BPU selected a consulting firm for this project and work is expected to begin in summer 2007. PSE&G cannot predict the
outcome of this process. 74
A listing of exhibits being filed with this document is as follows:
a.
PSEG:
Exhibit 3.1(a):
Certificate of Incorporation of Public Service Enterprise Group Incorporated
Exhibit 3.1(b):
Certificate of Amendment of Certificate of Incorporation of Public Service Enterprise Group Incorporated, effective April 23, 1987.
Exhibit 3.1(c):
Certificate of Amendment of Certificate of Incorporation of Public Service Enterprise Group Incorporated, effective April 20, 2007.
Exhibit 3.2:
By-Laws of Public Service Enterprise Group Incorporated as in effect April 20, 2007
Exhibit 10:
2007 Equity Compensation Plan for Outside Directors
Exhibit 12:
Computation of Ratios of Earnings to Fixed Charges
Exhibit 31:
Certification by Ralph Izzo 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 Ralph Izzo 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 3.3:
By-Laws of Public Service Electric and Gas Company as in effect April 17, 2007
Exhibit 10:
2007 Equity Compensation Plan for Outside Directors
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 Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934
Exhibit 31.3:
Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934
Exhibit 32.2:
Certification by Ralph Izzo Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
Exhibit 32.3:
Certification by Thomas M. O’Flynn 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 Ralph Izzo 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 Ralph Izzo 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 Ralph Izzo 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 Ralph Izzo 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 75
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
By:
/s/ DEREK M. DIRISIO
Derek M. DiRisio Date: May 4, 2007 76
(Registrant)
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
/s/ DEREK M. DIRISIO
Derek M. DiRisio Date: May 4, 2007 77
(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
/s/ DEREK M. DIRISIO
Derek M. DiRisio Date: May 4, 2007 78
(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. Derek M. DiRisio Date: May 4, 2007 79
(Registrant)
By:
/s/ DEREK M. DIRISIO
Vice President and Controller
(Principal Accounting Officer)