UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED March 31, 2011
OR
¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
Commission |
Registrants, State of Incorporation, Address, and Telephone Number |
I.R.S. Employer | ||
001-09120 | PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED | 22-2625848 | ||
(A New Jersey Corporation) | ||||
80 Park Plaza, P.O. Box 1171 | ||||
Newark, New Jersey 07101-1171 | ||||
973 430-7000 | ||||
http://www.pseg.com | ||||
001-34232 | PSEG POWER LLC | 22-3663480 | ||
(A Delaware Limited Liability Company) | ||||
80 Park PlazaT25 | ||||
Newark, New Jersey 07102-4194 | ||||
973 430-7000 | ||||
http://www.pseg.com | ||||
001-00973 | PUBLIC SERVICE ELECTRIC AND GAS COMPANY | 22-1212800 | ||
(A New Jersey Corporation) | ||||
80 Park Plaza, P.O. Box 570 | ||||
Newark, New Jersey 07101-0570 | ||||
973 430-7000 | ||||
http://www.pseg.com |
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 x No ¨
Indicate by check mark whether the registrants have submitted electronically and posted on their corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files).
Public Service Enterprise Group Incorporated | Yes x | No ¨ | ||
PSEG Power LLC | Yes ¨ | No ¨ | ||
Public Service Electric and Gas Company | Yes ¨ | No ¨ |
Indicate by check mark whether each registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of large accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the Exchange Act.
Public Service Enterprise Group Incorporated |
Large accelerated filer x | Accelerated filer ¨ | Non-accelerated filer ¨ | Smaller reporting company ¨ | ||||||
PSEG Power LLC |
Large accelerated filer ¨ | Accelerated filer ¨ | Non-accelerated filer x | Smaller reporting company ¨ | ||||||
Public Service Electric and Gas Company |
Large accelerated filer ¨ | Accelerated filer ¨ | Non-accelerated filer x | Smaller reporting company ¨ |
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 x
As of April 15, 2011, Public Service Enterprise Group Incorporated had outstanding 505,904,733 shares of its sole class of Common Stock, without par value.
As of April 15, 2011, 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 Public Service Electric and Gas Company 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. Each is filing its Quarterly Report on Form 10-Q with the reduced disclosure format authorized by General Instruction H.
ii | ||||||
PART I. FINANCIAL INFORMATION |
||||||
Item 1. |
||||||
1 | ||||||
5 | ||||||
8 | ||||||
12 | ||||||
12 | ||||||
13 | ||||||
13 | ||||||
13 | ||||||
15 | ||||||
17 | ||||||
20 | ||||||
21 | ||||||
32 | ||||||
32 | ||||||
37 | ||||||
43 | ||||||
43 | ||||||
45 | ||||||
46 | ||||||
47 | ||||||
48 | ||||||
50 | ||||||
Item 2. |
Managements Discussion and Analysis of Financial Condition and Results of Operations |
52 | ||||
52 | ||||||
55 | ||||||
61 | ||||||
64 | ||||||
64 | ||||||
Item 3. |
64 | |||||
Item 4. |
65 | |||||
Item 1. |
66 | |||||
Item 1A. |
67 | |||||
Item 2. |
67 | |||||
Item 5. |
67 | |||||
Item 6. |
74 | |||||
75 |
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 managements beliefs as well as assumptions made by and information currently available to management. When used herein, the words anticipate, intend, estimate, believe, expect, plan, should, hypothetical, potential, forecast, project, variations of such words and similar expressions are intended to identify forward-looking statements. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Other factors that could cause actual results to differ materially from those contemplated in any forward-looking statements made by us herein are discussed in Item 1. Financial StatementsNote 8. Commitments and Contingent Liabilities, Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations, and other factors discussed in filings we make with the U.S. Securities and Exchange Commission (SEC). These factors include, but are not limited to:
| adverse changes in energy industry law, policies and regulation, including market structures and a potential shift away from competitive markets toward subsidized market mechanisms, transmission planning and cost allocation rules, including rules regarding how transmission is planned and who is permitted to build transmission going forward, and reliability standards, |
| any inability of our transmission and distribution businesses to obtain adequate and timely rate relief and regulatory approvals from federal and state regulators, |
| changes in federal and state environmental regulations that could increase our costs or limit operations of our generating units, |
| changes in nuclear regulation and/or general developments in the nuclear power industry, including various impacts from any accidents or incidents experienced at our facilities or by others in the industry, that could limit operations of our nuclear generating units, |
| actions or activities at one of our nuclear units located on a multi-unit site that might adversely affect our ability to continue to operate that unit or other units located at the same site, |
| any inability to balance our energy obligations, available supply and trading risks, |
| any deterioration in our credit quality or the credit quality of our counterparties, |
| availability of capital and credit at commercially reasonable terms and conditions and our ability to meet cash needs, |
| any inability to realize anticipated tax benefits or retain tax credits, |
| changes in the cost of, or interruption in the supply of, fuel and other commodities necessary to the operation of our generating units, |
| delays in receipt of necessary permits and approvals for our construction and development activities, |
| delays or unforeseen cost escalations in our construction and development activities, |
| adverse changes in the demand for or price of the capacity and energy that we sell into wholesale electricity markets, |
| increase in competition in energy markets in which we compete, |
| challenges associated with retention of a qualified workforce, |
| adverse performance of our decommissioning and defined benefit plan trust fund investments and changes in discount rates and funding requirements, and |
| changes in technology and customer usage patterns. |
Additional information concerning these factors is set forth in Part II under Item 1A. Risk Factors.
All of the forward-looking statements made in this report are qualified by these cautionary statements and we cannot assure you that the results or developments anticipated by management will be realized, or even if realized, will have the expected consequences to, or effects on, us or our business prospects, financial condition or results of operations. Readers are cautioned not to place undue reliance on these forward-looking statements in making any investment decision. Forward-looking statements made in this report only apply as of the date of this report. While we may elect to update forward-looking statements from time to time, we specifically disclaim any obligation to do so, even if internal estimates change, unless otherwise required by applicable securities laws.
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.
ii
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
(Unaudited)
For The Three Months Ended March 31, |
||||||||
2011 |
2010 |
|||||||
OPERATING REVENUES |
$ | 3,354 | $ | 3,573 | ||||
OPERATING EXPENSES |
||||||||
Energy Costs |
1,563 | 1,688 | ||||||
Operation and Maintenance |
651 | 670 | ||||||
Depreciation and Amortization |
241 | 227 | ||||||
Taxes Other Than Income Taxes |
43 | 42 | ||||||
Total Operating Expenses |
2,498 | 2,627 | ||||||
OPERATING INCOME |
856 | 946 | ||||||
Income from Equity Method Investments |
3 | 3 | ||||||
Other Income |
76 | 43 | ||||||
Other Deductions |
(13 | ) | (16 | ) | ||||
Other-Than-Temporary Impairments |
(4 | ) | (1 | ) | ||||
Interest Expense |
(127 | ) | (116 | ) | ||||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES |
791 | 859 | ||||||
Income Tax (Expense) Benefit |
(329 | ) | (361 | ) | ||||
INCOME FROM CONTINUING OPERATIONS |
462 | 498 | ||||||
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of ($36) and $5, for the periods ended 2011 and 2010, respectively |
64 | (7 | ) | |||||
NET INCOME |
$ | 526 | $ | 491 | ||||
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (THOUSANDS): | ||||||||
BASIC |
505,979 | 505,950 | ||||||
DILUTED |
507,132 | 507,147 | ||||||
EARNINGS PER SHARE: |
||||||||
BASIC |
||||||||
INCOME FROM CONTINUING OPERATIONS |
$ | 0.91 | $ | 0.99 | ||||
NET INCOME |
$ | 1.04 | $ | 0.97 | ||||
DILUTED |
||||||||
INCOME FROM CONTINUING OPERATIONS |
$ | 0.91 | $ | 0.99 | ||||
NET INCOME |
$ | 1.04 | $ | 0.97 | ||||
DIVIDENDS PAID PER SHARE OF COMMON STOCK | $ | 0.3425 | $ | 0.3425 | ||||
See Notes to Condensed Consolidated Financial Statements.
1
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)
March 31, | December 31, | |||||||
2011 |
2010 |
|||||||
ASSETS |
||||||||
CURRENT ASSETS |
||||||||
Cash and Cash Equivalents |
$ | 900 | $ | 280 | ||||
Accounts Receivable, net of allowances of $65 and $68 in 2011 and 2010, respectively |
1,419 | 1,387 | ||||||
Tax Receivable |
248 | 689 | ||||||
Unbilled Revenues |
296 | 400 | ||||||
Fuel |
376 | 666 | ||||||
Materials and Supplies, net |
365 | 359 | ||||||
Prepayments |
102 | 204 | ||||||
Derivative Contracts |
174 | 182 | ||||||
Assets of Discontinued Operations |
293 | 564 | ||||||
Deferred Income Taxes |
80 | 43 | ||||||
Regulatory Assets |
100 | 155 | ||||||
Other |
113 | 122 | ||||||
Total Current Assets |
4,466 | 5,051 | ||||||
PROPERTY, PLANT AND EQUIPMENT |
23,698 | 23,272 | ||||||
Less: Accumulated Depreciation and Amortization |
(7,050 | ) | (6,882 | ) | ||||
Net Property, Plant and Equipment |
16,648 | 16,390 | ||||||
NONCURRENT ASSETS |
||||||||
Regulatory Assets |
3,590 | 3,736 | ||||||
Regulatory Assets of Variable Interest Entities (VIEs) |
1,080 | 1,128 | ||||||
Long-Term Investments |
1,630 | 1,623 | ||||||
Nuclear Decommissioning Trust (NDT) Funds |
1,366 | 1,363 | ||||||
Other Special Funds |
164 | 160 | ||||||
Goodwill |
16 | 16 | ||||||
Other Intangibles |
135 | 136 | ||||||
Derivative Contracts |
50 | 79 | ||||||
Restricted Cash of VIEs |
21 | 21 | ||||||
Other |
204 | 206 | ||||||
Total Noncurrent Assets |
8,256 | 8,468 | ||||||
TOTAL ASSETS |
$ | 29,370 | $ | 29,909 | ||||
See Notes to Condensed Consolidated Financial Statements.
2
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)
March 31, | December 31, | |||||||
2011 |
2010 |
|||||||
LIABILITIES AND CAPITALIZATION | ||||||||
CURRENT LIABILITIES |
||||||||
Long-Term Debt Due Within One Year |
$ | 981 | $ | 915 | ||||
Securitization Debt of VIEs Due Within One Year |
209 | 206 | ||||||
Commercial Paper and Loans |
21 | 64 | ||||||
Accounts Payable |
1,067 | 1,176 | ||||||
Derivative Contracts |
64 | 103 | ||||||
Accrued Interest |
153 | 108 | ||||||
Accrued Taxes |
102 | 49 | ||||||
Clean Energy Program |
211 | 195 | ||||||
Obligation to Return Cash Collateral |
106 | 104 | ||||||
Regulatory Liabilities |
166 | 174 | ||||||
Liabilities of Discontinued Operations |
45 | 72 | ||||||
Other |
358 | 319 | ||||||
Total Current Liabilities |
3,483 | 3,485 | ||||||
NONCURRENT LIABILITIES |
||||||||
Deferred Income Taxes and Investment Tax Credits (ITC) |
5,000 | 5,129 | ||||||
Regulatory Liabilities |
265 | 285 | ||||||
Regulatory Liabilities of VIEs |
9 | 8 | ||||||
Asset Retirement Obligations |
467 | 461 | ||||||
Other Postretirement Benefit (OPEB) Costs |
956 | 967 | ||||||
Accrued Pension Costs |
373 | 788 | ||||||
Clean Energy Program |
174 | 235 | ||||||
Environmental Costs |
659 | 669 | ||||||
Derivative Contracts |
25 | 22 | ||||||
Long-Term Accrued Taxes |
221 | 248 | ||||||
Other |
82 | 152 | ||||||
Total Noncurrent Liabilities |
8,231 | 8,964 | ||||||
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8) |
||||||||
CAPITALIZATION |
||||||||
LONG-TERM DEBT |
||||||||
Long-Term Debt |
6,762 | 6,834 | ||||||
Securitization Debt of VIEs |
890 | 939 | ||||||
Project Level, Non-Recourse Debt |
45 | 46 | ||||||
Total Long-Term Debt |
7,697 | 7,819 | ||||||
STOCKHOLDERS EQUITY |
||||||||
Common Stock, no par, authorized 1,000,000,000 shares; issued, 2011 and 2010533,556,660 shares |
4,813 | 4,807 | ||||||
Treasury Stock, at cost, 201127,651,927 shares; 201027,582,437 shares |
(597 | ) | (593 | ) | ||||
Retained Earnings |
5,928 | 5,575 | ||||||
Accumulated Other Comprehensive Loss |
(187 | ) | (156 | ) | ||||
Total Common Stockholders Equity |
9,957 | 9,633 | ||||||
Noncontrolling Interest |
2 | 8 | ||||||
Total Stockholders Equity |
9,959 | 9,641 | ||||||
Total Capitalization |
17,656 | 17,460 | ||||||
TOTAL LIABILITIES AND CAPITALIZATION |
$ | 29,370 | $ | 29,909 | ||||
See Notes to Condensed Consolidated Financial Statements.
3
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
(Unaudited)
For the Three Months Ended March 31, |
||||||||
2011 |
2010 |
|||||||
CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||
Net Income |
$ | 526 | $ | 491 | ||||
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: |
||||||||
Gain on Disposal of Discontinued Operations |
(81 | ) | 0 | |||||
Depreciation and Amortization |
245 | 232 | ||||||
Amortization of Nuclear Fuel |
39 | 34 | ||||||
Provision for Deferred Income Taxes (Other than Leases) and ITC |
(152 | ) | 41 | |||||
Non-Cash Employee Benefit Plan Costs |
53 | 78 | ||||||
Leveraged Lease Income, Adjusted for Rents Received and Deferred Taxes |
(11 | ) | (114 | ) | ||||
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives |
8 | (112 | ) | |||||
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs |
31 | 8 | ||||||
Over (Under) Recovery of Societal Benefits Charge (SBC) |
23 | 30 | ||||||
Cost of Removal |
(13 | ) | (19 | ) | ||||
Net Realized (Gains) Losses and (Income) Expense from NDT Funds |
(60 | ) | (24 | ) | ||||
Net Change in Tax Receivable |
441 | 0 | ||||||
Net Change in Certain Current Assets and Liabilities |
455 | 727 | ||||||
Employee Benefit Plan Funding and Related Payments |
(446 | ) | (276 | ) | ||||
Other |
(16 | ) | (24 | ) | ||||
Net Cash Provided By (Used In) Operating Activities |
1,042 | 1,072 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||
Additions to Property, Plant and Equipment |
(497 | ) | (427 | ) | ||||
Proceeds from Sale of Discontinued Operations |
351 | 0 | ||||||
Proceeds from the Sale of Capital Leases and Investments |
0 | 106 | ||||||
Proceeds from Sales of Available-for-Sale Securities |
315 | 181 | ||||||
Investments in Available-for-Sale Securities |
(331 | ) | (189 | ) | ||||
Other |
7 | 11 | ||||||
Net Cash Provided By (Used In) Investing Activities |
(155 | ) | (318 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||
Net Change in Commercial Paper and Loans |
(43 | ) | (530 | ) | ||||
Issuance of Long-Term Debt |
0 | 344 | ||||||
Redemption of Long-Term Debt |
0 | (300 | ) | |||||
Repayment of Non-Recourse Debt |
(1 | ) | (1 | ) | ||||
Redemption of Securitization Debt |
(46 | ) | (44 | ) | ||||
Cash Dividends Paid on Common Stock |
(173 | ) | (173 | ) | ||||
Redemption of Preferred Securities |
0 | (80 | ) | |||||
Other |
(4 | ) | (8 | ) | ||||
Net Cash Provided By (Used In) Financing Activities |
(267 | ) | (792 | ) | ||||
Net Increase (Decrease) in Cash and Cash Equivalents |
620 | (38 | ) | |||||
Cash and Cash Equivalents at Beginning of Period |
280 | 350 | ||||||
Cash and Cash Equivalents at End of Period |
$ | 900 | $ | 312 | ||||
Supplemental Disclosure of Cash Flow Information: |
||||||||
Income Taxes Paid (Received) |
$ | 8 | $ | 24 | ||||
Interest Paid, Net of Amounts Capitalized |
$ | 85 | $ | 79 |
See Notes to Condensed Consolidated Financial Statements.
4
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
(Unaudited)
For The Three Months Ended March 31, |
||||||||
2011 |
2010 |
|||||||
OPERATING REVENUES |
$ | 1,967 | $ | 2,196 | ||||
OPERATING EXPENSES |
||||||||
Energy Costs |
1,135 | 1,251 | ||||||
Operation and Maintenance |
277 | 251 | ||||||
Depreciation and Amortization |
54 | 43 | ||||||
Total Operating Expenses |
1,466 | 1,545 | ||||||
OPERATING INCOME |
501 | 651 | ||||||
Other Income |
70 | 39 | ||||||
Other Deductions |
(12 | ) | (14 | ) | ||||
Other-Than-Temporary Impairments |
(2 | ) | (1 | ) | ||||
Interest Expense |
(51 | ) | (40 | ) | ||||
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES |
506 | 635 | ||||||
Income Tax (Expense) Benefit |
(208 | ) | (264 | ) | ||||
INCOME FROM CONTINUING OPERATIONS |
298 | 371 | ||||||
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax (expense) benefit of ($36) and $5 for the periods ended 2011 and 2010, respectively |
64 | (7 | ) | |||||
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED |
$ | 362 | $ | 364 | ||||
See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements.
5
PSEG POWER LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)
March 31, | December 31, | |||||||
2011 |
2010 |
|||||||
ASSETS |
||||||||
CURRENT ASSETS |
||||||||
Cash and Cash Equivalents |
$ | 10 | $ | 11 | ||||
Accounts Receivable |
424 | 511 | ||||||
Accounts ReceivableAffiliated Companies, net |
250 | 782 | ||||||
Short-Term Loan to Affiliate |
1,324 | 398 | ||||||
Fuel |
376 | 666 | ||||||
Materials and Supplies, net |
271 | 269 | ||||||
Derivative Contracts |
156 | 163 | ||||||
Prepayments |
54 | 80 | ||||||
Assets of Discontinued Operations |
293 | 564 | ||||||
Total Current Assets |
3,158 | 3,444 | ||||||
PROPERTY, PLANT AND EQUIPMENT |
8,763 | 8,643 | ||||||
Less: Accumulated Depreciation and Amortization |
(2,394 | ) | (2,301 | ) | ||||
Net Property, Plant and Equipment |
6,369 | 6,342 | ||||||
NONCURRENT ASSETS |
||||||||
Nuclear Decommissioning Trust (NDT) Funds |
1,366 | 1,363 | ||||||
Goodwill |
16 | 16 | ||||||
Other Intangibles |
136 | 130 | ||||||
Other Special Funds |
32 | 32 | ||||||
Derivative Contracts |
32 | 42 | ||||||
Long-Term Accrued Taxes |
16 | 16 | ||||||
Other |
67 | 67 | ||||||
Total Noncurrent Assets |
1,665 | 1,666 | ||||||
TOTAL ASSETS |
$ | 11,192 | $ | 11,452 | ||||
LIABILITIES AND MEMBERS EQUITY |
||||||||
CURRENT LIABILITIES |
||||||||
Long-Term Debt Due Within One Year |
$ | 716 | $ | 650 | ||||
Accounts Payable |
601 | 643 | ||||||
Derivative Contracts |
53 | 91 | ||||||
Deferred Income Taxes |
35 | 64 | ||||||
Accrued Interest |
83 | 40 | ||||||
Liabilities of Discontinued Operations |
45 | 72 | ||||||
Other |
78 | 91 | ||||||
Total Current Liabilities |
1,611 | 1,651 | ||||||
NONCURRENT LIABILITIES |
||||||||
Deferred Income Taxes and Investment Tax Credits (ITC) |
1,018 | 1,146 | ||||||
Asset Retirement Obligations |
245 | 242 | ||||||
Other Postretirement Benefit (OPEB) Costs |
154 | 151 | ||||||
Derivative Contracts |
25 | 22 | ||||||
Accrued Pension Costs |
129 | 253 | ||||||
Environmental Costs |
51 | 51 | ||||||
Other |
38 | 104 | ||||||
Total Noncurrent Liabilities |
1,660 | 1,969 | ||||||
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8) |
||||||||
LONG-TERM DEBT |
||||||||
Total Long-Term Debt |
2,740 | 2,805 | ||||||
MEMBERS EQUITY |
||||||||
Contributed Capital |
2,028 | 2,028 | ||||||
Basis Adjustment |
(986 | ) | (986 | ) | ||||
Retained Earnings |
4,267 | 4,080 | ||||||
Accumulated Other Comprehensive Loss |
(128 | ) | (95 | ) | ||||
Total Members Equity |
5,181 | 5,027 | ||||||
TOTAL LIABILITIES AND MEMBERS EQUITY |
$ | 11,192 | $ | 11,452 | ||||
See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements.
6
PSEG POWER LLC
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
(Unaudited)
For the Three Months Ended March 31, |
||||||||
2011 |
2010 |
|||||||
CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||
Net Income |
$ | 362 | $ | 364 | ||||
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: |
||||||||
Gain on Disposal of Discontinued Operations |
(81 | ) | 0 | |||||
Depreciation and Amortization |
58 | 48 | ||||||
Amortization of Nuclear Fuel |
39 | 34 | ||||||
Provision for Deferred Income Taxes and ITC |
(139 | ) | 38 | |||||
Net Realized and Unrealized (Gains) Losses on Energy Contracts and Other Derivatives |
8 | (112 | ) | |||||
Non-Cash Employee Benefit Plan Costs |
13 | 17 | ||||||
Net Realized (Gains) Losses and (Income) Expense from NDT Funds |
(60 | ) | (24 | ) | ||||
Net Change in Certain Current Assets and Liabilities: |
||||||||
Fuel, Materials and Supplies |
286 | 315 | ||||||
Margin Deposit |
(23 | ) | 54 | |||||
Accounts Receivable |
145 | (21 | ) | |||||
Accounts Payable |
(126 | ) | 5 | |||||
Accounts Receivable/Payable-Affiliated Companies, net |
500 | 295 | ||||||
Accrued Interest Payable |
43 | 37 | ||||||
Other Current Assets and Liabilities |
15 | (29 | ) | |||||
Employee Benefit Plan Funding and Related Payments |
(124 | ) | (78 | ) | ||||
Other |
(13 | ) | 5 | |||||
Net Cash Provided By (Used In) Operating Activities |
903 | 948 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||
Additions to Property, Plant and Equipment |
(155 | ) | (174 | ) | ||||
Proceeds from Sale of Discontinued Operations |
351 | 0 | ||||||
Proceeds from Sales of Available-for-Sale Securities |
315 | 181 | ||||||
Investments in Available-for-Sale Securities |
(331 | ) | (189 | ) | ||||
Short-Term LoanAffiliated Company, net |
(926 | ) | (509 | ) | ||||
Other |
17 | 17 | ||||||
Net Cash Provided By (Used In) Investing Activities |
(729 | ) | (674 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||
Issuance of Recourse Long-Term Debt |
0 | 44 | ||||||
Cash Dividend Paid |
(175 | ) | (175 | ) | ||||
Short-Term LoanAffiliated Company, net |
0 | (194 | ) | |||||
Net Cash Provided By (Used In) Financing Activities |
(175 | ) | (325 | ) | ||||
Net Increase (Decrease) in Cash and Cash Equivalents |
(1 | ) | (51 | ) | ||||
Cash and Cash Equivalents at Beginning of Period |
11 | 64 | ||||||
Cash and Cash Equivalents at End of Period |
$ | 10 | $ | 13 | ||||
Supplemental Disclosure of Cash Flow Information: | ||||||||
Income Taxes Paid (Received) |
$ | 9 | $ | 40 | ||||
Interest Paid, Net of Amounts Capitalized |
$ | 10 | $ | 13 |
See disclosures regarding PSEG Power LLC included in the Notes to Condensed Consolidated Financial Statements.
7
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
(Unaudited)
For The Three Months Ended March 31, |
||||||||
2011 |
2010 |
|||||||
OPERATING REVENUES |
$ | 2,306 | $ | 2,444 | ||||
OPERATING EXPENSES | ||||||||
Energy Costs |
1,366 | 1,540 | ||||||
Operation and Maintenance |
368 | 414 | ||||||
Depreciation and Amortization |
179 | 177 | ||||||
Taxes Other Than Income Taxes |
43 | 42 | ||||||
Total Operating Expenses |
1,956 | 2,173 | ||||||
OPERATING INCOME | 350 | 271 | ||||||
Other Income |
5 | 5 | ||||||
Other Deductions |
(1 | ) | (1 | ) | ||||
Other-Than-Temporary Impairments |
(1 | ) | 0 | |||||
Interest Expense |
(79 | ) | (77 | ) | ||||
INCOME BEFORE INCOME TAXES |
274 | 198 | ||||||
Income Tax (Expense) Benefit |
(111 | ) | (80 | ) | ||||
NET INCOME |
163 | 118 | ||||||
Preferred Stock Dividends |
0 | (1 | ) | |||||
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED |
$ | 163 | $ | 117 | ||||
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.
8
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)
March 31, | December 31, | |||||||
2011 |
2010 |
|||||||
ASSETS |
||||||||
CURRENT ASSETS |
||||||||
Cash and Cash Equivalents |
$ | 28 | $ | 245 | ||||
Accounts Receivable, net of allowances of $65 in 2011 and $67 in 2010, respectively |
983 | 832 | ||||||
Unbilled Revenues |
296 | 400 | ||||||
Materials and Supplies |
93 | 90 | ||||||
Prepayments |
38 | 117 | ||||||
Regulatory Assets |
100 | 155 | ||||||
Other |
30 | 19 | ||||||
Total Current Assets |
1,568 | 1,858 | ||||||
PROPERTY, PLANT AND EQUIPMENT | 14,363 | 14,068 | ||||||
Less: Accumulated Depreciation and Amortization |
(4,393 | ) | (4,326 | ) | ||||
Net Property, Plant and Equipment |
9,970 | 9,742 | ||||||
NONCURRENT ASSETS |
||||||||
Regulatory Assets |
3,590 | 3,736 | ||||||
Regulatory Assets of VIEs |
1,080 | 1,128 | ||||||
Long-Term Investments |
240 | 230 | ||||||
Other Special Funds |
54 | 54 | ||||||
Derivative Contracts |
6 | 17 | ||||||
Restricted Cash of VIEs |
21 | 21 | ||||||
Other |
87 | 87 | ||||||
Total Noncurrent Assets |
5,078 | 5,273 | ||||||
TOTAL ASSETS |
$ | 16,616 | $ | 16,873 | ||||
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.
9
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED BALANCE SHEETS
Millions
(Unaudited)
March 31, | December 31, | |||||||
2011 |
2010 |
|||||||
LIABILITIES AND CAPITALIZATION |
||||||||
CURRENT LIABILITIES |
||||||||
Long-Term Debt Due Within One Year |
$ | 264 | $ | 264 | ||||
Securitization Debt of VIEs Due Within One Year |
209 | 206 | ||||||
Commercial Paper and Loans |
21 | 0 | ||||||
Accounts Payable |
358 | 406 | ||||||
Accounts PayableAffiliated Companies, net |
19 | 85 | ||||||
Accrued Interest |
67 | 65 | ||||||
Clean Energy Program |
211 | 195 | ||||||
Derivative Contracts |
11 | 12 | ||||||
Deferred Income Taxes |
14 | 19 | ||||||
Obligation to Return Cash Collateral |
106 | 104 | ||||||
Regulatory Liabilities |
166 | 174 | ||||||
Other |
316 | 229 | ||||||
Total Current Liabilities |
1,762 | 1,759 | ||||||
NONCURRENT LIABILITIES |
||||||||
Deferred Income Taxes and ITC |
3,134 | 3,127 | ||||||
Other Postretirement Benefit (OPEB) Costs |
755 | 770 | ||||||
Accrued Pension Costs |
128 | 377 | ||||||
Regulatory Liabilities |
265 | 285 | ||||||
Regulatory Liabilities of VIEs |
9 | 8 | ||||||
Clean Energy Program |
174 | 235 | ||||||
Environmental Costs |
608 | 617 | ||||||
Asset Retirement Obligations |
218 | 216 | ||||||
Long-Term Accrued Taxes |
44 | 74 | ||||||
Other |
21 | 23 | ||||||
Total Noncurrent Liabilities |
5,356 | 5,732 | ||||||
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 8) |
||||||||
CAPITALIZATION |
||||||||
LONG-TERM DEBT |
||||||||
Long-Term Debt |
4,020 | 4,019 | ||||||
Securitization Debt of VIEs |
890 | 939 | ||||||
Total Long-Term Debt |
4,910 | 4,958 | ||||||
STOCKHOLDERS EQUITY |
||||||||
Common Stock; 150,000,000 shares authorized; issued and outstanding, 2011 and 2010132,450,344 shares |
892 | 892 | ||||||
Contributed Capital |
420 | 420 | ||||||
Basis Adjustment |
986 | 986 | ||||||
Retained Earnings |
2,289 | 2,126 | ||||||
Accumulated Other Comprehensive Income |
1 | 0 | ||||||
Total Stockholders Equity |
4,588 | 4,424 | ||||||
Total Capitalization |
9,498 | 9,382 | ||||||
TOTAL LIABILITIES AND CAPITALIZATION |
$ | 16,616 | $ | 16,873 | ||||
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.
10
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
(Unaudited)
For The Three Months Ended March 31, |
||||||||
2011 |
2010 |
|||||||
CASH FLOWS FROM OPERATING ACTIVITIES |
||||||||
Net Income |
$ | 163 | $ | 118 | ||||
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: |
||||||||
Depreciation and Amortization |
179 | 177 | ||||||
Provision for Deferred Income Taxes and ITC |
(8 | ) | 4 | |||||
Non-Cash Employee Benefit Plan Costs |
35 | 54 | ||||||
Cost of Removal |
(13 | ) | (19 | ) | ||||
Market Transition Charge (MTC) Refund |
(15 | ) | 0 | |||||
Over (Under) Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs |
31 | 8 | ||||||
Over (Under) Recovery of SBC |
23 | 30 | ||||||
Net Changes in Certain Current Assets and Liabilities: |
||||||||
Accounts Receivable and Unbilled Revenues |
(47 | ) | (98 | ) | ||||
Materials and Supplies |
(3 | ) | (10 | ) | ||||
Prepayments |
79 | 65 | ||||||
Accounts Receivable/Payable-Affiliated Companies, net |
(33 | ) | (77 | ) | ||||
Other Current Assets and Liabilities |
40 | 94 | ||||||
Employee Benefit Plan Funding and Related Payments |
(276 | ) | (168 | ) | ||||
Other |
2 | (18 | ) | |||||
Net Cash Provided By (Used In) Operating Activities |
157 | 160 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES |
||||||||
Additions to Property, Plant and Equipment |
(339 | ) | (217 | ) | ||||
Solar Loan Investments |
(10 | ) | (6 | ) | ||||
Other |
0 | (2 | ) | |||||
Net Cash Provided By (Used In) Investing Activities |
(349 | ) | (225 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES |
||||||||
Net Change in Short-Term Debt |
21 | 0 | ||||||
Issuance of Long-Term Debt |
0 | 300 | ||||||
Redemption of Long-Term Debt |
0 | (300 | ) | |||||
Redemption of Securitization Debt |
(46 | ) | (44 | ) | ||||
Redemption of Preferred Securities |
0 | (80 | ) | |||||
Deferred Issuance Costs |
0 | (4 | ) | |||||
Cash Dividend on Preferred Stock |
0 | (1 | ) | |||||
Net Cash Provided By (Used In) Financing Activities |
(25 | ) | (129 | ) | ||||
Net Increase (Decrease) In Cash and Cash Equivalents |
(217 | ) | (194 | ) | ||||
Cash and Cash Equivalents at Beginning of Period |
245 | 240 | ||||||
Cash and Cash Equivalents at End of Period |
$ | 28 | $ | 46 | ||||
Supplemental Disclosure of Cash Flow Information: |
||||||||
Income Taxes Paid (Received) |
$ | 0 | $ | (3 | ) | |||
Interest Paid, Net of Amounts Capitalized |
$ | 74 | $ | 66 |
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Condensed Consolidated Financial Statements.
11
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
This combined Form 10-Q is separately filed by Public Service Enterprise Group Incorporated (PSEG), PSEG Power LLC (Power) and Public Service Electric and Gas Company (PSE&G). Information relating to any individual company is filed by such company on its own behalf. Power and PSE&G each is only responsible for information about itself and its subsidiaries.
Note 1. Organization and Basis of Presentation
Organization
PSEG is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid Atlantic United States and in other select markets. PSEGs four principal direct wholly owned subsidiaries are:
| Powerwhich 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 functions through three principal direct wholly owned subsidiaries. Powers subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC) and the states in which they operate. |
| PSE&Gwhich is an operating public utility engaged principally in the transmission of electricity and distribution of electricity 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 FERC. Pursuant to applicable BPU orders, PSE&G is also investing in the development of solar generation projects and energy efficiency programs within its service territory. |
| PSEG Energy Holdings L.L.C. (Energy Holdings)which has invested in leveraged leases and owns and operates primarily domestic projects engaged in the generation of energy through its direct wholly owned subsidiaries. Certain Energy Holdings subsidiaries are subject to regulation by FERC and the states in which they operate. Energy Holdings is also investing in solar generation projects and exploring opportunities for other investments in renewable generation. |
| PSEG Services Corporation (Services)which provides management and administrative and general services to PSEG and its subsidiaries. |
Basis of Presentation
The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with accounting principles generally accepted in the United States (GAAP) have been condensed or omitted pursuant to such rules and regulations. These Condensed Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements (Notes) should be read in conjunction with, and update and supplement matters discussed in the Annual Report on Form 10-K for the year ended December 31, 2010.
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, 2010.
In January 2011, Power reached an agreement to sell its two generating facilities located in Texas. As a result, amounts related to these plants have been reclassified as Discontinued Operations in the financial statements. See Note 4. Discontinued Operations and Dispositions for additional information.
12
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Note 2. Recent Accounting Standards
New Standard Adopted during 2011
Revenue Arrangements with Multiple Deliverables
| amends existing guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist, |
| establishes a selling price hierarchy, such as, vendor-specific objective evidence, third-party evidence and estimated selling price for determining the selling price of a deliverable, and |
| provides guidance for allocating and recognizing revenue based on separate deliverables. |
We adopted this standard, prospectively effective January 1, 2011, for new and significantly modified revenue arrangements. Upon adoption, there was no material impact on our financial statements and we do not anticipate any changes to the pattern or general timing of revenue recognition for our significant units of account in future periods.
Note 3. Variable Interest Entities (VIEs)
Variable Interest Entities for which PSE&G is the Primary Beneficiary
PSE&G is the primary beneficiary and consolidates two marginally capitalized VIEs, PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II), which were created for the purpose of issuing transition bonds and purchasing bond transitional property of PSE&G, which is pledged as collateral to the trustee. PSE&G acts as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds are remitted to Transition Funding and Transition Funding II and are used for interest and principal payments on the transition bonds and related costs.
The assets and liabilities of these VIEs are presented separately on the face of the Condensed Consolidated Balance Sheets of PSEG and PSE&G because the Transition Funding and Transition Funding II assets are restricted and can only be used to settle the obligations of Transition Funding and Transition Funding II, respectively. The Transition Funding and Transition Funding II creditors do not have any recourse to the general credit of PSE&G in the event the transition charges are not sufficient to cover the bond principal and interest payments of Transition Funding and Transition Funding II, respectively.
PSE&Gs maximum exposure to loss is equal to its equity investment in these VIEs which was $16 million as of March 31, 2011 and December 31, 2010. The risk of actual loss to PSE&G is considered remote. PSE&G did not provide any financial support to Transition Funding and Transition Funding II during the first quarter of 2011 or in 2010. Further, PSE&G does not have any contractual commitments or obligations to provide financial support to Transition Funding and Transition Funding II.
Note 4. Discontinued Operations and Dispositions
Discontinued Operations
Power
In January 2011, Power reached agreements to sell its two 1,000 MW combined-cycle generating facilities located in Texas. The plants are being sold in two separate transactions aggregating approximately $687 million. The sale of the Guadalupe facility closed in March 2011 for proceeds of $351 million, resulting in an after-tax gain of $53 million. The sale of the Odessa facility is expected to be closed in the second quarter of 2011.
13
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
PSEG Texas operating results for the three months ended March 31, 2011 and 2010, which were reclassified to Discontinued Operations, are summarized below:
Three Months Ended March 31, | ||||||||
2011 |
2010 |
|||||||
Millions | ||||||||
Operating Revenues |
$ | 63 | $ | 107 | ||||
Income (Loss) Before Income Taxes | $ | 18 | $ | (12 | ) | |||
Net Income (Loss) |
$ | 11 | $ | (7 | ) |
The carrying amounts of PSEG Texas assets and liabilities as of March 31, 2011 and December 31, 2010 are summarized in the following table:
As of March 31, |
As of December 31, |
|||||||
2011 |
2010 |
|||||||
Millions | ||||||||
Current Assets |
$ | 12 | $ | 28 | ||||
Noncurrent Assets | 281 | 536 | ||||||
Total Assets of Discontinued Operations |
$ | 293 | $ | 564 | ||||
Current Liabilities | $ | 11 | $ | 28 | ||||
Noncurrent Liabilities |
34 | 44 | ||||||
Total Liabilities of Discontinued Operations |
$ | 45 | $ | 72 | ||||
Dispositions
Leveraged Leases
During the first quarter of 2010, Energy Holdings sold its interest in two leveraged leases, including one international lease for which the IRS has indicated its intention to disallow certain tax deductions taken in prior years.
Three Months Ended March 31, |
||||
2010 |
||||
Millions | ||||
Proceeds from Sales |
$ | 106 | ||
Gain on Sales, after-tax |
$ | 8 |
Proceeds from the sales of the international leases were used to reduce the tax exposure related to these lease investments. For additional information see Note 8. Commitments and Contingent Liabilities.
14
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
PSE&G
PSE&G sponsors a solar loan program designed to help finance the installation of solar power systems throughout our electric service area. The loans are generally paid back with Solar Renewable Energy Certificates (SRECS) generated from the installed solar electric systems. The following table reflects the outstanding short and long-term loans by class of customer, none of which would be considered non-performing.
Credit Risk Profile Based on Payment Activity | As of | As of | ||||||
March 31, | December 31, | |||||||
Consumer Loans |
2011 |
2010 |
||||||
Millions | ||||||||
Performing |
||||||||
Commercial/Industrial |
$ | 71 | $ | 62 | ||||
Residential |
5 | 4 | ||||||
$ | 76 | $ | 66 | |||||
Energy Holdings
Energy Holdings has investments in domestic energy and real estate assets subject to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEGs Condensed Consolidated Balance Sheets. As an equity investor, Energy Holdings investments in the leases are comprised of the total expected lease receivables by Energy Holdings on its equity investments over the lease terms plus the estimated residual values at end of lease term, and are reduced for any income on the leases not yet earned. This amount is included in Long-Term Investments on PSEGs Condensed Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Taxes on PSEGs Condensed Consolidated Balance Sheets. The table below shows Energy Holdings gross and net lease investment as of March 31, 2011 and December 31, 2010, respectively.
As of March 31, |
As of December 31, |
|||||||
2011 |
2010 |
|||||||
Millions | ||||||||
Lease receivables (net of non-recourse debt) |
$ | 893 | $ | 896 | ||||
Estimated residual value of leased assets |
891 | 905 | ||||||
1,784 | 1,801 | |||||||
Unearned and deferred income |
(534 | ) | (546 | ) | ||||
Gross investments in leases |
1,250 | 1,255 | ||||||
Deferred tax liabilities |
(896 | ) | (899 | ) | ||||
Net investments in leases |
$ | 354 | $ | 356 | ||||
15
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The corresponding receivables associated with the lease portfolio are reflected below, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings. Not Rated counterparties relate to investments in leases of commercial real estate properties.
Lease Receivables, Net of Non-Recourse Debt |
||||||||
As of March 31, |
As of December 31, |
|||||||
Counterparties Credit Rating (S&P) |
2011 |
2010 |
||||||
Millions | ||||||||
AAA - AA |
$ | 21 | $ | 21 | ||||
A |
110 | 112 | ||||||
BBB - BB |
316 | 316 | ||||||
B |
300 | 430 | ||||||
CC |
129 | 0 | ||||||
Not Rated |
17 | 17 | ||||||
$ | 893 | $ | 896 | |||||
The B and CC ratings above represent lease receivables underlying coal, gas and oil fired assets in Illinois, New York and Pennsylvania. As of March 31, 2011, the gross investment in the leases of such assets, net of non-recourse debt, was $816 million ($144 million, net of deferred taxes). A more detailed description of such assets under lease is as follows:
Asset |
Location |
Gross |
% |
Total |
Fuel |
Counterparty | ||||||||||||
Powerton Station Units 5 and 6 |
IL | $ | 135 | 64% | 1,538 | Coal | Edison Mission Energy | |||||||||||
Joliet Station Units 7 and 8 |
IL | $ | 84 | 64% | 1,044 | Coal | Edison Mission Energy | |||||||||||
Danskammer Station Units 3 and 4 |
NY | $ | 71 | 100% | 370 | Coal | Dynegy | |||||||||||
Roseton Station Units 1 and 2 |
NY | $ | 199 | 100% | 1,200 | Gas/Oil | Dynegy | |||||||||||
Keystone Station Units 1 and 2 |
PA | $ | 110 | 17% | 1,711 | Coal | GenOn REMA Services LLC | |||||||||||
Conemaugh Station Units 1 and 2 |
PA | $ | 111 | 17% | 1,711 | Coal | GenOn REMA Services LLC | |||||||||||
Shawville Station Units 1, 2, 3 and 4 |
PA | $ | 106 | 100% | 603 | Coal | GenOn REMA Services LLC |
The credit exposure to the lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions. These credit enhancement features vary from lease to lease. Some of the leasing transactions include covenants that restrict the flow of dividends from the lessee to its parent, over-collateralization of the lessee with non-leased assets, historical and forward cash flow coverage tests that prohibit discretionary capital expenditures and dividend payments to the parent/lessee if stated minimum coverage ratios are not met and similar cash flow restrictions if ratings are not maintained at stated levels. These covenants are designed to maintain cash reserves in the transaction entity for the benefit of the non-recourse lenders and the lessor/equity participants in the event of a market downturn or degradation in operating performance of the leased assets. In the event of a default in any of the lease transactions, Energy Holdings would exercise its rights and attempt to seek recovery of its investment. The results of such efforts may not be known for a period of time. A bankruptcy of a lessee and failure to recover adequate value could lead to a foreclosure of the lease. If foreclosures were to occur, Energy Holdings could potentially record a pre-tax write-off up to its gross investment in these facilities and also be required to pay significant cash tax liabilities.
16
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The counterparty with the CC credit rating noted above is Dynegy Inc (Dynegy). In March 2011, S&P downgraded Dynegy from B to CC following Dynegys issuance of its annual report. In that report, Dynegys independent auditors noted in their opinion on the financial statements that there was substantial doubt about Dynegys ability to continue as a going concern.
Although all payments of equity rent, debt service and other fees are current, no assurances can be given that all payments in accordance with the lease contracts will continue. Factors which may impact future lease cash flow include, but are not limited to, new environmental legislation regarding air quality and other discharges in the process of generating electricity, market prices for fuel and electricity, overall financial condition of lease counterparties, and the quality and condition of assets under lease.
Note 6. Available-for-Sale Securities
Nuclear Decommissioning Trust (NDT) Funds
Power maintains an external master nuclear decommissioning trust to fund its share of decommissioning for its five nuclear facilities upon termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. The trust funds are managed by third party investment advisors who operate under investment guidelines developed by Power.
Power classifies investments in the NDT funds as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT funds:
As of March 31, 2011 | ||||||||||||||||
Cost |
Gross Unrealized Gains |
Gross Unrealized Losses |
Estimated Fair |
|||||||||||||
Millions | ||||||||||||||||
Equity Securities | $ | 504 | $ | 198 | $ | (3 | ) | $ | 699 | |||||||
Debt Securities |
||||||||||||||||
Government Obligations |
294 | 6 | (4 | ) | 296 | |||||||||||
Other Debt Securities |
254 | 9 | (2 | ) | 261 | |||||||||||
Total Debt Securities | 548 | 15 | (6 | ) | 557 | |||||||||||
Other Securities | 110 | 0 | 0 | 110 | ||||||||||||
Total Available-for-Sale Securities | $ | 1,162 | $ | 213 | $ | (9 | ) | $ | 1,366 | |||||||
As of December 31, 2010 | ||||||||||||||||
Cost |
Gross Unrealized Gains |
Gross Unrealized Losses |
Estimated Fair |
|||||||||||||
Millions | ||||||||||||||||
Equity Securities |
$ | 525 | $ | 213 | $ | (3 | ) | $ | 735 | |||||||
Debt Securities |
||||||||||||||||
Government Obligations |
301 | 6 | (4 | ) | 303 | |||||||||||
Other Debt Securities |
247 | 10 | (2 | ) | 255 | |||||||||||
Total Debt Securities |
548 | 16 | (6 | ) | 558 | |||||||||||
Other Securities |
70 | 0 | 0 | 70 | ||||||||||||
Total Available-for-Sale Securities |
$ | 1,143 | $ | 229 | $ | (9 | ) | $ | 1,363 | |||||||
17
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The following table shows the value of securities in the NDT funds that have been in an unrealized loss position for less than and greater than 12 months:
As of March 31, 2011 | As of December 31, 2010 | |||||||||||||||||||||||||||||||
Less Than
12 Months |
Greater Than
12 Months |
Less Than
12 Months |
Greater Than
12 Months |
|||||||||||||||||||||||||||||
Fair Value |
Gross Unrealized Losses |
Fair Value |
Gross Unrealized Losses |
Fair Value |
Gross Unrealized Losses |
Fair Value |
Gross Unrealized Losses |
|||||||||||||||||||||||||
Millions | ||||||||||||||||||||||||||||||||
Equity Securities (A) |
$ | 43 | $ | (3 | ) | $ | 0 | $ | 0 | $ | 55 | $ | (3 | ) | $ | 0 | $ | 0 | ||||||||||||||
Debt Securities |
||||||||||||||||||||||||||||||||
Government Obligations (B) |
117 | (4 | ) | 2 | 0 | 106 | (4 | ) | 1 | 0 | ||||||||||||||||||||||
Other Debt Securities (C) |
73 | (1 | ) | 5 | (1 | ) | 65 | (1 | ) | 8 | (1 | ) | ||||||||||||||||||||
Total Debt Securities |
190 | (5 | ) | 7 | (1 | ) | 171 | (5 | ) | 9 | (1 | ) | ||||||||||||||||||||
Total Available-for-Sale Securities |
$ | 233 | $ | (8 | ) | $ | 7 | $ | (1 | ) | $ | 226 | $ | (8 | ) | $ | 9 | $ | (1 | ) | ||||||||||||
(A) | Equity SecuritiesInvestments in marketable equity securities within the NDT funds are primarily investments in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over one hundred companies with limited impairment durations and a severity that is generally less than fifteen percent of cost. Power does not consider these securities to be other-than-temporarily impaired as of March 31, 2011. |
(B) | Debt Securities (Government)Unrealized losses on Powers NDT investments in U.S. Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the U.S. government or an agency of the U.S. government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of March 31, 2011. |
(C) | Debt Securities (Corporate)Powers investments in corporate bonds are primarily with investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of March 31, 2011. |
The proceeds from the sales of and the net realized gains on securities in the NDT Funds were:
Three Months Ended March 31, |
||||||||
2011 |
2010 |
|||||||
Millions | ||||||||
Proceeds from Sales |
$ | 315 | $ | 181 | ||||
Net Realized Gains (Losses): |
||||||||
Gross Realized Gains |
$ | 59 | $ | 28 | ||||
Gross Realized Losses |
(7 | ) | (12 | ) | ||||
Net Realized Gains (Losses) |
$ | 52 | $ | 16 | ||||
18
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Net realized gains disclosed in the above table were recognized in Other Income and Other Deductions in PSEGs and Powers Condensed Consolidated Statements of Operations. Net unrealized gains of $102 million (after-tax) were recognized in Accumulated Other Comprehensive Income (OCI) on Powers Condensed Consolidated Balance Sheet as of March 31, 2011. The available-for-sale debt securities held as of March 31, 2011 had the following maturities:
Time Frame |
Fair Value |
|||
Millions | ||||
Less than one year |
$ | 25 | ||
1 - 5 years |
100 | |||
6 - 10 years |
143 | |||
11 - 15 years |
40 | |||
16 - 20 years |
9 | |||
Over 20 years |
240 | |||
$ | 557 | |||
The cost of these securities was determined on the basis of specific identification.
Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through OCI. In 2011, other-than-temporary impairments of $1 million were recognized on securities in the NDT funds. Any subsequent recoveries in the value of these securities are recognized in OCI unless the securities are sold, in which case, any gain is recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost detail of the securities.
Rabbi Trusts
PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in grantor trusts commonly known as Rabbi Trusts.
PSEG classifies investments in the Rabbi Trusts as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost basis for the securities held in the Rabbi Trusts.
As of March 31, 2011 | ||||||||||||||||
Cost |
Gross Unrealized Gains |
Gross Unrealized Losses |
Estimated Fair |
|||||||||||||
Millions | ||||||||||||||||
Equity Securities |
$ | 16 | $ | 4 | $ | 0 | $ | 20 | ||||||||
Debt Securities |
144 | 0 | 0 | 144 | ||||||||||||
Total PSEG Available-for-Sale Securities |
$ | 160 | $ | 4 | $ | 0 | $ | 164 | ||||||||
19
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
As of December 31, 2010 | ||||||||||||||||
Cost |
Gross Unrealized Gains |
Gross Unrealized Losses |
Estimated Fair |
|||||||||||||
Millions | ||||||||||||||||
Equity Securities |
$ | 16 | $ | 2 | $ | 0 | $ | 18 | ||||||||
Debt Securities |
142 | 0 | 0 | 142 | ||||||||||||
Total PSEG Available-for-Sale Securities |
$ | 158 | $ | 2 | $ | 0 | $ | 160 | ||||||||
The Rabbi Trusts are invested in commingled indexed mutual funds, in which the shares have the characteristics of equity securities. Due to the commingled nature of these funds, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For the three months ended March 31, 2011 and 2010, proceeds from sales, realized gains and realized losses related to the Rabbi Trusts were immaterial. For the three months ended March 31, 2011, other-than-temporary impairments of $3 million were recognized on the bond portfolio of the Rabbi Trusts.
The cost of these securities was determined on the basis of specific identification.
The estimated fair value of the Rabbi Trusts related to PSEG, Power and PSE&G are detailed as follows:
As of 2011 |
As of 2010 |
|||||||
Millions | ||||||||
Power |
$ | 32 | $ | 32 | ||||
PSE&G |
54 | 54 | ||||||
Other |
78 | 74 | ||||||
Total PSEG Available-for-Sale Securities |
$ | 164 | $ | 160 | ||||
PSEG sponsors several qualified and nonqualified pension plans and OPEB plans covering PSEGs 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. New federal health care legislation enacted in March 2010 eliminates the tax deductibility of retiree health care costs beginning in 2013, to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. See Note 13. Income Taxes for additional information.
20
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Pension and OPEB costs for PSEG are detailed as follows:
Pension Benefits Three Months March 31, |
OPEB Three Months March 31, |
|||||||||||||||
2011 |
2010 |
2011 |
2010 |
|||||||||||||
Millions | ||||||||||||||||
Components of Net Periodic |
||||||||||||||||
Service Cost |
$ | 24 | $ | 22 | $ | 4 | $ | 4 | ||||||||
Interest Cost |
58 | 58 | 15 | 18 | ||||||||||||
Expected Return on Plan Assets |
(81 | ) | (67 | ) | (4 | ) | (4 | ) | ||||||||
Amortization of Net |
||||||||||||||||
Transition Obligation |
0 | 0 | 2 | 7 | ||||||||||||
Prior Service Cost |
0 | 0 | (3 | ) | 3 | |||||||||||
Actuarial Loss |
30 | 30 | 3 | 2 | ||||||||||||
Net Periodic Benefit Cost |
$ | 31 | $ | 43 | $ | 17 | $ | 30 | ||||||||
Effect of Regulatory Asset |
0 | 0 | 5 | 5 | ||||||||||||
Total Benefit Costs, Including Effect of Regulatory Asset |
$ | 31 | $ | 43 | $ | 22 | $ | 35 | ||||||||
Pension and OPEB costs for Power, PSE&G and PSEGs other subsidiaries are detailed as follows:
Pension Three Months Ended March 31, |
OPEB Three Months Ended March 31, |
|||||||||||||||
2011 |
2010 |
2011 |
2010 |
|||||||||||||
Millions | ||||||||||||||||
Power |
$ | 10 | $ | 13 | $ | 3 | $ | 4 | ||||||||
PSE&G |
17 | 24 | 18 | 30 | ||||||||||||
Other |
4 | 6 | 1 | 1 | ||||||||||||
Total Benefit Costs |
$ | 31 | $ | 43 | $ | 22 | $ | 35 | ||||||||
During the three months ended March 31, 2011, PSEG contributed its entire planned contributions for the year 2011 of $415 million and $11 million into its pension and postretirement healthcare plans, respectively.
Note 8. Commitments and Contingent Liabilities
Guaranteed Obligations
Powers 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 with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees.
Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to
| support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and |
| obtain credit. |
21
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
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.
In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to
| fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and |
| all of the related contracts would have to be out-of-the-money (if the contracts are terminated, Power would owe money to the counterparties). |
Power believes the probability of this result is unlikely. For this reason, Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.
Power is subject to
| counterparty collateral calls related to commodity contracts, and |
| certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries. |
Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules.
The face value of outstanding guarantees, current exposure and margin positions as of March 31, 2011 and December 31, 2010 are shown below:
As of 2011 |
As of 2010 |
|||||||
Millions | ||||||||
Face Value of Outstanding Guarantees |
$ | 1,998 | $ | 1,936 | ||||
Exposure under Current Guarantees |
$ | 297 | $ | 330 | ||||
Letters of Credit Margin Posted |
$ | 199 | $ | 137 | ||||
Letters of Credit Margin Received |
$ | 64 | $ | 109 | ||||
Cash Deposited and Received |
||||||||
Counterparty Cash Margin Deposited |
$ | 0 | $ | 0 | ||||
Counterparty Cash Margin Received |
$ | (4 | ) | $ | (2 | ) | ||
Net Broker Balance Received |
$ | (3 | ) | $ | (28 | ) | ||
In the event Power were to lose its investment grade rating: |
||||||||
Additional Collateral that could be Required |
$ | 772 | $ | 828 | ||||
Liquidity Available under PSEGs and Powers Credit Facilities to Post Collateral |
$ | 2,752 | $ | 2,750 | ||||
Additional Amounts Posted |
||||||||
Other Letters of Credit |
$ | 98 | $ | 98 |
Power nets receivables and payables with the corresponding net energy contract balances. See Note 10. Financial Risk Management Activities for further discussion. The remaining balance of net cash (received) deposited is primarily included in Accounts Payable.
22
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
In the event of a deterioration of Powers 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 further performance assurance. See table above.
In addition to amounts for outstanding guarantees, current exposure and margin positions, Power had posted letters of credit to support various other non-energy contractual and environmental obligations. See table above.
Environmental Matters
Passaic River
Historic operations by PSEG companies and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex.
Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA)
The U.S. Environmental Protection Agency (EPA) has determined that an eight-mile stretch of the Passaic River in the area of Newark, New Jersey is a facility within the meaning of that term under CERCLA. The EPA has determined the need to perform a study of the entire 17-mile tidal reach of the lower Passaic River.
PSE&G and certain of its predecessors conducted operations at properties in this area on or adjacent to the Passaic River. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former manufactured gas plant (MGP) sites. When the Essex Site was transferred from PSE&G to Power, PSE&G obtained releases and indemnities for liabilities arising out of the former Essex generating station and Power assumed any environmental liabilities.
The EPA believes that hazardous substances were released from the Essex Site and one of PSE&Gs former MGP locations (Harrison Site). In 2006, the EPA notified the potentially responsible parties (PRPs) that the cost of its study would greatly exceed the original estimated cost of $20 million. 73 PRPs, including Power and PSE&G, agreed to assume responsibility for the study and to divide the associated costs according to a mutually agreed upon formula. The PRP group, currently 69 members, is presently executing the study. Approximately five percent of the study costs are attributable to PSE&Gs former MGP sites and approximately one percent to Powers generating stations. Power has provided notice to insurers concerning this potential claim.
In 2007, the EPA released a draft Focused Feasibility Study that proposed six options to address the contamination cleanup of the lower eight miles of the Passaic River. The estimated costs for the proposed remedy range from $1.3 billion to $3.7 billion. The work contemplated by the study is not subject to the cost sharing agreement discussed above. A revised focused feasibility study may be released as early as the second quarter of 2011.
In June 2008, an agreement was announced between the EPA and two PRPs for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of $80 million. The two PRPs have reserved their rights to seek contribution for the removal costs from the other PRPs, including Power and PSE&G.
New Jersey Spill Compensation and Control Act (Spill Act)
In 2005, the New Jersey Department of Environmental Protection (NJDEP) filed suit against a PRP and its related companies in the New Jersey Superior Court seeking damages and reimbursement for costs expended by the State of New Jersey to address the effects of the PRPs discharge of hazardous substances into both the Passaic River and the balance of the Newark Bay Complex. Power and PSE&G are alleged to have owned, operated or contributed hazardous substances to a total of 11 sites or facilities that impacted these water bodies. In February 2009, third party complaints were filed against some 320 third party defendants, including Power and PSE&G, claiming that each of the third party defendants is responsible for its proportionate share
23
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
of the clean-up costs for the hazardous substances they allegedly discharged into the Passaic River and the Newark Bay Complex. The third party complaints seek statutory contribution and contribution under the Spill Act to recover past and future removal costs and damages. Power and PSE&G filed answers to the complaint in June 2010. A special master for discovery has been appointed by the court. Power and PSE&G believe they have good and valid defenses to the allegations contained in the third party complaints and will vigorously assert those defenses.
Natural Resource Damage Claims
In 2003, the NJDEP directed PSEG, PSE&G and 56 other 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 Spill Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million. In 2007, agencies of the United States Department of Commerce and the United States Department of the Interior sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees claims can be resolved in a cooperative fashion. That effort is continuing.
Newark Bay Study Area
The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area and encouraged the PRPs to contact Occidental Chemical Corporation (OCC) to discuss participating in the Remedial Investigation/Feasibility Study that OCC was conducting. The notice stated the EPAs belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG is participating in and partially funding this study. Notices to fund the next phase of the study have been received but it is uncertain at this time whether the PSEG companies will consent to fund the next phase.
PSEG, Power and PSE&G cannot predict what further actions, if any, or the costs or the timing thereof, may be required with respect to the Passaic River, the NJDEP Litigation, the Newark Bay Study Area or with respect to natural resource damages claims; however, such costs could be material.
MGP Remediation Program
PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at PSE&Gs former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. The NJDEP has also 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. In 2005, the NJDEP initiated a program on the Delaware River aimed at identifying the ten most significant sites for cleanup. One of the sites identified was PSE&Gs former Camden Coke facility.
During the third quarter of 2010, PSE&G updated the estimated cost to remediate all MGP sites to completion and determined that the cost to completion could range between $668 million and $774 million from September 30, 2010 through 2021. Since no amount within the range was considered to be most likely, PSE&G reflected a liability of $668 million on its Condensed Consolidated Balance Sheet as of September 30, 2010. Since September 30, 2010, PSE&G had $10 million of expenditures, reducing the liability to $658 million as of March 31, 2011. Of this amount, $59 million was recorded in Other Current Liabilities and $599 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $658 million Regulatory Asset with respect to these costs.
24
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Prevention of Significant Deterioration (PSD)/New Source Review (NSR)
The PSD/NSR regulations, promulgated under the Clean Air Act, 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 that are not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties ranging from $25,000 to $37,500 per day for each violation, depending upon when the alleged violation occurred.
In November 2006, Power reached an agreement with the EPA and the NJDEP to achieve emissions reductions targets at certain of Powers generating stations. Under this agreement, Power was required to undertake a number of technology projects, plant modifications and operating procedure changes at the Hudson and Mercer facilities designed to meet targeted reductions in emissions of sulfur dioxide (SO2), nitrogen oxide (NOx), particulate matter and mercury. Power completed the construction of all plant modifications by the end of 2010 at a cost of $1.3 billion. Performance testing to validate the agreed-upon emission reductions is ongoing.
In January 2009, the EPA issued a notice of violation to Power and the other owners of the Keystone coal fired plant in Pennsylvania, alleging, among other things, that various capital improvement projects were completed at the plant which are considered modifications (or major modifications) causing significant net emission increases of PSD/NSR air pollutants, beginning in 1985 for Keystone Unit 1 and in 1984 for Keystone Unit 2. The notice of violation states that none of these modifications underwent PSD/NSR permitting process prior to being put into service, which the EPA alleges was required under the Clean Air Act. The notice of violation states that the EPA may issue an order requiring compliance with the relevant Clean Air Act provisions and may seek injunctive relief and/or civil penalties. Power owns approximately 23% of the plant. Power cannot predict the outcome of this matter.
Hazardous Air Pollutants Regulation
In accordance with a court ruling, the EPA proposed a Maximum Achievable Control Technology (MACT) regulation in March 2011 which is expected to be finalized by November 2011. This regulation includes reduction of mercury and other hazardous air pollutants pursuant to the Clean Air Act. Until the final rule is adopted, the impact cannot be determined; however, if the rule is adopted as proposed, Power believes the back end technology environmental controls recently installed at its Hudson and Mercer coal facilities should meet the rules requirements. At Powers Connecticut and some of the other New Jersey facilities, some additional controls could be necessary, pending engineering evaluation. The impact to Powers jointly owned coal fired generating facilities in Pennsylvania is under evaluation.
New Jersey regulations required coal fired electric generating units to meet certain emissions limits or reduce mercury emissions by approximately 90% by December 15, 2007. Companies that are parties to multi-pollutant reduction agreements, such as Power, have been permitted to postpone such reductions on half of their coal fired electric generating capacity until December 15, 2012.
With its newly installed controls in New Jersey, Power is expected to achieve the required mercury reductions that are part of Powers multi-pollutant reduction agreement that resolved issues arising out of the PSD/NSR air pollution control programs discussed above.
In 2007, Pennsylvania finalized its state-specific requirements to reduce mercury emissions from coal fired electric generating units. In 2009, the Commonwealth Court of Pennsylvania struck down the state rule, indicating that the rule violated Pennsylvania law because it was inconsistent with the Clean Air Act. This decision was affirmed by the Supreme Court of Pennsylvania.
NOx Regulation
In April 2009, the NJDEP finalized revisions to NOx emission control regulations that impose new NOx emission reduction requirements and limits for New Jersey fossil fuel fired electric generating units. The rule
25
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
has a significant impact on Powers generation fleet, as it imposes NOx emissions limits that will require significant capital investment for controls or the retirement of up to 102 combustion turbines (approximately 2,000 MW) and five older New Jersey steam electric generating units (approximately 800 MW) by April 30, 2015.
Power has been working with the NJDEP throughout the development of this rulemaking to minimize financial impact and to provide for transitional lead time to address the retirement of electric generating units. Power cannot predict the financial impact resulting from compliance with this rulemaking.
Under current Connecticut regulations, Powers Bridgeport and New Haven facilities have been utilizing Discrete Emission Reduction Credits (DERCs) to comply with certain NOx emission limitations that were incorporated into the facilities operating permits. On April 30, 2010, Power negotiated new agreements with the State of Connecticut extending the continued use of DERCs for certain emission units and equipment until May 31, 2014.
New Jersey Industrial Site Recovery Act (ISRA)
Potential environmental liabilities related to the alleged discharge of hazardous substances at certain generating stations have been identified. In the second quarter of 1999, in anticipation of the transfer of PSE&Gs generation-related assets to Power, a study was conducted pursuant to ISRA, which applied to the sale of certain assets. Power had a $50 million liability related to these obligations, which was included in Environmental Costs on Powers and PSEGs Condensed Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010.
Clean Water Act Permit Renewals
Pursuant to the Federal Water Pollution Control Act (FWPCA), New Jersey Pollutant Discharge Elimination System (NJPDES) permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. Power has filed or will be filing applications for permits in a variety of states.
One of the most significant NJPDES permits governing cooling water intake structures at Power is for Salem. In 2001, the NJDEP issued a renewed NJPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water intake system. In February 2006, Power filed with the NJDEP a renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued. Power prepared its renewal application in accordance with the FWPCA Section 316(b) and the 316(b) rules published in 2004. Those rules did not mandate the use of cooling towers at large existing generating plants. Rather, the rules provided alternatives for compliance with 316(b), including the use of restoration efforts to mitigate for the potential effects of cooling water intake structures, as well as the use of site-specific analysis to determine the best technology available for minimizing adverse impact based upon a cost-benefit test. Power has used restoration and/or a site-specific cost-benefit test in applications filed to renew the permits at its once-through cooled plants, including Salem, Hudson and Mercer.
As a result of several challenges to the 2004 316(b) rule by certain northeast states, environmentalists and industry groups, the rule has been suspended and has been returned to the EPA to be consistent with a January 2007 U.S. Court of Appeals for the Second Circuit decision, as modified by an April 2009 United States Supreme Court decision. In sum, the Second Circuit issued a decision that remanded major portions of the regulations and determined that Section 316(b) of the FWPCA does not support the use of restoration and the site-specific cost-benefit test. In April 2009, the U.S. Supreme Court reversed the Second Circuits opinion concerning the cost-benefit test, concluding that the EPA could rely upon cost-benefit analysis in setting the national performance standards and in providing for cost-benefit variances from those standards as part of the Phase II regulations.
In late 2010, the EPA entered into a settlement agreement with environmental groups that established a schedule to develop a new 316(b) rule. On April 20, 2011, the EPA published the proposed rule and comments
26
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
are due 90 days thereafter. The proposed rule would establish certain standards for existing cooling water intake structures with a design flow of more than 2 million gallons per day. If the rule were to be adopted as proposed, the majority of Powers electric generating facilities would be affected as they employ once-through cooling utilizing tidal river and tidal waters. Power is reviewing the proposed rule and assessing the potential impact on its generating facilities. Power is unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on its future capital requirements, financial condition or results of operations which could be material.
The results of further proceedings on this matter could have a material impact on Powers ability to renew permits at its larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Powers once-through cooled plants could be material, and would require economic review to determine whether to continue operations at these facilities. For example, in Powers application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1 billion, of which Powers share would have been approximately $575 million. These cost estimates have not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Powers forecasted capital expenditures.
In addition to the EPA rulemaking, several states, including California and New York, have begun setting policies that may require closed cycle cooling. It is unknown how these policies will ultimately impact the EPAs rulemaking.
In January 2010, the NJDEP issued a draft NJPDES permit to another company which would require the installation of closed cycle cooling at that companys nuclear generating station located in New Jersey. In December 2010, NJDEP and that company entered into an Administrative Consent Order (ACO) which would require the company to cease operations at the nuclear generating station no later than 2019. In the ACO, the NJDEP agreed that closed cycle cooling is not the best technology available for that facility and agreed to issue a new draft NJPDES permit for that facility without a requirement for construction of cooling towers or other closed cycle cooling facilities. The new draft NJPDES permit will be issued in substitution for the draft NJPDES permit issued in January 2010. We cannot predict at this time the final outcome of the NJDEP decision and the impact, if any, such a decision would have on any of Powers once-through cooled generating stations.
Stormwater
In October 2008, the NJDEP notified Power that it must apply for an individual stormwater discharge permit for its Hudson generating station. Hudson stores its coal in an open air pile and, as a result, it is exposed to precipitation. Discharge of stormwater from Hudson has been regulated pursuant to a Basic Industrial Stormwater General Permit, authorization of which has been previously approved by the NJDEP. The NJDEP has determined that Hudson is no longer eligible to utilize this general permit.
In December 2010, the NJDEP issued a draft renewal NJPDES permit to Power which, among other things, proposed conditions regarding stormwater runoff from the Hudson coal pile. The NJDEP authorized a new discharge of stormwater runoff without further requirement to construct technologies preventing the discharge of stormwater to surface water or groundwater. The draft permit is subject to public comment. It is unclear when the NJDEP will issue a final NJPDES permit. To the extent the NJDEP reverses course and requires elimination of the exposure of coal to stormwater, or requires new technologies to prevent the discharge of stormwater to surface or groundwater, those costs could be material.
New Generation and Development
Nuclear
Power has approved the expenditure of approximately $192 million for a steam path retrofit and related upgrades at its co-owned Peach Bottom Units 2 and 3. Completion of these upgrades is expected to result in an
27
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
increase of Powers share of nominal capacity by approximately 32 MW (14 MW at Unit 3 in 2011 and 18 MW at Unit 2 in 2012). Total expenditures through March 31, 2011 were $57 million and are expected to continue through 2012.
Power has begun expenditures in pursuit of additional output through an extended power uprate of the Peach Bottom nuclear units. The uprate is expected to be in service in 2015 for Unit 2 and 2016 for Unit 3. Powers share of the increased capacity is expected to be approximately 133 MW with an anticipated cost of approximately $400 million. Total expenditures through March 31, 2011 were $22 million and are expected to continue through 2016.
Connecticut
Power has been selected by the Connecticut Department of Public Utility Control in a regulatory process to build 130 MW of gas fired peaking capacity. Final approval has been received and construction is expected to commence in the second quarter of 2011. The project is expected to be in service by June 2012. Power estimates the cost of these generating units to be $130 million to $140 million. Total capitalized expenditures through March 31, 2011 were $60 million, which are included in Property, Plant and Equipment on the Condensed Consolidated Balance Sheets of PSEG and Power.
PJM Interconnection L.L.C. (PJM)
Power plans to construct gas fired peaking facilities at its Kearny site. Capacity in the amount of 178 MW was bid into and cleared the PJM Reliability Pricing Model (RPM) base residual capacity auction for the 2012-2013 period. Final approval has been received and construction is expected to commence in the second quarter of 2011. The project is expected to be in service by June 2012. In addition, capacity in the amount of 89 MW was bid into and cleared the PJM RPM base residual capacity auction for the 2013-2014 period. Final approval has been received, and the project is expected to be in service by June 2012. Power estimates the cost of these generating units to be $250 million to $300 million. Total capitalized expenditures through March 31, 2011 were $64 million which are included in Property, Plant and Equipment on Powers and PSEGs Condensed Consolidated Balance Sheets.
PSE&GSolar
As part of the BPU-approved Solar 4 All Program, PSE&G is installing up to 40 MW of solar generation on existing utility poles within its service territory. PSE&G has entered into an agreement to purchase solar units for this program. PSE&Gs commitments under this agreement are contingent upon, among other things, the availability of suitable utility poles for installation of the units. Approximately 18 MW have been installed as of March 31, 2011. PSE&Gs cumulative investments for these solar units were approximately $130 million, with additional purchases to be made on a quarterly basis during the remaining two-year term of the purchase agreement.
Another aspect of the Solar 4 All program is the installation of another 40 MW of solar systems on land and buildings owned by PSE&G and third parties. Through March 31, 2011, 19 MW representing 13 projects were placed into service with an investment of approximately $100 million.
Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS)
PSE&G obtains its electric supply requirements for customers who do not purchase electric supply from third party suppliers through the annual New Jersey BGS auctions. Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master Agreement (SMA) with the winners of these BGS auctions following the BPUs approval of the auction results. PSE&G has entered into contracts with Power, as well as with other winning BGS suppliers, to purchase BGS for PSE&Gs load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jerseys renewable portfolio standards.
28
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Power seeks to mitigate volatility in its results by contracting in advance for the sale of most of 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 also enters into firm supply contracts with EDCs, as well as other firm sales and commitments.
PSE&G has contracted for its anticipated BGS-Fixed Price eligible load, as follows:
Auction Year | ||||||||||||||||
2008 |
2009 |
2010 |
2011 |
|||||||||||||
36-Month Terms Ending |
May 2011 | May 2012 | May 2013 | May 2014 | (A) | |||||||||||
Load (MW) |
2,800 | 2,900 | 2,800 | 2,800 | ||||||||||||
$ per kWh |
0.11150 | 0.10372 | 0.09577 | 0.09430 |
(A) | Prices set in the 2011 BGS auction will become effective on June 1, 2011 when the 2008 BGS auction agreements expire. |
PSE&G has a full requirements contract with Power to meet the gas supply requirements of PSE&Gs 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 PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. For additional information, see Note 17. Related-Party Transactions. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements.
Minimum Fuel Purchase Requirements
Power has various long-term fuel purchase commitments for coal and oil to support its fossil generation stations and for supply of nuclear fuel for the Salem and Hope Creek nuclear generating stations and for firm transportation and storage capacity for natural gas.
Powers various multi-year contracts for firm transportation and storage capacity for natural gas are primarily used to meet its gas supply obligations to PSE&G. These purchase obligations are consistent with Powers strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts.
Powers strategy is to maintain certain levels of uranium in inventory and to make periodic purchases to support such levels. As such, the commitments referred to below may include estimated quantities to be purchased that deviate from contractual nominal quantities. Powers nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2012 and a portion for 2013, 2014 and 2015 at Salem, Hope Creek and Peach Bottom.
As of March 31, 2011, the total minimum purchase requirements included in these commitments were as follows:
Fuel Type |
Commitments |
|||
Millions | ||||
Nuclear Fuel |
||||
Uranium |
$ | 414 | ||
Enrichment |
$ | 351 | ||
Fabrication |
$ | 128 | ||
Natural Gas |
$ | 803 | ||
Coal |
$ | 1,196 |
29
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Included in the $1,196 million commitment for coal is $723 million related to a certain coal contract under which Power can cancel contractual deliveries at minimal cost. In 2011, Power has not cancelled any coal shipments.
Regulatory Proceedings
Electric Discount and Energy Competition Act (Competition Act)
In April 2007, PSE&G and Transition Funding were served with a purported class action complaint (Complaint) in New Jersey Superior Court challenging the constitutional validity of certain stranded cost recovery provisions of the Competition Act, seeking injunctive relief against continued collection from PSE&Gs electric customers of the Transition Bond Charge (TBC) of Transition Funding, as well as recovery of TBC amounts previously collected. Under New Jersey law, the Competition Act, enacted in 1999, is presumed constitutional.
In July 2007, the plaintiff filed an amended Complaint to also seek injunctive relief from continued collection of related taxes as well as recovery of such taxes previously collected. In July 2007, PSE&G filed a motion to dismiss the amended Complaint, which was granted in October 2007. In November 2007, the plaintiff filed a notice of appeal with the Appellate Division of the New Jersey Superior Court. In February 2009, the New Jersey Appellate Division affirmed the decision of the lower court dismissing the case. In May 2009, the New Jersey Supreme Court denied a request from the plaintiff to review the Appellate Divisions decision.
In July 2007, the same plaintiff also filed a petition with the BPU requesting review and adjustment to PSE&Gs recovery of the same stranded cost charges. In September 2007, PSE&G filed a motion with the BPU to dismiss the petition. In June 2010, the BPU granted PSE&Gs motion to dismiss. In April 2011, the BPU issued a written order memorializing this decision. The petitioner had previously stated that it would appeal the BPUs written order to the New Jersey Appellate Division and has until June 6, 2011 to do so.
New Jersey Clean Energy Program
In 2008, the BPU approved funding requirements for each New Jersey utility applicable to its Renewable Energy and Energy Efficiency programs for the years 2009 to 2012. The aggregate funding amount is $1.2 billion for all years. PSE&Gs share is $705 million. PSE&G has recorded a discounted liability of $385 million as of March 31, 2011. Of this amount, $211 million was recorded as a current liability and $174 million as a noncurrent liability. The liability has been recorded with an offsetting Regulatory Asset, since the costs associated with this program are expected to be recovered from PSE&G ratepayers through the societal benefits charge.
Long-Term Capacity Agreement Pilot Program (LCAPP)
In January 2011, New Jersey enacted the LCAPP Act directing the BPU to conduct a process to procure and subsidize up to 2,000 megawatts of baseload or mid-merit electric power generation. In March 2011 the BPU issued a written order approving a form of agreement and selecting three generators to build a total of approximately 1,949 MWs of new combined-cycle generating facilities located in New Jersey. Each of the New Jersey EDCs, including PSE&G, executed standard offer capacity agreements (SOCA) with each of the three selected generators in compliance with the BPUs directive, but did so under protest preserving its legal rights. The SOCA requires that the generator bid in and clear the PJM RPM base residual auction in each year of the SOCA term. The SOCA provides for the EDCs to make capacity payments to, or receive capacity payments from, the generators as calculated based on the difference between the RPM clearing price for each year of the term and the price bid and accepted for that generator in the BPU process. The LCAPP Act and the BPU order provide that, once the SOCAs are executed and approved by the BPU, they will be irrevocable and the EDCs will be entitled to full rate recovery of the prudently incurred costs. On April 27, 2011, the BPU approved the executed contracts and also announced that it will convene a proceeding to consider whether current mechanisms are adequate to incent needed generation construction in New Jersey.
30
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Leveraged Lease Investments
The IRS has issued reports with respect to its audits of PSEGs consolidated federal corporate income tax returns for tax years 1997 through 2003, which disallowed all deductions associated with certain lease transactions. The IRS reports also proposed a 20% penalty for substantial understatement of tax liability. PSEG has filed protests of these findings with the Office of Appeals of the IRS.
PSEG believes its tax position related to these transactions was proper based on applicable statutes, regulations and case law in effect at the time that the deductions were taken. There are several pending tax cases involving other taxpayers with similar leveraged lease investments. To date, six cases have been decided at the trial court level, four of which were decided in favor of the government. The appeals of two of these decisions were affirmed, both in favor of the government. The fifth case involves a jury verdict that was challenged by both parties on inconsistency grounds but was later settled by the parties. One case, involving an investment in an energy transaction by a utility, was decided in favor of the taxpayer.
In order to reduce the cash tax exposure related to these leases, Energy Holdings pursued opportunities to terminate international leases with lessees that were willing to meet certain economic thresholds. As of December 31, 2010, Energy Holdings had terminated all of these leasing transactions and reduced the related cash tax exposure by $1.1 billion. PSEG has completely eliminated its gross investment in such transactions.
Cash Impact
As of March 31, 2011, an aggregate of approximately $263 million would become currently payable if PSEG conceded all deductions taken through that date. PSEG has deposited $320 million with the IRS to defray potential interest costs associated with this disputed tax liability, eliminating its cash exposure completely. In the event PSEG is successful in defense of its position, the deposit is fully refundable with interest. Penalties of $150 million would also become payable if the IRS successfully asserted and litigated a case against PSEG. PSEG has not established a reserve for penalties because it believes it has strong defenses to the assertion of penalties under applicable law. Interest and penalty exposure will grow at an average rate of $2 million per quarter during 2011. If the IRS is successful in a litigated case consistent with the positions it has taken in the generic settlement offer recently proposed, an additional $20 million to $40 million of tax would be due for tax positions through March 31, 2011.
Unless this matter is resolved with the IRS, PSEG currently anticipates that it may be required to pay between $110 million and $300 million in tax, interest and penalties for the tax years 1997-2000 during 2011 and subsequently commence litigation to recover those amounts. It is possible that an additional payment of between $220 million and $540 million could be required during 2011 for tax years 2001-2003 followed by further litigation to recover those amounts. The amounts that may be required to litigate differ from the potential net cash exposure noted above, as the former amounts include all potential deficiencies for only contested tax years 1997 through 2003. These litigation amounts also include penalties which are not included in the computation of potential net cash exposure as PSEG believes it has strong defenses. These amounts also exclude an offset for taxes paid on lease terminations, which is netted in the potential net cash exposure as PSEG would be entitled to a refund of such amounts under a loss scenario. Any potential claims PSEG would make to recover such amounts would include the deposit noted above.
Earnings Impact
PSEGs current reserve position represents its view of the earnings impact that could result from a settlement related to these transactions, although a total loss, consistent with the broad settlement offer proposed by the IRS, would result in an additional earnings charge of $120 million to $140 million.
31
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Note 9. Changes in Capitalization
The following capital transactions occurred in the first three months of 2011:
Power
| paid a cash dividend of $175 million to PSEG in March. |
PSE&G
| paid $46 million of Transition Fundings securitization debt. |
Energy Holdings
| paid $1 million of nonrecourse project debt. |
In addition, Power paid its $606 million of 7.75% Senior Notes at maturity in April 2011.
Note 10. Financial Risk Management Activities
The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through hedging transactions. Hedging transactions use derivative instruments to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.
Commodity Prices
The availability and price of energy commodities are subject to fluctuations due to weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market conditions, transmission availability and other events. Power uses physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. Derivative contracts that do not qualify for hedge accounting or normal purchases/normal sales treatment are marked to market (MTM) with changes in fair value recorded in the income statement. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists.
Cash Flow Hedges
Power uses forward sale and purchase contracts, swaps, futures and firm transmission right (FTR) contracts to hedge
| forecasted energy sales from its generation stations and the related load obligations and |
| the price of fuel to meet its fuel purchase requirements. |
These derivative transactions are designated and effective as cash flow hedges. As of March 31, 2011 and December 31, 2010, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with these hedges was as follows:
As of 2011 |
As of 2010 |
|||||||
Millions | ||||||||
Fair Value of Cash Flow Hedges |
$ | 152 | $ | 196 | ||||
Impact on Accumulated Other Comprehensive Income (Loss) (after tax) |
$ | 82 | $ | 114 |
32
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The expiration date of the longest-dated cash flow hedge at Power is in 2012. Powers after-tax unrealized gains on these derivatives that are expected to be reclassified to earnings during the next 12 months and thereafter, are $81 million and $1 million, respectively. There was no material ineffectiveness associated with these hedges as of March 31, 2011.
Trading Derivatives
In general, the main purpose of Powers wholesale marketing operation is to optimize the value of the output of the generating facilities via various products and services available in the markets we serve. Power does engage in trading of electricity and energy-related products where such transactions are not associated with the output or fuel purchase requirements of our facilities. This trading consists mostly of energy supply contracts where we secure sales commitments with the intent to supply the energy services from purchases in the market rather than from our owned generation. Such trading activities are marked to market through the income statement and represent less than one percent of gross margin (revenues less energy costs) on an annual basis.
Other Derivatives
Power enters into other contracts that are derivatives, but do not qualify for cash flow hedge accounting. Most of these contracts are used for fuel purchases for generation requirements and for electricity purchases for contractual sales obligations. Changes in fair market value of these contracts are recorded in earnings. The fair value of these contracts as of March 31, 2011 and December 31, 2010 was $2 million and $(4) million, respectively.
Interest Rates
PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, we have used a mix of fixed and floating rate debt, interest rate swaps and interest rate lock agreements.
Fair Value Hedges
PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. Since 2009, PSEG has entered into eight interest rate swaps totaling $1.150 billion. These swaps convert $300 million of Powers $600 million of 6.95% Senior Notes due June 2012, Powers $250 million of 5% Senior Notes due April 2014, Powers $300 million of 5.5% Senior Notes due 2015 and $300 million of Powers $303 million of 5.32% Senior Notes due September 2016 into variable-rate debt. These interest rate swaps are designated and effective as fair value hedges. The fair value changes of the interest rate swaps are fully offset by the changes in the fair value of the underlying debt. As of March 31, 2011 and December 31, 2010, the fair value of all the underlying hedges was $30 million and $39 million, respectively.
Cash Flow Hedges
PSEG, Power and Energy Holdings use interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage their exposure to the variability of cash flows, primarily related to variable-rate debt instruments. As of March 31, 2011, there was no hedge ineffectiveness associated with these hedges. The total fair value of these interest rate derivatives was immaterial as of each of March 31, 2011 and December 31, 2010. The Accumulated Other Comprehensive Loss (after tax) related to interest rate derivatives designated as cash flow hedges was $3 million as of March 31, 2011 and December 31, 2010.
33
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Fair Values of Derivative Instruments
The following are the fair values of derivative instruments on the Condensed Consolidated Balance Sheets:
As of March 31, 2011 | ||||||||||||||||||||||||||||
Power | PSE&G | PSEG | Consolidated | |||||||||||||||||||||||||
Cash Flow Hedges |
Non Hedges | Netting (A) |
Total Power |
Non Hedges | Fair Value Hedges |
Total Derivatives |
||||||||||||||||||||||
Balance Sheet Location |
Energy- |
Energy- |
Energy- |
Interest |
||||||||||||||||||||||||
Millions | ||||||||||||||||||||||||||||
Derivative Contracts |
||||||||||||||||||||||||||||
Current Assets |
$ | 156 | $ | 348 | $ | (348 | ) | $ | 156 | $ | 0 | $ | 18 | $ | 174 | |||||||||||||
Noncurrent Assets |
6 | 64 | (38 | ) | 32 | 6 | 12 | 50 | ||||||||||||||||||||
Total Mark-to-Market Derivative Assets |
$ | 162 | $ | 412 | $ | (386 | ) | $ | 188 | $ | 6 | $ | 30 | $ | 224 | |||||||||||||
Derivative Contracts |
||||||||||||||||||||||||||||
Current Liabilities |
$ | (7 | ) | $ | (386 | ) | $ | 340 | $ | (53 | ) | $ | (11 | ) | $ | 0 | $ | (64 | ) | |||||||||
Noncurrent Liabilities |
(3 | ) | (60 | ) | 38 | (25 | ) | 0 | 0 | (25 | ) | |||||||||||||||||
Total Mark-to-Market Derivative (Liabilities) |
$ | (10 | ) | $ | (446 | ) | $ | 378 | $ | (78 | ) | $ | (11 | ) | $ | 0 | $ | (89 | ) | |||||||||
Total Net Mark-to-Market Derivative Assets (Liabilities) |
$ | 152 | $ | (34 | ) | $ | (8 | ) | $ | 110 | $ | (5 | ) | $ | 30 | $ | 135 | |||||||||||
As of December 31, 2010 | ||||||||||||||||||||||||||||
Power | PSE&G | PSEG | Consolidated | |||||||||||||||||||||||||
Cash Flow Hedges |
Non Hedges | Netting (A) |
Total Power |
Non Hedges | Fair Value Hedges |
Total Derivatives |
||||||||||||||||||||||
Balance Sheet Location |
Energy- |
Energy- |
Energy- |
Interest |
||||||||||||||||||||||||
Millions | ||||||||||||||||||||||||||||
Derivative Contracts |
||||||||||||||||||||||||||||
Current Assets |
$ | 204 | $ | 403 | $ | (444 | ) | $ | 163 | $ | 0 | $ | 19 | $ | 182 | |||||||||||||
Noncurrent Assets |
3 | 80 | (41 | ) | 42 | 17 | 20 | 79 | ||||||||||||||||||||
Total Mark-to-Market Derivative Assets |
$ | 207 | $ | 483 | $ | (485 | ) | $ | 205 | $ | 17 | $ | 39 | $ | 261 | |||||||||||||
Derivative Contracts |
||||||||||||||||||||||||||||
Current Liabilities |
$ | (11 | ) | $ | (454 | ) | $ | 374 | $ | (91 | ) | $ | (12 | ) | $ | 0 | $ | (103 | ) | |||||||||
Noncurrent Liabilities |
0 | (72 | ) | 50 | (22 | ) | 0 | 0 | (22 | ) | ||||||||||||||||||
Total Mark-to-Market Derivative (Liabilities) |
$ | (11 | ) | $ | (526 | ) | $ | 424 | $ | (113 | ) | $ | (12 | ) | $ | 0 | $ | (125 | ) | |||||||||
Total Net Mark-to-Market Derivative Assets (Liabilities) |
$ | 196 | $ | (43 | ) | $ | (61 | ) | $ | 92 | $ | 5 | $ | 39 | $ | 136 | ||||||||||||
(A) | Represents the netting of fair value balances with the same counterparty and the application of collateral. As of March 31, 2011 and December 31, 2010, net cash collateral received of $8 million and |
34
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
$61 million, respectively, was netted against the corresponding net derivative contract positions. Of the $8 million as of March 31, 2011, cash collateral of $(18) million and $(2) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $10 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively. Of the $61 million as of December 31, 2010, cash collateral of $(132) million and $(3) million were netted against current assets and noncurrent assets, respectively, and cash collateral of $62 million and $12 million were netted against current liabilities and noncurrent liabilities, respectively. |
The aggregate fair value of energy-related contracts in a liability position as of March 31, 2011 that contain triggers for additional collateral was $261 million. This potential additional collateral is included in the $772 million discussed in Note 8. Commitments and Contingent Liabilities.
The following shows the effect on the Condensed Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the three months ended March 31, 2011 and 2010:
Derivatives in Cash Flow Hedging Relationships |
Amount of Pre-Tax Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion) |
Location of Pre-Tax Gain (Loss) Reclassified from AOCI into Income |
Amount of Pre-Tax Gain (Loss) Reclassified from AOCI into Income (Effective Portion) |
Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion) |
Amount of Pre-Tax Gain (Loss) Recognized in Income on Derivatives (Ineffective Portion) |
|||||||||||||||||||||||||||
Three
Months Ended March 31, |
Three Months Ended March 31, |
Three Months Ended March 31, |
||||||||||||||||||||||||||||||
2011 | 2010 | 2011 | 2010 | 2011 | 2010 | |||||||||||||||||||||||||||
Millions | ||||||||||||||||||||||||||||||||
PSEG and Power | ||||||||||||||||||||||||||||||||
Energy-Related Contracts |
$ | 13 | $ | 208 | Operating Revenues | $ | 66 | $ | 76 | Operating Revenues | $ | (2 | ) | $ | (2 | ) | ||||||||||||||||
Energy-Related Contracts |
2 | (2 | ) | Energy Costs | 3 | (1 | ) | 0 | 0 | |||||||||||||||||||||||
Total PSEG | $ | 15 | $ | 206 | $ | 69 | $ | 75 | $ | (2 | ) | $ | (2 | ) | ||||||||||||||||||
The following reconciles the Accumulated Other Comprehensive Income for derivative activity included in the Accumulated Other Comprehensive Loss of PSEG on a pre-tax and after-tax basis:
Accumulated Other Comprehensive Income |
Pre-Tax | After-Tax | ||||||
Millions | ||||||||
Balance as of December 31, 2010 |
$ | 188 | $ | 111 | ||||
Gain Recognized in AOCI (Effective Portion) |
15 | 9 | ||||||
Less: Gain Reclassified into Income (Effective Portion) |
(69 | ) | (41 | ) | ||||
Balance as of March 31, 2011 |
$ | 134 | $ | 79 | ||||
35
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The following shows the effect on the Condensed Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as normal purchases and sales for the three months ended March 31, 2011 and 2010:
Derivatives Not Designated as Hedges |
Location of Pre-Tax Gain (Loss) Recognized in Income on Derivatives |
Pre-Tax Gain (Loss) Recognized in Income on Derivatives |
||||||||||
Three Months Ended |
||||||||||||
2011 |
2010 |
|||||||||||
PSEG and Power | Millions | |||||||||||
Energy-Related Contracts |
Operating Revenues | $ | (42 | ) | $ | 87 | ||||||
Energy-Related Contracts |
Energy Costs | 3 | (10 | ) | ||||||||
Total PSEG and Power |
$ | (39 | ) | $ | 77 | |||||||
Powers derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity and the purchase of fuel. Not all of these contracts qualify for hedge accounting. Most of these contracts are marked to market. The tables above do not include contracts for which Power has elected the normal purchase/normal sales exemption, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load. In addition, PSEG has interest rate swaps designated as fair value hedges. The effect of these hedges was to reduce interest expense by approximately $6 million for each of the three month periods ended March 31, 2011 and 2010.
The following reflects the gross volume, on an absolute value basis, of derivatives as of March 31, 2011 and December 31, 2010:
Type |
Notional |
Total |
PSEG |
Power |
PSE&G |
|||||||||||||||
Millions | ||||||||||||||||||||
As of March 31, 2011 |
||||||||||||||||||||
Natural Gas |
Dth | 979 | 0 | 715 | 264 | |||||||||||||||
Electricity |
MWh | 170 | 0 | 170 | 0 | |||||||||||||||
FTRs |
MWh | 12 | 0 | 12 | 0 | |||||||||||||||
Interest Rate Swaps |
US Dollars | 1,150 | 1,150 | 0 | 0 | |||||||||||||||
As of December 31, 2010 |
||||||||||||||||||||
Natural Gas |
Dth | 704 | 0 | 424 | 280 | |||||||||||||||
Electricity |
MWh | 154 | 0 | 154 | 0 | |||||||||||||||
Capacity |
MW days | 1 | 0 | 1 | 0 | |||||||||||||||
FTRs |
MWh | 23 | 0 | 23 | 0 | |||||||||||||||
Interest Rate Swaps |
US Dollars | 1,150 | 1,150 | 0 | 0 |
Credit Risk
Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we believe significantly minimize credit risk. These policies include an evaluation of potential counterparties financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which allow for the netting of positive and negative exposures associated with a single counterparty.
In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Powers financial condition, results of operations or net cash flows. As of March 31, 2011, 95% of the credit exposure (MTM plus net receivables and payables, less cash collateral) for Powers operations was with investment grade counterparties.
36
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The following table provides information on Powers credit risk from others, net of collateral, as of March 31, 2011. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of 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 quality of the companys credit risk by credit rating of the counterparties.
Rating |
Current |
Securities |
Net |
Number of |
Net Exposure of |
|||||||||||||||
Millions | Millions | |||||||||||||||||||
Investment Grade External Rating |
$ | 908 | $ | 45 | $ | 905 | 2 | $ | 572 | (A) | ||||||||||
Non-Investment Grade External Rating |
46 | 0 | 46 | 0 | 0 | |||||||||||||||
Investment Grade No External Rating |
9 | 0 | 9 | 0 | 0 | |||||||||||||||
Non-Investment Grade No External Rating |
7 | 0 | 7 | 0 | 0 | |||||||||||||||
Total |
$ | 970 | $ | 45 | $ | 967 | 2 | $ | 572 | |||||||||||
(A) | Includes net exposure of $432 million with PSE&G. The remaining net exposure of $140 million is with a nonaffiliated power purchaser which is a regulated investment grade counterparty. |
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 cash collateral than the outstanding exposure, in which case there would be no exposure. When letters of credit have been posted as collateral, the exposure amount is not reduced, but the exposure amount is transferred to the rating of the issuing bank. As of March 31, 2011, Power had 208 active counterparties.
Note 11. Fair Value Measurements
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entitys own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:
Level 1measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, Power and PSE&G have the ability to access. These consist primarily of listed equity securities.
Level 2measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities.
Level 3measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entitys own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instruments level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. These consist mainly of various FTRs, certain full requirements contracts and other longer term capacity and transportation contracts.
37
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
The following tables present information about PSEGs, Powers and PSE&Gs respective assets and (liabilities) measured at fair value on a recurring basis as of March 31, 2011 and December 31, 2010, including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for Power and PSE&G.
Recurring Fair Value Measurements as of March 31, 2011 |
||||||||||||||||||||
Cash Collateral |
Quoted Market Prices of Identical Assets |
Significant Other Observable Inputs |
Significant Unobservable Inputs |
|||||||||||||||||
Description |
Total |
Netting(E) |
(Level 1) |
(Level 2) |
(Level 3) |
|||||||||||||||
Millions | ||||||||||||||||||||
PSEG |
||||||||||||||||||||
Assets: |
||||||||||||||||||||
Derivative Contracts: |
||||||||||||||||||||
Energy-Related Contracts (A) |
$ | 194 | $ | (20 | ) | $ | 0 | $ | 185 | $ | 29 | |||||||||
Interest Rate Swaps (B) |
$ | 30 | $ | 0 | $ | 0 | $ | 30 | $ | 0 | ||||||||||
NDT Funds: (C) |
||||||||||||||||||||
Equity Securities |
$ | 699 | $ | 0 | $ | 699 | $ | 0 | $ | 0 | ||||||||||
Debt Securities-Govt Obligations |
$ | 296 | $ | 0 | $ | 0 | $ | 296 | $ | 0 | ||||||||||
Debt Securities-Other |
$ | 261 | $ | 0 | $ | 0 | $ | 261 | $ | 0 | ||||||||||
Other Securities |
$ | 110 | $ | 0 | $ | 5 | $ | 105 | $ | 0 | ||||||||||
Rabbi TrustsMutual Funds (C) |
$ | 164 | $ | 0 | $ | 20 | $ | 144 | $ | 0 | ||||||||||
Other Long-Term Investments (D) |
$ | 3 | $ | 0 | $ | 3 | $ | 0 | $ | 0 | ||||||||||
Liabilities: |
||||||||||||||||||||
Derivative Contracts: |
||||||||||||||||||||
Energy-Related Contracts (A) |
$ | (89 | ) | $ | 12 | $ | 0 | $ | (74 | ) | $ | (27 | ) | |||||||
Power |
||||||||||||||||||||
Assets: |
||||||||||||||||||||
Derivative Contracts: |
||||||||||||||||||||
Energy-Related Contracts (A) |
$ | 188 | $ | (20 | ) | $ | 0 | $ | 185 | $ | 23 | |||||||||
NDT Funds: (C) |
||||||||||||||||||||
Equity Securities |
$ | 699 | $ | 0 | $ | 699 | $ | 0 | $ | 0 | ||||||||||
Debt Securities-Govt Obligations |
$ | 296 | $ | 0 | $ | 0 | $ | 296 | $ | 0 | ||||||||||
Debt Securities-Other |
$ | 261 | $ | 0 | $ | 0 | $ | 261 | $ | 0 | ||||||||||
Other Securities |
$ | 110 | $ | 0 | $ | 5 | $ | 105 | $ | 0 | ||||||||||
Rabbi TrustsMutual Funds (C) |
$ | 32 | $ | 0 | $ | 4 | $ | 28 | $ | 0 | ||||||||||
Liabilities: |
||||||||||||||||||||
Derivative Contracts: |
||||||||||||||||||||
Energy-Related Contracts (A) |
$ | (78 | ) | $ | 12 | $ | 0 | $ | (74 | ) | $ | (16 | ) | |||||||
PSE&G |
||||||||||||||||||||
Assets: |
||||||||||||||||||||
Derivative Contracts: |
||||||||||||||||||||
Energy-Related Contracts (A) |
$ | 6 | $ | 0 | $ | 0 | $ | 0 | $ | 6 | ||||||||||
Rabbi TrustsMutual Funds (C) |
$ | 54 | $ | 0 | $ | 7 | $ | 47 | $ | 0 | ||||||||||
Liabilities: |
||||||||||||||||||||
Energy-Related Contracts (A) |
$ | (11 | ) | $ | 0 | $ | 0 | $ | 0 | $ | (11 | ) |
38
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Recurring Fair Value Measurements as of December 31, 2010 |
||||||||||||||||||||
Cash Collateral |
Quoted Market Prices of Identical Assets |
Significant Other Observable Inputs |
Significant Unobservable Inputs |
|||||||||||||||||
Description |
Total |
Netting(E) |
(Level 1) |
(Level 2) |
(Level 3) |
|||||||||||||||
Millions | ||||||||||||||||||||
PSEG |
||||||||||||||||||||
Assets: |
||||||||||||||||||||
Derivative Contracts: |
||||||||||||||||||||
Energy-Related Contracts (A) |
$ | 222 | $ | (135 | ) | $ | 0 | $ | 228 | $ | 129 | |||||||||
Interest Rate Swaps (B) |
$ | 39 | $ | 0 | $ | 0 | $ | 39 | $ | 0 | ||||||||||
NDT Funds: (C) |
||||||||||||||||||||
Equity Securities |
$ | 735 | $ | 0 | $ | 735 | $ | 0 | $ | 0 | ||||||||||
Debt Securities-Govt Obligations |
$ | 303 | $ | 0 | $ | 0 | $ | 303 | $ | 0 | ||||||||||
Debt Securities-Other |
$ | 255 | $ | 0 | $ | 0 | $ | 255 | $ | 0 | ||||||||||
Other Securities |
$ | 70 | $ | 0 | $ | 0 | $ | 62 | $ | 8 | ||||||||||
Rabbi TrustsMutual Funds (C) |
$ | 160 | $ | 0 | $ | 18 | $ | 142 | $ | 0 | ||||||||||
Other Long-Term Investments (D) |
$ | 2 | $ | 0 | $ | 2 | $ | 0 | $ | 0 | ||||||||||
Liabilities: |
||||||||||||||||||||
Derivative Contracts: |
||||||||||||||||||||
Energy-Related Contracts (A) |
$ | (125 | ) | $ | 74 | $ | 0 | $ | (117 | ) | $ | (82 | ) | |||||||
Power |
||||||||||||||||||||
Assets: |
||||||||||||||||||||
Derivative Contracts: |
||||||||||||||||||||
Energy-Related Contracts (A) |
$ | 205 | $ | (135 | ) | $ | 0 | $ | 228 | $ | 112 | |||||||||
NDT Funds: (C) |
||||||||||||||||||||
Equity Securities |
$ | 735 | $ | 0 | $ | 735 | $ | 0 | $ | 0 | ||||||||||
Debt Securities-Govt Obligations |
$ | 303 | $ | 0 | $ | 0 | $ | 303 | $ | 0 | ||||||||||
Debt Securities-Other |
$ | 255 | $ | 0 | $ | 0 | $ | 255 | $ | 0 | ||||||||||
Other Securities |
$ | 70 | $ | 0 | $ | 0 | $ | 62 | $ | 8 | ||||||||||
Rabbi TrustsMutual Funds (C) |
$ | 32 | $ | 0 | $ | 4 | $ | 28 | $ | 0 | ||||||||||
Liabilities: |
||||||||||||||||||||
Derivative Contracts: |
||||||||||||||||||||
Energy-Related Contracts (A) |
$ | (113 | ) | $ | 74 | $ | 0 | $ | (117 | ) | $ | (70 | ) | |||||||
PSE&G |
||||||||||||||||||||
Assets: |
||||||||||||||||||||
Derivative Contracts: |
||||||||||||||||||||
Energy-Related Contracts (A) |
$ | 17 | $ | 0 | $ | 0 | $ | 0 | $ | 17 | ||||||||||
Rabbi TrustsMutual Funds (C) |
$ | 54 | $ | 0 | $ | 6 | $ | 48 | $ | 0 | ||||||||||
Liabilities: |
||||||||||||||||||||
Energy-Related Contracts (A) |
$ | (12 | ) | $ | 0 | $ | 0 | $ | 0 | $ | (12 | ) |
(A) | Level 2Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using the average midpoint from multiple broker or dealer quotes or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs. |
39
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Level 3For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information is available, modeling techniques are employed using assumptions reflective of contractual terms, current market rates, forward price curves, discount rates and risk factors, as applicable. For certain energy-related option contracts where daily settled option prices are not observable, a traditional Black-Scholes valuation methodology is used which incorporates an internally developed volatility curve that is considered a significant unobservable input. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data. We considered the creditworthiness of our counterparties in the valuation of our energy-related contracts and the impacts are immaterial.
(B) | Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment. |
(C) | Powers NDT funds maintain investments in various equity and fixed income securities classified as available for sale. These securities are valued using quoted market prices, broker or dealer quotations or alternative pricing sources with reasonable levels of price transparency. All fair value measurements for the fund securities are provided by the trustees of these funds. Investments in marketable equity securities within the NDT funds are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or in some cases midpoint, bid or ask price (primarily Level 1). |
Powers NDT investments in fixed income securities are primarily with investment grade corporate bonds and U.S. Treasury obligations or Federal Agency mortgage-backed securities with a wide range of maturities. Fixed income securities are priced using an evaluated pricing methodology that reflects observable market information such as the most recent exchange price or quoted bid for similar securities (primarily Level 2). Short-term investments and certain commingled temporary investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield (primarily Level 2).
The Rabbi Trust mutual funds are mainly invested in a U.S. bond index fund, an S&P 500 index fund and a commingled temporary investment fund. The equity index fund is valued based on quoted prices in an active market (Level 1) while the bond index fund is valued using recent exchange prices or a quoted bid (Level 2).
(D) | Other long-term investments consist of equity securities and are valued using a market based approach based on quoted market prices. |
(E) | Cash collateral netting represents collateral amounts netted against derivative assets and liabilities as permitted under the accounting guidance for Offsetting of Amounts Related to Certain Contracts. |
40
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the three months ended March 31, 2011 and 2010 follows:
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Three Months Ended March 31, 2011
Total Gains or (Losses) Realized/Unrealized |
||||||||||||||||||||||||||||
Description |
Balance as of |
Included in |
Included in |
Purchases, |
(Issuances) |
Transfers |
Balance as of |
|||||||||||||||||||||
Millions | ||||||||||||||||||||||||||||
PSEG |
||||||||||||||||||||||||||||
Net Derivative Assets |
$ | 47 | $ | (31 | ) | $ | (10 | ) | $ | 18 | $ | (22 | ) | $ | 0 | $ | 2 | |||||||||||
NDT Funds |
$ | 8 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | (8 | ) | $ | 0 | |||||||||||||
Power |
||||||||||||||||||||||||||||
Net Derivative Assets |
$ | 42 | $ | (31 | ) | $ | 0 | $ | 18 | $ | (22 | ) | $ | 0 | $ | 7 | ||||||||||||
NDT Funds |
$ | 8 | $ | 0 | $ | 0 | $ | 0 | $ | 0 | $ | (8 | ) | $ | 0 | |||||||||||||
PSE&G |
||||||||||||||||||||||||||||
Net Derivative Assets |
$ | 5 | $ | 0 | $ | (10 | ) | $ | 0 | $ | 0 | $ | 0 | $ | (5 | ) |
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Three Months Ended March 31, 2010
Total Gains or (Losses) Realized/Unrealized |
||||||||||||||||||||
Description |
Balance as of |
Included in |
Included
in |
Purchases, |
Balance as of |
|||||||||||||||
Millions | ||||||||||||||||||||
PSEG |
||||||||||||||||||||
Net Derivative Assets |
$ | 105 | $ | 114 | $ | 45 | $ | (24 | ) | $ | 240 | |||||||||
NDT Funds |
$ | 9 | $ | 0 | $ | 0 | $ | 4 | $ | 13 | ||||||||||
Rabbi Trust Funds |
$ | 14 | $ | 0 | $ | 0 | $ | 2 | $ | 16 | ||||||||||
Power |
||||||||||||||||||||
Net Derivative Assets |
$ | 99 | $ | 114 | $ | 0 | $ | (24 | ) | $ | 189 | |||||||||
NDT Funds |
$ | 9 | $ | 0 | $ | 0 | $ | 4 | $ | 13 | ||||||||||
Rabbi Trust Funds |
$ | 3 | $ | 0 | $ | 0 | $ | 0 | $ | 3 | ||||||||||
PSE&G |
||||||||||||||||||||
Net Derivative Assets |
$ | 6 | $ | 0 | $ | 45 | $ | 0 | $ | 51 | ||||||||||
Rabbi Trust Funds |
$ | 5 | $ | 0 | $ | 0 | $ | 0 | $ | 5 |
(A) | PSEGs and Powers gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $(33) million is included in Operating Income, $(1) million is included in OCI, and $3 million is included in Income from Discontinued Operations. Of the $(33) million in Operating Income, $(32) million is unrealized and $(1) million is realized. |
41
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
(B) | Mainly includes gains/losses on PSE&Gs derivative contracts that are not included in either earnings or OCI, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&Gs customers. |
(C) | Represents $18 million in purchases. |
(D) | Includes $(11) million in issuances and $(11) million in settlements. |
(E) | PSEGs and Powers gains and losses are mainly attributable to changes in net derivative assets and liabilities of which $72 million is included in Operating Income, $20 million is included in OCI, and $22 million is included in Income from Discontinued Operations. Of the $72 million in Operating Income, $55 million is unrealized and $17 million is realized. |
As of March 31, 2011, PSEG carried $1.7 billion of net assets that are measured at fair value on a recurring basis, of which $2 million were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEGs total assets. During the quarter, $8 million of assets in the NDT fund were transferred from Level 3 to Level 2, due to more observable pricing for underlying securities. As per our company policy, this transfer was recognized as of the beginning of the quarter.
As of March 31, 2010, PSEG carried $1.7 billion of net assets that are measured at fair value on a recurring basis, of which $269 million were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy. These Level 3 net assets represent less than 1% of PSEGs total assets and there were no transfers among levels during the three months ended March 31, 2010.
Fair Value of Debt
The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of March 31, 2011 and December 31, 2010.
March 31, 2011 | December 31, 2010 | |||||||||||||||
Carrying Amount |
Fair Value (A) |
Carrying Amount |
Fair Value (A) |
|||||||||||||
Millions | ||||||||||||||||
Long-Term Debt: | ||||||||||||||||
PSEG (Parent) |
$ | 2 | $ | 30 | $ | 10 | $ | 39 | ||||||||
Power -Recourse Debt |
3,456 | 3,743 | 3,455 | 3,831 | ||||||||||||
PSE&G |
4,284 | 4,539 | 4,283 | 4,615 | ||||||||||||
Transition Funding (PSE&G) |
1,044 | 1,182 | 1,090 | 1,245 | ||||||||||||
Transition Funding II (PSE&G) |
55 | 59 | 55 | 59 | ||||||||||||
Energy Holdings: |
||||||||||||||||
Project Level, Non-Recourse Debt |
46 | 46 | 47 | 47 | ||||||||||||
$ | 8,887 | $ | 9,599 | $ | 8,940 | $ | 9,836 | |||||||||
(A) | Fair value excludes unamortized discounts, including amounts related to the Debt Exchange between Power and Energy Holdings that is deferred at the PSEG parent level since the exchange was between subsidiaries of the same parent company. |
42
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Note 12. Other Income and Deductions
Other Income | Power |
PSE&G | Other(A) | Consolidated Total |
||||||||||||
Millions | ||||||||||||||||
Three Months Ended March 31, 2011: |
||||||||||||||||
NDT Fund Gains, Interest, Dividend and Other Income |
$ | 69 | $ | 0 | $ | 0 | $ | 69 | ||||||||
Other |
1 | 5 | 1 | 7 | ||||||||||||
Total Other Income |
$ | 70 | $ | 5 | $ | 1 | $ | 76 | ||||||||
Three Months Ended March 31, 2010: |
||||||||||||||||
NDT Fund Gains, Interest, Dividend and Other Income |
$ | 38 | $ | 0 | $ | 0 | $ | 38 | ||||||||
Other |
1 | 5 | (1 | ) | 5 | |||||||||||
Total Other Income |
$ | 39 | $ | 5 | $ | (1 | ) | $ | 43 | |||||||
Other Deductions | Power | PSE&G | Other(A) | Consolidated Total |
||||||||||||
Millions | ||||||||||||||||
Three Months Ended March 31, 2011: |
||||||||||||||||
NDT Fund Realized Losses and Expenses |
$ | 9 | $ | 0 | $ | 0 | $ | 9 | ||||||||
Other |
3 | 1 | 0 | 4 | ||||||||||||
Total Other Deductions |
$ | 12 | $ | 1 | $ | 0 | $ | 13 | ||||||||
Three Months Ended March 31, 2010: |
||||||||||||||||
NDT Fund Realized Losses and Expenses |
$ | 13 | $ | 0 | $ | 0 | $ | 13 | ||||||||
Other |
1 | 1 | 1 | 3 | ||||||||||||
Total Other Deductions |
$ | 14 | $ | 1 | $ | 1 | $ | 16 | ||||||||
(A) | Other primarily consists of activity at PSEG (as parent company), Energy Holdings, Services and intercompany eliminations. |
PSEGs, Powers and PSE&Gs effective tax rates for the three months ended March 31, 2011 and 2010 were as follows:
Three Months Ended March 31, |
||||||||
2011 |
2010 |
|||||||
PSEG |
41.6 | % | 42.0 | % | ||||
Power |
41.1 | % | 41.6 | % | ||||
PSE&G |
40.5 | % | 40.6 | % |
For the quarter ended March 31, 2011, there were no material changes in the effective tax rate for PSEG, Power or PSE&G.
The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 include various health care-related provisions which will go into effect over the next several years. One of the provisions eliminates the tax deductibility of retiree health care costs, to the extent of federal subsidies
43
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. As a result, in the first quarter of 2010, PSEG recorded noncash after tax charges of $9 million for income tax expense to establish the related deferred tax liabilities, primarily related to Power. There was no immediate impact on PSE&Gs income tax expense or effective tax rate since the related amount of $78 million was deferred as a Regulatory Asset to be collected and amortized over future periods.
Two other tax provisions were enacted during 2010 that will have significant impact on PSEGs cash position. The Small Business Jobs Act of 2010, enacted September 27, 2010, extended the tax deduction for 50% bonus depreciation through 2010 for qualified property. The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010, enacted December 17, 2010, included a provision making qualified property placed into service after September 8, 2010 and before January 1, 2012, eligible for 100% bonus depreciation for tax purposes. In addition, qualified property placed into service in 2012 will be eligible for 50% bonus depreciation for tax purposes. These provisions will generate cash for PSEG through tax benefits related to the accelerated depreciation most of which is anticipated to be realized in 2011. These tax benefits would have otherwise been received over an estimated average 20 year period.
PSE&G has accrued $18 million of Investment Tax Credits (ITC) associated with alternative energy projects in the first quarter of 2011. Because the law provides an option to claim either a grant or the ITC, the ITC has been accounted for as a reduction of the book basis of the related assets as opposed to being recorded in tax expense.
PSEGs unrecognized tax benefits increased by approximately $38 million in the first quarter 2011, primarily attributable to PSE&G. This increase is primarily due to a prior period position raised by the IRS during its examination of the tax years 2004 to 2006 and a new position attributable to refund claims being filed for tax years 2004 to 2009 related to casualty loss deductions. The balance of unrecognized tax benefits that are reasonably likely to increase or decrease within the next 12 months reported at December 31, 2010, will increase by $17 million related to the prior period position discussed above.
PSEG made tax deposits with the IRS to defray interest costs associated with disputed tax assessments associated with certain lease investments. The deposits are fully refundable and are recorded as a reduction to Current Accrued Taxes on PSEGs Condensed Consolidated Balance Sheets, but are not reflected in the unrecognized tax benefits.
As a result of a change in accounting method for the capitalization of indirect costs, PSEG reduced the net amount of its uncertain tax positions (including interest) by $96 million, approximately $42 million of which related to PSE&G. It is reasonably possible that PSE&Gs claim related to this matter will be settled with the IRS in the next 12 months, resulting in an increase in the uncertain tax positions.
It is reasonably possible that unrecognized tax benefits associated with the leasing tax issue discussed in Note 8. Commitments and Contingent Liabilities, will change significantly. This change could be triggered by a settlement with the IRS or developments in other litigated cases. Based upon these developments, unrecognized tax benefits could increase by as much as $193 million or decrease by as much as $302 million. It is not possible to predict the magnitude, timing or direction of any such change.
44
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Note 14. Comprehensive Income, Net of Tax
Comprehensive Income
Power |
PSE&G |
Other(A) |
Consolidated |
|||||||||||||
Millions | ||||||||||||||||
Three Months Ended March 31, 2011 | ||||||||||||||||
Net Income |
$ | 362 | $ | 163 | $ | 1 | $ | 526 | ||||||||
Other Comprehensive Income (Loss) |
(33 | ) | 1 | 1 | (31 | ) | ||||||||||
Comprehensive Income |
$ | 329 | $ | 164 | $ | 2 | $ | 495 | ||||||||
Three Months Ended March 31, 2010 | ||||||||||||||||
Net Income |
$ | 364 | $ | 118 | $ | 9 | $ | 491 | ||||||||
Other Comprehensive Income (Loss) |
91 | 0 | 1 | 92 | ||||||||||||
Comprehensive Income |
$ | 455 | $ | 118 | $ | 10 | $ | 583 | ||||||||
(A) | Other consists of activity at PSEG (as parent company), Energy Holdings, Services and intercompany eliminations. |
Accumulated Other Comprehensive Income (Loss)
Balance as of |
Power |
PSE&G |
Other |
Balance as of |
||||||||||||||||
Millions | ||||||||||||||||||||
Derivative Contracts |
$ | 111 | $ | (32 | ) | $ | 0 | $ | 0 | $ | 79 | |||||||||
Pension and OPEB Plans |
(377 | ) | 6 | 0 | 0 | (371 | ) | |||||||||||||
NDT Funds |
109 | (7 | ) | 0 | 0 | 102 | ||||||||||||||
Other |
1 | 0 | 1 | 1 | 3 | |||||||||||||||
Accumulated Other Comprehensive Income (Loss) |
$ | (156 | ) | $ | (33 | ) | $ | 1 | $ | 1 | $ | (187 | ) | |||||||
Balance as of |
Power |
PSE&G |
Other |
Balance as of |
||||||||||||||||
Millions | ||||||||||||||||||||
Derivative Contracts |
$ | 180 | $ | 78 | $ | 0 | $ | 0 | $ | 258 | ||||||||||
Pension and OPEB Plans |
(400 | ) | 6 | 0 | 0 | (394 | ) | |||||||||||||
NDT Funds |
91 | 7 | 0 | 0 | 98 | |||||||||||||||
Other |
13 | 0 | 0 | 1 | 14 | |||||||||||||||
Accumulated Other Comprehensive Income (Loss) |
$ | (116 | ) | $ | 91 | $ | 0 | $ | 1 | $ | (24 | ) | ||||||||
45
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Note 15. Earnings Per Share (EPS)
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 or vesting of restricted stock awards granted under our stock compensation plans and upon payment of performance units or restricted stock units. The following table shows the effect of these stock options, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS:
Three Months Ended March 31, | ||||||||||||||||
2011 | 2010 | |||||||||||||||
Basic |
Diluted |
Basic |
Diluted |
|||||||||||||
EPS Numerator: |
||||||||||||||||
Earnings (Millions): | ||||||||||||||||
Continuing Operations |
$ | 462 | $ | 462 | $ | 498 | $ | 498 | ||||||||
Discontinued Operations | 64 | 64 | (7 | ) | (7 | ) | ||||||||||
Net Income |
$ | 526 | $ | 526 | $ | 491 | $ | 491 | ||||||||
EPS Denominator (Thousands): | ||||||||||||||||
Weighted Average Common Shares Outstanding |
505,979 | 505,979 | 505,950 | 505,950 | ||||||||||||
Effect of Stock Options | 0 | 155 | 0 | 141 | ||||||||||||
Effect of Stock Performance Share Units |
0 | 846 | 0 | 991 | ||||||||||||
Effect of Restricted Stock Units |
0 | 152 | 0 | 65 | ||||||||||||
Total Shares | 505,979 | 507,132 | 505,950 | 507,147 | ||||||||||||
EPS: |
||||||||||||||||
Continuing Operations | $ | 0.91 | $ | 0.91 | $ | 0.99 | $ | 0.99 | ||||||||
Discontinued Operations |
0.13 | 0.13 | (0.02 | ) | (0.02 | ) | ||||||||||
Net Income | $ | 1.04 | $ | 1.04 | $ | 0.97 | $ | 0.97 | ||||||||
Three Months Ended March 31, |
||||||||
Dividend payments on Common Stock |
2011 |
2010 |
||||||
Per Share | $ | 0.3425 | $ | 0.3425 | ||||
in Millions | $ | 173 | $ | 173 |
46
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Note 16. Financial Information by Business Segments
Power |
PSE&G |
Energy |
Other(A) |
Consolidated |
||||||||||||||||
Millions | ||||||||||||||||||||
Three Months Ended March 31, 2011 |
||||||||||||||||||||
Total Operating Revenues |
$ | 1,967 | $ | 2,306 | $ | 20 | $ | (939 | ) | $ | 3,354 | |||||||||
Income (Loss) From Continuing Operations |
298 | 163 | (3 | ) | 4 | 462 | ||||||||||||||
Income (Loss) from Discontinued Operations, including Gain on Disposal, net of tax |
64 | 0 | 0 | 0 | 64 | |||||||||||||||
Net Income (Loss) |
362 | 163 | (3 | ) | 4 | 526 | ||||||||||||||
Segment Earnings (Loss) |
362 | 163 | (3 | ) | 4 | 526 | ||||||||||||||
Gross Additions to Long-Lived Assets |
155 | 339 | 1 | 2 | 497 | |||||||||||||||
Three Months Ended March 31, 2010 |
||||||||||||||||||||
Total Operating Revenues |
$ | 2,196 | $ | 2,444 | $ | 36 | $ | (1,103 | ) | $ | 3,573 | |||||||||
Income (Loss) From Continuing Operations |
371 | 118 | 7 | 2 | 498 | |||||||||||||||
Income (Loss) from Discontinued Operations, net of tax |
(7 | ) | 0 | 0 | 0 | (7 | ) | |||||||||||||
Net Income (Loss) |
364 | 118 | 7 | 2 | 491 | |||||||||||||||
Preferred Securities Dividends |
0 | (1 | ) | 0 | 1 | 0 | ||||||||||||||
Segment Earnings (Loss) |
364 | 117 | 7 | 3 | 491 | |||||||||||||||
Gross Additions to Long-Lived Assets |
174 | 217 | 35 | 1 | 427 | |||||||||||||||
As of March 31, 2011 |
||||||||||||||||||||
Total Assets |
$ | 11,192 | $ | 16,616 | $ | 2,210 | $ | (648 | ) | $ | 29,370 | |||||||||
Investments in Equity Method Subsidiaries |
$ | 25 | $ | 0 | $ | 108 | $ | 0 | $ | 133 | ||||||||||
As of December 31, 2010 |
||||||||||||||||||||
Total Assets |
$ | 11,452 | $ | 16,873 | $ | 2,234 | $ | (650 | ) | $ | 29,909 | |||||||||
Investments in Equity Method Subsidiaries |
$ | 25 | $ | 0 | $ | 105 | $ | 0 | $ | 130 |
(A) | Other activities include amounts applicable to PSEG (as parent company), Services 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 priced in accordance with applicable regulations, including affiliate pricing rules, or 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 17. Related-Party Transactions. |
47
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Note 17. Related-Party Transactions
The following discussion relates to intercompany transactions, the majority of which are eliminated during the PSEG consolidation process in accordance with GAAP.
Power
The financial statements for Power include transactions with related parties presented as follows:
Three Months Ended March 31, |
||||||||
Related Party Transactions |
2011 |
2010 |
||||||
Millions | ||||||||
Revenue from Affiliates: |
||||||||
Billings to PSE&G through BGSS(A) |
$ | 698 | $ | 818 | ||||
Billings to PSE&G through BGS(A) |
233 | 273 | ||||||
Total Revenue from Affiliates |
$ | 931 | $ | 1,091 | ||||
Expense Billings from Affiliates: |
||||||||
Administrative Billings from Services(B) |
$ | (37 | ) | $ | (36 | ) | ||
Total Expense Billings from Affiliates |
$ | (37 | ) | $ | (36 | ) | ||
Related Party Transactions |
March 31, 2011 |
December 31, 2010 |
||||||
Millions | ||||||||
Receivables from PSE&G through BGS and BGSS(A) |
$ | 249 | $ | 372 | ||||
Receivables from PSE&G Related to Gas Supply Hedges for BGSS(A) |
26 | 58 | ||||||
Payable to Services (B) |
(27 | ) | (26 | ) | ||||
Tax Sharing Receivable from (Payable to) PSEG(C) |
(5 | ) | 380 | |||||
Current Unrecognized Tax Receivable from PSEG(C) |
2 | 1 | ||||||
Receivable from (Payable to) PSEG |
5 | (3 | ) | |||||
Accounts ReceivableAffiliated Companies, net | $ | 250 | $ | 782 | ||||
Short-Term Loan to Affiliate (demand Note to PSEG)(D) |
$ | 1,324 | $ | 398 | ||||
Working Capital Advances to Services(E) | $ | 17 | $ | 17 | ||||
Long-Term Accrued Taxes Receivable(C) |
$ | 16 | $ | 16 | ||||
PSE&G
The financials statements for PSE&G include transactions with related parties presented as follows:
Three Months Ended March 31, |
||||||||
Related Party Transactions |
2011 |
2010 |
||||||
Millions | ||||||||
Expense Billings from Affiliates: |
||||||||
Billings From Power through BGSS(A) |
$ | (698 | ) | $ | (818 | ) | ||
Billings From Power through BGS(A) |
(233 | ) | (273 | ) | ||||
Administrative Billings from Services(B) |
(51 | ) | (50 | ) | ||||
Total Expense Billings from Affiliates |
$ | (982 | ) | $ | (1,141 | ) | ||
48
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Related Party Transactions |
March 31, 2011 |
December 31, 2010 |
||||||
Millions | ||||||||
Payable to Power through BGS and BGSS(A) |
$ | (249 | ) | $ | (372 | ) | ||
Payable to Power Related to Gas Supply Hedges for BGSS(A) |
(26 | ) | (58 | ) | ||||
Payable to Power for SREC Liability(F) |
(7 | ) | (7 | ) | ||||
Payable to Services(B) |
(44 | ) | (48 | ) | ||||
Tax Sharing Receivable from PSEG(C) |
241 | 321 | ||||||
Current Unrecognized Tax Receivable from PSEG(C) |
57 | 73 | ||||||
Receivable from PSEG |
8 | 6 | ||||||
Receivable from Services(B) |
1 | 0 | ||||||
Accounts PayableAffiliated Companies, net |
$ | (19 | ) | $ | (85 | ) | ||
Working Capital Advances to Services(E) |
$ | 33 | $ | 33 | ||||
Long-Term Accrued Taxes Payable(C) |
$ | (44 | ) | $ | (74 | ) | ||
(A) | PSE&G has entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&Gs BGSS and other contractual requirements through March 31, 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. |
(B) | Services provides and bills administrative services to Power and PSE&G at cost. In addition, Power and PSE&G 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. |
(C) | PSEG files a consolidated federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits. |
PSEG and its subsidiaries follow the accounting guidance for Accounting for Uncertainty in Income Taxes, 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.
(D) | Powers short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial. |
(E) | Power and PSE&G have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on Powers and PSE&Gs Condensed Consolidated Balance Sheets. |
(F) | In January 2008, the BPU issued a decision that certain BGS suppliers will be reimbursed for the cost they incurred above $300 per Solar Renewable Energy Certificate (SREC) during the period June 1, 2008 through May 31, 2010. The BPU order further provided that the excess cost may be passed on to ratepayers. Following an appeal, on March 10, 2011, the New Jersey Supreme Court reversed and remanded the BPUs 2008 order. The Court did not rule on the substantive issue of whether the pass-through of SREC costs was appropriate. The BPU is expected to begin a legislative hearing process to comply with the Courts ruling in the next few months. PSE&G has estimated and accrued a total liability for the excess SREC cost of $17 million as of March 31, 2011 and December 31, 2010, including approximately $7 million for Powers share which is included in PSE&Gs Accounts PayableAffiliated Companies. Under current guidance, Power is unable to record the related intercompany receivable on its Condensed Consolidated Balance Sheet. As a result, PSE&Gs liability to Power is not eliminated in consolidation and is included in Other Current Liabilities on PSEGs Condensed Consolidated Balance Sheet as of March 31, 2011 and December 31, 2010. |
49
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Each series of Powers Senior Notes, Pollution Control Notes and its syndicated revolving credit facilities are fully and unconditionally and jointly and severally guaranteed by PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear), and PSEG Energy Resources & Trade LLC (ER&T). The following table presents condensed financial information for the guarantor subsidiaries, as well as Powers non-guarantor subsidiaries.
Power |
Guarantor |
Other |
Consolidating |
Consolidated |
||||||||||||||||
Millions | ||||||||||||||||||||
Three Months Ended March 31, 2011 |
||||||||||||||||||||
Operating Revenues |
$ | 0 | $ | 2,278 | $ | 50 | $ | (361 | ) | $ | 1,967 | |||||||||
Operating Expenses |
2 | 1,774 | 52 | (362 | ) | 1,466 | ||||||||||||||
Operating Income (Loss) |
(2 | ) | 504 | (2 | ) | 1 | 501 | |||||||||||||
Equity Earnings (Losses) of Subsidiaries |
382 | 60 | 0 | (442 | ) | 0 | ||||||||||||||
Other Income |
10 | 71 | 0 | (11 | ) | 70 | ||||||||||||||
Other Deductions |
(3 | ) | (9 | ) | 0 | 0 | (12 | ) | ||||||||||||
Other-Than-Temporary Impairments |
(1 | ) | (1 | ) | 0 | 0 | (2 | ) | ||||||||||||
Interest Expense |
(45 | ) | (11 | ) | (5 | ) | 10 | (51 | ) | |||||||||||
Income Tax Benefit (Expense) |
21 | (232 | ) | 3 | 0 | (208 | ) | |||||||||||||
Income (Loss) on Discontinued Operations, net of tax |
0 | 0 | 64 | 0 | 64 | |||||||||||||||
Net Income (Loss) |
$ | 362 | $ | 382 | $ | 60 | $ | (442 | ) | $ | 362 | |||||||||
Three Months Ended March 31, 2011 |
||||||||||||||||||||
Net Cash Provided By (Used In) Operating Activities |
$ | 350 | $ | 1,202 | $ | (189 | ) | $ | (460 | ) | $ | 903 | ||||||||
Net Cash Provided By (Used In) Investing Activities |
$ | (175 | ) | $ | (777 | ) | $ | 336 | $ | (113 | ) | $ | (729 | ) | ||||||
Net Cash Provided By (Used In) Financing Activities |
$ | (175 | ) | $ | (426 | ) | $ | (147 | ) | $ | 573 | $ | (175 | ) | ||||||
Three Months Ended March 31, 2010 |
||||||||||||||||||||
Operating Revenues |
$ | 0 | $ | 2,474 | $ | 38 | $ | (316 | ) | $ | 2,196 | |||||||||
Operating Expenses |
(2 | ) | 1,822 | 41 | (316 | ) | 1,545 | |||||||||||||
Operating Income (Loss) |
2 | 652 | (3 | ) | 0 | 651 | ||||||||||||||
Equity Earnings (Losses) of Subsidiaries |
377 | (14 | ) | 0 | (363 | ) | 0 | |||||||||||||
Other Income |
9 | 41 | 0 | (11 | ) | 39 | ||||||||||||||
Other Deductions |
(1 | ) | (13 | ) | 0 | 0 | (14 | ) | ||||||||||||
Other-Than-Temporary Impairments |
0 | (1 | ) | 0 | 0 | (1 | ) | |||||||||||||
Interest Expense |
(31 | ) | (14 | ) | (6 | ) | 11 | (40 | ) | |||||||||||
Income Tax Benefit (Expense) |
8 | (274 | ) | 2 | 0 | (264 | ) | |||||||||||||
Income (Loss) on Discontinued Operations, net of tax |
0 | 0 | (7 | ) | 0 | (7 | ) | |||||||||||||
Net Income (Loss) |
$ | 364 | $ | 377 | $ | (14 | ) | $ | (363 | ) | $ | 364 | ||||||||
Three Months Ended March 31, 2010 |
||||||||||||||||||||
Net Cash Provided By (Used In) Operating Activities |
$ | 343 | $ | 999 | $ | (14 | ) | $ | (380 | ) | $ | 948 | ||||||||
Net Cash Provided By (Used In) Investing Activities |
$ | (170 | ) | $ | (1,010 | ) | $ | 0 | $ | 506 | $ | (674 | ) | |||||||
Net Cash Provided By (Used In) Financing Activities |
$ | (174 | ) | $ | 8 | $ | (31 | ) | $ | (128 | ) | $ | (325 | ) |
50
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Power | Guarantor Subsidiaries |
Other Subsidiaries |
Consolidating Adjustments |
Consolidated Total |
||||||||||||||||
Millions | ||||||||||||||||||||
As of March 31, 2011 |
||||||||||||||||||||
Current Assets |
$ | 4,259 | $ | 6,930 | $ | 1,059 | $ | (9,090 | ) | $ | 3,158 | |||||||||
Property, Plant and Equipment, net |
56 | 5,404 | 909 | 0 | 6,369 | |||||||||||||||
Investment in Subsidiaries |
4,586 | 964 | 0 | (5,550 | ) | 0 | ||||||||||||||
Noncurrent Assets |
167 | 1,547 | 41 | (90 | ) | 1,665 | ||||||||||||||
Total Assets |
$ | 9,068 | $ | 14,845 | $ | 2,009 | $ | (14,730 | ) | $ | 11,192 | |||||||||
Current Liabilities |
$ | 846 | $ | 8,944 | $ | 911 | $ | (9,090 | ) | $ | 1,611 | |||||||||
Noncurrent Liabilities |
301 | 1,318 | 131 | (90 | ) | 1,660 | ||||||||||||||
Long-Term Debt |
2,740 | 0 | 0 | 0 | 2,740 | |||||||||||||||
Members Equity |
5,181 | 4,583 | 967 | (5,550 | ) | 5,181 | ||||||||||||||
Total Liabilities and Members Equity |
$ | 9,068 | $ | 14,845 | $ | 2,009 | $ | (14,730 | ) | $ | 11,192 | |||||||||
As of December 31, 2010 |
||||||||||||||||||||
Current Assets |
$ | 3,988 | $ | 6,807 | $ | 1,117 | $ | (8,468 | ) | $ | 3,444 | |||||||||
Property, Plant and Equipment, net |
55 | 5,385 | 902 | 0 | 6,342 | |||||||||||||||
Investment in Subsidiaries |
4,794 | 1,079 | 0 | (5,873 | ) | 0 | ||||||||||||||
Noncurrent Assets |
170 | 1,549 | 41 | (94 | ) | 1,666 | ||||||||||||||
Total Assets |
$ | 9,007 | $ | 14,820 | $ | 2,060 | $ | (14,435 | ) | $ | 11,452 | |||||||||
Current Liabilities |
$ | 751 | $ | 8,519 | $ | 849 | $ | (8,468 | ) | $ | 1,651 | |||||||||
Noncurrent Liabilities |
423 | 1,510 | 129 | (93 | ) | 1,969 | ||||||||||||||
Long-Term Debt |
2,805 | 0 | 0 | 0 | 2,805 | |||||||||||||||
Members Equity |
5,028 | 4,791 | 1,082 | (5,874 | ) | 5,027 | ||||||||||||||
Total Liabilities and Members Equity |
$ | 9,007 | $ | 14,820 | $ | 2,060 | $ | (14,435 | ) | $ | 11,452 | |||||||||
51
ITEM 2. | MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A) |
This combined MD&A is separately filed by PSEG, Power and PSE&G. Information contained herein relating to any individual company is filed by such company on its own behalf. Power and PSE&G each make representations only as to itself and make no representations whatsoever as to any other company.
PSEGs business consists of three reportable segments, which are:
| Power, our wholesale energy supply company that integrates its generating asset operations with its wholesale energy, fuel supply, energy trading and marketing and risk management activities primarily in the Northeast and Mid Atlantic U.S., |
| PSE&G, our public utility company which provides transmission and distribution of electric energy and gas in New Jersey; implements demand response and energy efficiency programs and invests in solar generation, and |
| Energy Holdings, which owns our energy-related leveraged leases and other investments. |
Our discussion in Part I, Item 1. Business of our 2010 Annual Report on Form 10-K provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets. Our risk factors section in Part II Item 1A provides information about factors that could have a material adverse impact on our businesses. The following supplements that discussion and the discussion included in the Overview of 2010 and Future Outlook provided in Item 7 in our Form 10-K by describing significant events and business developments that have occurred during 2011 and any changes to the key factors that we expect may drive our future performance. The following discussion refers to the Condensed Consolidated Financial Statements (Statements) and the Related Notes to Condensed Consolidated Financial Statements (Notes). This information should be read in conjunction with such Statements, Notes and the 2010 Annual Report on Form 10-K.
OVERVIEW OF 2011 AND FUTURE OUTLOOK
During the first quarter of 2011, we continued to be impacted by lower pricing at Power. We anticipate a greater impact beginning later in the year due to a significant decline in both PJM Reliability Pricing Model (RPM) and Basic Generation Service (BGS) rates which become effective in the second quarter. Our pricing also continues to be impacted by customer migration away from our BGS supply contracts as these volumes are replaced with lower priced spot market sales.
Partially offsetting this lower pricing at Power, our utility operations are expected to benefit from a full year of distribution rate relief from the base rate case settlement in 2010, which included an increase of $73.5 million and $26.5 million in annual electric and gas revenues, respectively, with a return on equity (ROE) of 10.3%. The new electric rates were effective on June 7, 2010 and the new gas rates were effective on July 9, 2010. We also expect an increase in transmission revenues from our 2011 Annual Formula Rate Update which provides for approximately $45 million in increased revenues in our 2011 transmission rates effective January 1, 2011.
In addition, our gas sales volumes improved for the first quarter of 2011 compared to the same period in 2010, due primarily to colder winter weather this year. Heating degree days, as a measure of winter weather in 2011, were 6% higher than in 2010. This favorable weather impact was partially offset by the gas weather normalization clause which was implemented effective with the base rate case settlement last year. The weather, the economy and other factors all contributed to an overall increase of approximately 2% in Powers Basic Gas Supply Service (BGSS) sales volumes and PSE&Gs gas delivery volumes as compared to 2010.
For 2011 and beyond, the key issues our business will confront are:
| potential for sustained lower natural gas and electricity prices, |
| uncertainty in the economic recovery, |
| regulatory and political uncertainty, particularly around environmental regulation, and |
| pressure on competitive markets in many states, including New Jersey. |
52
Our future success will also depend on our ability to respond to these challenges and take advantage of opportunities presented by these and other regulatory and legislative initiatives. In order to do this, we must:
| focus on controlling costs while maintaining our safety, reliability and compliance standards, |
| successfully recontract open positions, and |
| execute our capital investment program, including continued investments for growth that yield contemporaneous returns. |
There have also been other significant regulatory and legislative developments during the year which may affect our operations in the future as new rules and regulations are adopted. For additional information on these issues, see Part II, Item 5. Other Information.
| In an attempt to stimulate the development of new generation capacity in New Jersey through a subsidized rate mechanism, in January 2011, New Jersey enacted the long-term capacity agreement pilot program Act (LCAPP) directing the New Jersey Board of Public Utilities (BPU) to conduct a process to procure and subsidize up to 2,000 megawatts of baseload or mid-merit electric power generation. This could result in artificially depressed pricing in the competitive wholesale market and thus has the potential to harm competitive markets, on both a short-term and a long-term basis. In March 2011, the BPU issued a written order approving a form of agreement and selecting three generators to build a total of 1,949 MWs of new combined-cycle generating facilities located in New Jersey. Each of the New Jersey electric distribution companies, including PSE&G, executed standard offer capacity agreements (SOCA) with the three generators in compliance with the BPUs directive, but did so under protest reserving its legal rights. On April 27, 2011, the BPU approved the executed contracts and also announced that it will convene a proceeding to consider whether current mechanisms are adequate to incent needed generation construction in New Jersey. |
The SOCA requires that the generator bid in and clear the PJM RPM base residual auction in each year of the SOCA term. The SOCA provides for the EDCs to make capacity payments to, or receive capacity payments from, the generators as calculated based on the difference between the RPM clearing price for each year of the term and the price bid and accepted for that generator in the BPU process. On April 12, 2011, the Federal Energy regulatory Commission (FERC) issued an order making effective changes to the PJM Tariff that would require new generation to clear in the RPM at competitive prices. In response to this decision the BPU has indicated that it may pursue other available options.
Various challenges relating to LCAPP legislation which were made by us and other parties are currently pending.
| The U.S. Environmental Protection Agency (EPA) published a proposed rule in April 2011 related to 316(b) Clean Water Act requirements. The proposed rule would establish a separate marine life entrainment mortality standard as well as new impingement mortality standards for certain existing cooling water intake structures. If the rule were to be adopted as proposed, the majority of our electric generating facilities could be affected as they employ once-through cooling utilizing tidal river and tidal waters. We are unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take or the effect, if any, that they may have on our future capital requirements, financial condition or results of operations which could be material. |
| As a result of events at the Fukushima Daiichi nuclear facility in Japan following the earthquake and tsunami in March 2011, the Nuclear Regulatory Commission (NRC) will be performing additional operational and safety reviews of nuclear facilities in the United States. These reviews and the lessons learned from the events in Japan may result in additional regulation for the nuclear industry and could impact future operations and capital requirements for our facilities. We believe that our nuclear plants meet the stringent applicable design and safety specifications of the NRC. In addition, in April 2011, a petition was filed with the NRC seeking suspension of the operating licenses of all General Electric (GE) boiling water reactors (BWRs) utilizing the Mark 1 containment design in the United States, including our Hope Creek and Peach Bottom units, pending completion of the NRC review. The |
53
petition names 23 of the total 104 active commercial nuclear reactors in the United States. While we do not believe the petition will be successful, we are unable to predict the outcome of any action that the NRC may take in connection with its operational and safety reviews or any other regulatory or industry responses to the events in Japan. |
| During 2011, the SEC and the Commodity Futures Trading Commission (CFTC) are continuing efforts to implement new rules to enact stricter regulation over swaps and derivatives. CFTC has issued Notices of Proposed Rulemakings (NOPRs) on many of the key issues. We cannot assess the exact scope of the new rules until they are issued by the SEC and CFTC. We will carefully monitor these new rules as they are developed to analyze the potential impact on our swap and derivatives transactions, including any potential increase in our collateral requirements. |
| We expect the BPU to release a new draft Energy Master Plan (EMP) during the first half of 2011 with a final plan expected to be completed later next year. We cannot predict what modifications or new goals will be included in the new EMP or the potential impacts to our businesses. |
Operational Excellence
Our generating stations continued to perform well in 2011. Generation volumes for the first quarter of 2011 were approximately 1% lower than in the first quarter of 2010, primarily at our coal facilities.
In addition, PSE&G continued to demonstrate its commitment to system reliability by limiting customer outages. In February 2011, our service territory experienced winter storms that impacted the electric transmission and distribution systems due to heavy icing and salt spray and in March 2011, our northern gas service territory was impacted by two heavy rainstorms that resulted in widespread flooding. Our personnel were prepared in each case for widespread outages and, as a result, were able to minimize the length of time our customers were without electric or gas service.
Financial Strength
Our cash from operations is expected to remain strong. During the first quarter, we made $497 million in capital expenditures, paid dividends of $173 million and made our entire planned pension contributions for the year 2011 of over $400 million. Cash from operations for the year is expected to benefit from two tax provisions enacted in 2010 which are expected to generate approximately $750 million of cash benefits for us through accelerated depreciation, most of which is expected to be realized in 2011. See Note 13. Income Taxes for additional information. These funds, combined with proceeds from the sales of our Texas facilities, will be used to support our anticipated capital expenditures in 2011 and dividend payments.
Disciplined Investment
We seek to invest in areas that complement our existing businesses and provide attractive risk-adjusted returns. These areas include upgrading critical energy infrastructure, responding to trends in environmental protection and providing new energy supplies in markets with growing demand. We also have several projects where we are investing to continue to improve our operational performance.
| In January 2011, we reached agreement to sell our two 1,000 MW combined-cycle generating facilities in Texas in separate transactions for a total of approximately $687 million. In March 2011, we completed the sale of one plant for $351 million. The sale of the second plant is expected to be closed in the second quarter of 2011. |
| We are continuing to pursue obtaining the necessary regulatory approvals for the Susquehanna-Roseland transmission project but have incurred delays in obtaining environmental approvals. The failure to obtain these approvals on a timely basis has delayed the project implementation date. The estimated cost of construction is up to $750 million for this project. In October, the PJM Board approved a modified Branchburg to Hudson project, specifically a 230 kV project running from Roseland to Hudson. The Roseland to Hudson project has an expected in-service date of June 2015. The estimated cost of construction is up to $700 million for this project. Delays in the construction schedules of these projects could impact the timing of expected transmission revenues. |
54
| In April 2011, we filed a petition with FERC seeking incentive rates with an effective date of June 14, 2011 for five 230 kV transmission projects with a total estimated capital investment of approximately $1.3 billion. |
| Our utility has made additional investments in solar initiatives. Under our solar loan program we have provided a total of $80 million in loans for 246 projects as of March 31, 2011, representing 22 MW to date. Under our Solar 4 All program we have had total program expenditures of approximately $260 million as of March 31, 2011. Over 18 MW of solar panels have been installed on distribution poles and another 19 MW representing 13 projects have been placed into service. Additional projects are in various stages of negotiation and development. Our total anticipated expenditures to develop all 80 MW approved is approximately $465 million. See Note 8. Commitments and Contingent Liabilities for additional information. |
| We made additional expenditures under our Capital Economic Stimulus and Energy Efficiency Economic Stimulus programs. As of March 31, 2011, total expenditures since inception of these projects were $660 million and $107 million, respectively. |
| We continued various construction activities at Power, including a steam path retrofit and extended power uprate at Peach Bottom and construction of new gas fired peaking units at Kearny and in Connecticut (see Note 8. Commitments and Contingent Liabilities for additional information). This additional capacity at Kearny was bid into and has cleared the RPM capacity auction, and the additional capacity in Connecticut is subject to a contract with a Connecticut utility. |
| We are continuing to pursue 20-year license extensions for our Salem and Hope Creek facilities and continuing our efforts to obtain an Early Site Permit for a new nuclear generating station to be located at the current site of those stations. We expect a decision from the NRC regarding our license extension requests later this summer. |
There is no guarantee that the projects described above or any future initiatives will be achieved since many issues need to be favorably resolved, such as regulatory approvals.
Our leveraged lease investments face risks with regard to the creditworthiness of the various counterparties. In March 2011, S&P downgraded one of these counterparties from B to CC. See Note 5. Financing Receivables for further information.
The results for PSEG, PSE&G, Power and Energy Holdings for the three months ended March 31, 2011 and 2010 are presented below:
Three Months Ended March 31, |
||||||||
Earnings (Losses) |
2011 |
2010 |
||||||
Millions | ||||||||
Power |
$ | 298 | $ | 371 | ||||
PSE&G |
163 | 118 | ||||||
Energy Holdings |
(3 | ) | 7 | |||||
Other (A) |
4 | 2 | ||||||
PSEG Income from Continuing Operations |
462 | 498 | ||||||
PSEG Income (Loss) from Discontinued Operations (B) |
64 | (7 | ) | |||||
PSEG Net Income |
$ | 526 | $ | 491 | ||||
55
Three Months Ended March 31, |
||||||||
Earnings Per Share (Diluted) |
2011 |
2010 |
||||||
PSEG Income from Continuing Operations |
$ | 0.91 | $ | 0.99 | ||||
Income (Loss) from Discontinued Operations |
0.13 | (0.02 | ) | |||||
PSEG Net Income |
$ | 1.04 | $ | 0.97 | ||||
(A) | Other primarily includes parent company interest and financing costs, donations and certain administrative and general expenses. |
(B) | See Note 4. Discontinued Operations and Dispositions. |
Our results include the realized gains, losses and earnings on Powers Nuclear Decommissioning Trust (NDT) funds and other related NDT activity. This includes the net realized gains, interest and dividend income and other costs related to the NDT funds which are recorded in Other Income and Deductions. This also includes credit-related impairments on certain NDT securities which are included in Other-Than-Temporary Impairments and the interest accretion expense on Powers nuclear asset retirement obligation (ARO), which is recorded in Operation and Maintenance Expense and the depreciation expense related to the ARO.
Our results also include the after-tax impacts of non-trading mark-to-market (MTM) activity.
The quarter-over-quarter decreases in our Income from Continuing Operations include the changes related to NDT and MTM shown in the chart below:
Three Months Ended March 31, |
||||||||
2011 |
2010 |
|||||||
Millions, after tax | ||||||||
NDT Fund Income (Expense) |
$ | 27 | $ | 10 | ||||
Non-Trading Mark-to-Market Gains (Losses) |
$ | 4 | $ | 49 |
In addition to the changes in NDT and MTM, our decrease in Income from Continuing Operations for the three months ended March 31, 2011 was driven primarily by:
| losses on certain wholesale electric energy supply contracts, |
| higher interest costs and depreciation expense related to the completion of installation of back end technology at two of our fossil plants, |
| partially offset by higher transmission and distribution rates, and |
| higher gas delivery volumes. |
56
PSEG
Our results of operations are primarily comprised of the results of operations of our operating subsidiaries, Power, PSE&G and Energy Holdings, excluding charges related to intercompany transactions, which are eliminated in consolidation. We also include certain financing costs, charitable contributions and general and administrative costs at the parent company. For additional information on intercompany transactions, see Note 17. Related-Party Transactions. For an explanation of the variances, see the discussions for Power, PSE&G and Energy Holdings that follow the table below.
For the Three Months Ended March 31, |
Increase / (Decrease) |
|||||||||||||||
2011 |
2010 |
2011 vs 2010 |
||||||||||||||
Millions | Millions | % | ||||||||||||||
Operating Revenues |
$ | 3,354 | $ | 3,573 | $ | (219 | ) | (6 | ) | |||||||
Energy Costs |
1,563 | 1,688 | (125 | ) | (7 | ) | ||||||||||
Operation and Maintenance |
651 | 670 | (19 | ) | (3 | ) | ||||||||||
Depreciation and Amortization |
241 | 227 | 14 | 6 | ||||||||||||
Income from Equity Method Investments |
3 | 3 | 0 | 0 | ||||||||||||
Other Income and (Deductions) |
63 | 27 | 36 | N/A | ||||||||||||
Other-Than-Temporary Impairments |
4 | 1 | 3 | 300 | ||||||||||||
Interest Expense |
127 | 116 | 11 | 9 | ||||||||||||
Income Tax Expense |
329 | 361 | (32 | ) | (9 | ) | ||||||||||
Income (Loss) from Discontinued Operations, including Gain on Sale in 2011, net of tax |
64 | (7 | ) | 71 | N/A |
Power
Three Months Ended March 31, |
Increase (Decrease) |
|||||||||||
2011 |
2010 |
2011 vs 2010 |
||||||||||
Millions | ||||||||||||
Income from Continuing Operations |
$ | 298 | $ | 371 | $ | (73 | ) | |||||
Income (Loss) from Discontinued Operations, net of tax |
$ | 64 | $ | (7 | ) | $ | 71 | |||||
Net Income |
$ | 362 | $ | 364 | $ | (2 | ) |
For the three months ended March 31, 2011 the primary reasons for the $73 million decrease in Income from Continuing Operations were
| a decrease in amounts related to our MTM activity, |
| losses on certain wholesale electric energy supply contracts, |
| higher operation and maintenance expense related to refurbishments at certain of our fossil plants, and |
| higher interest costs and depreciation expense related to the completion of installation of back end technology at two of our fossil plants, |
| partially offset by lower fossil fuel costs used to generate electricity and lower congestion charges in 2011 in PJM, and |
| favorable amounts related to our NDT activity. |
57
The quarter-over-quarter details for these variances are discussed below:
Three Months Ended March 31, |
Increase / (Decrease) |
|||||||||||||||
Power | 2011 |
2010 |
2011 vs 2010 |
|||||||||||||
Millions | Millions | % | ||||||||||||||
Operating Revenues |
$ | 1,967 | $ | 2,196 | $ | (229 | ) | (10 | ) | |||||||
Energy Costs |
1,135 | 1,251 | (116 | ) | (9 | ) | ||||||||||
Operation and Maintenance |
277 | 251 | 26 | 10 | ||||||||||||
Depreciation and Amortization |
54 | 43 | 11 | 26 | ||||||||||||
Other Income (Deductions) |
58 | 25 | 33 | 132 | ||||||||||||
Other-Than-Temporary Impairments |
2 | 1 | 1 | 100 | ||||||||||||
Interest Expense |
51 | 40 | 11 | 28 | ||||||||||||
Income Tax Expense |
208 | 264 | (56 | ) | (21 | ) | ||||||||||
Income (Loss) from Discontinued Operations |
64 | (7 | ) | 71 | N/A |
For the three months ended March 31, 2011 as compared to 2010
Operating Revenues decreased $229 million due to
Generation Revenues decreased $118 million due primarily to
| lower net revenues of $97 million resulting principally from less favorable results from financial hedging transactions in the PJM, NE and NY power pools partly offset by higher volumes of generation sold in PJM, and |
| a net decrease of $59 million due to a lower volume of electricity sold under our BGS contracts, reflecting customer migration to alternative suppliers, |
| partially offset by an increase of $40 million from new wholesale load contracts in PJM and the NE regions commencing in January 2011 and May 2010, respectively. |
Gas Supply Revenues decreased $84 million
| including a net decrease of $108 million in sales under the BGSS contract, substantially comprised of lower average gas sales prices partially mitigated by increased volumes of sales and higher net gains on financial hedging transactions in 2011, |
| partially offset by a net increase of $24 million due to higher sales volumes at lower average prices to third party customers. |
Trading Revenues decreased $27 million due primarily to net losses on certain electric energy supply contracts in 2011.
Operating Expenses
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 Powers obligation under its BGSS contract with PSE&G. Energy Costs decreased by $116 million due to
| Gas costs decreased $85 million, principally related to Powers obligations under the BGSS contract, reflecting lower average gas inventory costs partially offset by higher demand as well as higher demand by third party customers. |
| Generation costs decreased $31 million due primarily to $32 million of lower net fossil fuel costs, primarily reflecting the utilization of lower volumes of coal partially offset by higher coal costs and the lower cost of natural gas on higher volumes, $25 million of lower net congestion charges incurred in 2011 from PJM and higher net gains of $8 million from financial hedging transactions. These decreases were partly offset by an increase of $35 million in spot energy purchases in 2011 in the NE and PJM power pools. |
58
Operation and Maintenance increased $26 million due primarily to
| a $21 million net increase due largely to hot gas path inspection outage costs at our gas-fired Bethlehem Energy and Linden facilities in New York and New Jersey, respectively, as well as to higher outage costs at our coal-fired Keystone facility in Pennsylvania, and |
| an increase of $4 million due to refurbishment projects in the first quarter of 2011 at our Peach Bottom nuclear facility and typical annual increases in Nuclear Regulatory Commission inspection fees and state licensing permit fees. |
Depreciation and Amortization increased $11 million due primarily to the completion of the installation of back end technology at the end of 2010 at our Mercer and Hudson generating facilities.
Other Income and (Deductions)The net increase of $33 million was due primarily to $36 million of higher net realized gains on the NDT funds mainly resulting from the liquidation of an underperforming fund in 2011 and a rebalancing to move toward our target asset allocation.
Other-Than-Temporary Impairments experienced no material change.
Interest Expense increased $11 million due primarily to lower capitalized interest resulting primarily from the installation by year-end 2010 of back end technology at our Mercer and Hudson fossil stations.
Income Tax Expense decreased $56 million in 2011 due primarily to lower pre-tax income.
Income (Loss) from Discontinued Operations
In January 2011, we reached agreement to sell our two 1,000 MW combined-cycle generating facilities in Texas in separate transactions for a total of approximately $687 million. In March 2011, we completed the sale of one plant for proceeds of $351 million at an after-tax gain of $53 million. The sale of the second plant is expected to be closed in the second quarter of 2011. The results of operations for both plants, including the gain on sale are included in this category.
See Note 4. Discontinued Operations and Dispositions for additional information.
PSE&G
Three Months Ended March 31, |
Increase (Decrease) |
|||||||||||
2011 |
2010 |
2011 vs 2010 |
||||||||||
Millions | ||||||||||||
Income from Continuing Operations |
$ | 163 | $ | 118 | $ | 45 | ||||||
Net Income |
$ | 163 | $ | 118 | $ | 45 |
For the three months ended March 31, 2011, the primary reasons for the $45 million increase in Income from Continuing Operations were
| higher base rates for electric and gas delivery as well as transmission, |
| higher gas delivery volumes, and |
| lower operation and maintenance expense. |
59
The quarter-over-quarter details for these variances are discussed below:
Three Months Ended March 31, |
Increase / (Decrease) |
|||||||||||||||
PSE&G | 2011 |
2010 |
2011 vs 2010 |
|||||||||||||
Millions | Millions | % | ||||||||||||||
Operating Revenues |
$ | 2,306 | $ | 2,444 | $ | (138 | ) | (6 | ) | |||||||
Energy Costs |
1,366 | 1,540 | (174 | ) | (11 | ) | ||||||||||
Operation and Maintenance |
368 | 414 | (46 | ) | (11 | ) | ||||||||||
Depreciation and Amortization |
179 | 177 | 2 | 1 | ||||||||||||
Other Income (Deductions) |
4 | 4 | 0 | N/A | ||||||||||||
Other-Than-Temporary Impairments |
1 | 0 | 1 | 100 | ||||||||||||
Interest Expense |
79 | 77 | 2 | 3 | ||||||||||||
Income Tax Expense |
111 | 80 | 31 | 39 |
For the three months ended March 31, 2011 as compared to 2010
Operating Revenues decreased $138 million due primarily to
Commodity Revenue decreased $174 million due to lower Electric and Gas revenues. This is entirely offset as savings in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS.
| Gas revenues decreased $138 million due to lower BGSS prices of $164 million, partially offset by higher BGSS volumes of $26 million due to colder weather. The average price of gas was 20% lower in 2011 than in 2010. |
| Electric revenues decreased $36 million due primarily to $55 million in lower BGS revenues, partially offset by $19 million in higher revenues from the sale of Non-Utility Generation (NUG) energy and collections of non-utility generation charges (NGC) due primarily to higher prices. BGS sales were down 13% due primarily to large customer migration to third party suppliers (TPS); in contrast delivery sales were up 1% due to colder weather. |
Clause Revenues decreased $4 million due primarily to lower Securitization Transition Charge (STC) revenues of $20 million, which were partially offset by a higher Electric Societal Benefit Charge (SBC) of $16 million. The changes in STC and SBC amounts were entirely offset by the amortization of related costs (Regulatory Assets) in Operation and Maintenance, Depreciation and Amortization and Interest Expense. PSE&G earns no margins on SBC or STC collections.
Delivery Revenues increased $37 million due primarily to an increase in prices for electric and gas distribution and transmission.
| Electric distribution revenues were up $5 million due primarily to the impact of the June base rate increases of $6 million and higher sales volumes of $3 million, partially offset by lower stimulus revenue of $4 million. |
| Transmission revenues were up $7 million due primarily to net rate increases. |
| Gas distribution revenues were up $25 million due primarily to the impact of the July base rate increase of $19 million and higher sales volumes of $13 million, partially offset by lower capital stimulus revenue of $7 million. |
Other Operating Revenues increased $3 million due primarily to increased revenues from our appliance repair business and miscellaneous electric operating revenues.
Energy Costs decreased $174 million. This is entirely offset by Commodity Revenue. Details are as follows:
| Gas costs decreased $138 million due to $164 million or 20% in lower prices, partially offset by $26 million or 3% in higher sales volumes due primarily to colder weather. |
60
| Electric costs decreased $36 million due to $87 million or 12% in lower BGS and NUG volumes due to large customer migration to TPS and NUG operations, partially offset by $11 million of higher BGS and NUG prices and $40 million for increased deferred cost recovery. |
Operation and Maintenance decreased $46 million due to
| $14 million of lower net expenses associated with SBC, RGGI and Stimulus clauses, |
| a $14 million reduction in storm restoration work, |
| a $13 million decrease in pension and OPEB expenses, and |
| a $4 million reduction in incentive payments. |
Depreciation and Amortization increased $2 million due primarily to
| an increase of $8 million for additional plant in service, and |
| an increase of $2 million in software amortization, |
| partially offset by a decrease of $8 million for amortization of Regulatory Assets. |
Other-Than-Temporary Impairments experienced no material change.
Interest Expense increased $2 million due primarily to higher average debt balances.
Income Tax Expense increased $31 million due primarily to higher pre-tax income.
Energy Holdings
Three Months Ended March 31, |
Increase (Decrease) |
|||||||||||
2011 |
2010 |
2011 vs 2010 |
||||||||||
Millions | ||||||||||||
Income from Continuing Operations |
$ | (3 | ) | $ | 7 | $ | (10 | ) | ||||
Net Income |
$ | (3 | ) | $ | 7 | $ | (10 | ) |
For the three months ended March 31, 2011, the primary reason for the $10 million decrease in Income from Continuing Operations was the absence of any sales of leveraged lease assets in 2011, as compared to gains on sales of leveraged lease assets in 2010.
LIQUIDITY AND CAPITAL RESOURCES
The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our three direct operating subsidiaries.
Operating Cash Flows
Our operating cash flows combined with cash on hand and financing activities are expected to be sufficient to fund capital expenditures and shareholder dividend payments.
For the three months ended March 31, 2011, our operating cash flow decreased $30 million as compared to the same period in 2010. The net change was due primarily to net changes from Power, PSE&G and Energy Holdings, as discussed below.
Power
Powers operating cash flow decreased $45 million from $948 million to $903 million for the three months ended March 31, 2011, as compared to the same period in 2010, primarily resulting from lower earnings for the quarter combined with
| a decrease of $131 million from higher net payments of counterparty payables, |
| $46 million in higher benefit plan funding, and |
| $77 million in higher net cash collateral payments, |
61
| partially offset by a $166 million increase in net collection of counterparty receivables, and |
| a $44 million net increase in other working capital. |
PSE&G
PSE&Gs operating cash flow decreased $3 million from $160 million to $157 million for the three months ended March 31, 2011, as compared to the same period in 2010, due primarily to an increase of $108 million in pension fund contributions and related payments offset by
| $51 million in higher collections of customer receivables, |
| $44 million of cash savings primarily due to a decrease in accrued federal income taxes, and |
| higher earnings. |
Energy Holdings
Energy Holdings operating cash flow improved $22 million for the three months ended March 31, 2011, as compared to the same period in 2010, primarily due to a net increase in working capital.
Short-Term Liquidity
PSEG meets its short-term liquidity requirements, as well as those of Power, primarily through the issuance of commercial paper. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Both commercial paper programs are fully back-stopped by their own separate credit facilities.
The commitments under PSEGs credit facilities are provided by a diverse bank group. As of March 31, 2011, no single institution represented more than 11% of the total commitments in our credit facilities.
As of March 31, 2011, our total credit capacity was in excess of our anticipated maximum liquidity requirements thorough 2011.
Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries liquidity needs. Our total credit facilities and available liquidity as of March 31, 2011 were as follows:
As of March 31, 2011 |
||||||||||||||||||
Company/Facility |
Total |
Usage |
Available |
Expiration |
Primary Purpose | |||||||||||||
Millions | ||||||||||||||||||
PSEG |
||||||||||||||||||
5-year Credit Facility (A) |
$ | 1,000 | $ | 14 | (C) | $ | 986 | Dec 2012 | Commercial Paper (CP) Support/Funding/Letters of Credit | |||||||||
Total PSEG |
$ | 1,000 | $ | 14 | $ | 986 | ||||||||||||
Power |
||||||||||||||||||
5-year Credit Facility (B) |
$ | 1,600 | $ | 184 | (C) | $ | 1,416 | Dec 2012 | Funding/Letters of Credit | |||||||||
2-year Credit Facility |
350 | 0 | 350 | July 2011 | Funding | |||||||||||||
Bilateral Credit Facility |
100 | 100 | (C) | 0 | Sept 2015 | Letters of Credit | ||||||||||||
Total Power |
$ | 2,050 | $ | 284 | $ | 1,766 | ||||||||||||
PSE&G |
||||||||||||||||||
5-year Credit Facility |
$ | 600 | $ | 21 | $ | 579 | June 2012 | CP Support/Funding/ Letters of Credit | ||||||||||
Total PSE&G |
$ | 600 | $ | 21 | $ | 579 | ||||||||||||
Total |
$ | 3,650 | $ | 319 | $ | 3,331 | ||||||||||||
62
(A) | This facility was reduced by $500 million on April 15, 2011. In December 2011, this facility will be reduced by an additional $23 million. |
(B) | In December 2011, this facility will be reduced by $75 million. |
(C) | Includes amounts related to letters of credit outstanding. |
On April 15, 2011, PSEG, Power and PSE&G entered into new 5-year credit agreements in the amounts of $500 million, $1 billion and $600 million, respectively. These new agreements will expire in April 2016. Concurrently PSEG reduced its existing $1 billion credit facility to $500 million, Power terminated its existing $350 million credit facility, and PSE&G terminated its existing $600 million credit facility. As a result of these changes, Powers total credit capacity increased by $650 million which increased our total credit capacity to $4.3 billion.
Long-Term Debt Financing
For a discussion of our long-term debt transactions during 2011, see Note 9. Changes in Capitalization.
Common Stock Dividends
Three Months Ended March 31, |
||||||||
Dividend Payments on Common Stock |
2011 |
2010 |
||||||
Per Share |
$ | 0.3425 | $ | 0.3425 | ||||
in Millions |
$ | 173 | $ | 173 |
We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant.
Credit Ratings
If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit 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 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. In April 2011, S&P published an updated credit opinion which left the ratings for PSEG, Power and PSE&G unchanged and improved their outlooks to positive from stable. In May 2011, Moodys affirmed its ratings for PSEG, Power and PSE&G. PSE&Gs outlook was improved to positive from stable while the outlooks at PSEG and Power remain at stable.
Moodys(A) |
S&P(B) |
Fitch(C) |
||||||||||
PSEG: |
||||||||||||
Outlook |
Stable | Positive | Stable | |||||||||
Commercial Paper |
P2 | A2 | F2 | |||||||||
Power: |
||||||||||||
Outlook |
Stable | Positive | Stable | |||||||||
Senior Notes |
Baa1 | BBB | BBB+ | |||||||||
PSE&G: |
||||||||||||
Outlook |
Positive | Positive | Stable | |||||||||
Mortgage Bonds |
A2 | A | A | |||||||||
Commercial Paper |
P2 | A2 | F2 |
(A) | Moodys ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities. |
63
(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. |
We expect that the majority of funding for our capital requirements over the next three years will come from a combination of internally generated funds and external financings. Our projected construction and investment expenditures through 2013 are consistent with the amounts disclosed in our Annual Report on Form 10-K for the year ended December 31, 2010.
Power
During the three months ended March 31, 2011, Power made $122 million of capital expenditures, including interest capitalized during construction (IDC) but excluding $33 million for nuclear fuel, primarily related to various projects at Fossil and Nuclear. For additional information regarding current projects, see Note 8. Commitments and Contingent Liabilities.
PSE&G
During the three months ended March 31, 2011, PSE&G made $349 million of capital expenditures, including $339 million of investment in plant, primarily for reliability of transmission and distribution systems and $10 million in solar loan investments. This does not include expenditures for cost of removal, net of salvage, of $13 million, which are included in operating cash flows.
For information related to recent accounting matters, see Note 2. Recent Accounting Standards.
ITEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The market risk inherent in our market-risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, equity security prices and interest rates as discussed in the Notes to Condensed Consolidated Financial Statements. It is our policy to use derivatives to manage risk consistent with business plans and prudent practices. We have a Risk Management Committee comprised of executive officers who utilize a risk oversight function to ensure compliance with our corporate policies and risk management practices.
Additionally, we are exposed to counterparty credit losses in the event of non-performance or non-payment. We have a credit management process, which is used to assess, monitor and mitigate counterparty exposure. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our financial condition, results of operations or net cash flows.
Commodity Contracts
The availability and price of energy-related commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, we enter into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with physical sales and other services, help reduce risk and optimize the value of owned electric generation capacity.
Value-at-Risk (VaR) Models
We use VaR models to assess the market risk of our commodity businesses. The portfolio VaR model includes our owned generation and physical contracts, as well as fixed price sales requirements, load requirements and financial derivative instruments. VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses.
64
We manage our exposure at the portfolio level, which consists of owned generation, electric load-serving contracts, fuel supply contracts and energy derivatives designed to manage the risk around generation and load. While we manage our risk at the portfolio level, we also monitor separately the risk of our trading activities and hedges. Non-trading MTM VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The non-trading MTM VaR calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some load serving activities. The MTM derivatives that are not hedges are included in the trading VaR.
The VaR models used are variance/covariance models adjusted for the change of positions with a 95% confidence level and a one-day holding period for the MTM trading and non-trading activities, and a 95% confidence level with a one-week holding period for the portfolio VaR. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio.
As of March 31, 2011 and December 31, 2010, trading VaR was $2 million and $1 million, respectively.
For the Three Months Ended March 31, 2011 |
Trading |
Non-Trading |
||||||
Millions | ||||||||
95% Confidence level, |
||||||||
Loss could exceed VaR one day in 20 days |
||||||||
Period End |
$ | 2 | $ | 6 | ||||
Average for the Period |
$ | 1 | $ | 8 | ||||
High |
$ | 2 | $ | 14 | ||||
Low |
$ | 0 | $ | 4 | ||||
99.5% Confidence level, |
||||||||
Loss could exceed VaR one day in 200 days |
||||||||
Period End |
$ | 3 | $ | 10 | ||||
Average for the Period |
$ | 1 | $ | 12 | ||||
High |
$ | 3 | $ | 21 | ||||
Low |
$ | 1 | $ | 7 |
See Note 10. Financial Risk Management Activities for a discussion of credit risk.
ITEM 4. | CONTROLS AND PROCEDURES |
Disclosure Controls and Procedures
We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the Exchange Act) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer and Chief Financial Officer of each respective company, as appropriate, by others within the entities to allow timely decisions regarding required disclosure. We have established a disclosure committee which includes 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 and, based on this evaluation, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report.
Internal Controls
We continually review our disclosure controls and procedures and make changes, as necessary, to ensure the quality of our financial reporting. There have been no changes in internal control over financial reporting that occurred during the first quarter of 2011 that have materially affected, or are reasonably likely to materially affect, each registrants internal control over financial reporting.
65
ITEM 1. | LEGAL PROCEEDINGS |
We are party to various lawsuits and regulatory matters in the ordinary course of business. For information regarding material legal proceedings, including updates to information reported under Item 3 of Part I of the respective 2010 Annual Reports on Form 10-K of PSEG, Power and PSE&G, see Note 8. Commitments and Contingent Liabilities and Item 5. Other Information.
Certain information reported under the 2010 Annual Report on Form 10-K is updated below. References are to the related pages on the Form 10-K as printed and distributed.
Long-Term Capacity Agreement Pilot Program (LCAPP)
December 31, 2010 Form 10-K page 47. In an attempt to stimulate the development of new generation capacity in New Jersey through a subsidized rate mechanism, New Jersey enacted LCAPP directing the BPU to conduct a process to procure and subsidize up to 2,000 megawatts of baseload or mid-merit electric power generation. In February 2011, we joined other plaintiffs in an action filed in the United States District Court for the District of New Jersey challenging the constitutionality of the LCAPP Act under the Supremacy and Commerce clauses of the United States Constitution. The complaint seeks declaratory and injunctive relief. Also in February 2011, PSEG and a group of other generators filed a complaint asking FERC to take steps to mitigate the impact of this subsidized generation on the capacity markets, and FERC so acted in an April 2011 order. For additional information, see Item 5. Other Information.
Electric Discount and Energy Competition Act (Competition Act)
December 31, 2010 Form 10-K page 48. In April 2007, PSE&G and Transition Funding were served with a purported class action complaint (Complaint) in New Jersey Superior Court challenging the constitutional validity of certain stranded cost recovery provisions of the Competition Act, seeking injunctive relief against continued collection from PSE&Gs electric customers of the Transition Bond Charge (TBC) of Transition Funding, as well as recovery of TBC amounts previously collected. Under New Jersey law, the Competition Act, enacted in 1999, is presumed constitutional.
In July 2007, the plaintiff filed an amended Complaint to also seek injunctive relief from continued collection of related taxes as well as recovery of such taxes previously collected. In July 2007, PSE&G filed a motion to dismiss the amended Complaint, which was granted in October 2007. In November 2007, the plaintiff filed a notice of appeal with the Appellate Division of the New Jersey Superior Court. In February 2009, the New Jersey Appellate Division affirmed the decision of the lower court dismissing the case. In May 2009, the New Jersey Supreme Court denied a request from the plaintiff to review the Appellate Divisions decision.
In July 2007, the same plaintiff also filed a petition with the BPU requesting review and adjustment to PSE&Gs recovery of the same stranded cost charges. In September 2007, PSE&G filed a motion with the BPU to dismiss the petition. In June 2010, the BPU granted PSE&Gs motion to dismiss. In April 2011, the BPU issued a written order memorializing this decision. The petitioner had previously stated that it would appeal the BPUs written order to the New Jersey Appellate Division and has until June 6, 2011 to do so.
Con Edison (Con Ed)
December 31, 2010 Form 10-K page 48. In 2001, Con Ed filed a complaint with FERC against PSE&G, PJM and NYISO asserting a failure to comply with agreements between PSE&G and Con Ed covering 1,000 MW of transmission. On September 16, 2010, FERC approved a settlement agreement entered into by PSE&G, Con Ed, PJM, NYISO and others. This settlement provides the basis for moving forward with Con Ed after the current contracts expire in 2012 and settles all issues associated with the existing contracts, including cases pending in the D.C. Circuit Court of Appeals. However, dismissal of these court cases is contingent upon receipt of a final, non-appealable order from the FERC. One party to the proceeding sought rehearing of the FERC approval order, which FERC denied in an order issued on April 8, 2011. The party may appeal this decision and has until June 7, 2011 to do so.
66
ITEM 1A. | RISK FACTORS |
The Risk Factor shown below is to be added to those disclosed in Part I Item 1A of our 2010 Annual Reports on Form 10-K.
Challenges associated with retention of a qualified workforce could adversely impact our businesses.
Our operations depend on the retention of a skilled workforce. The loss or retirement of key executives or other employees, including those with the specialized knowledge required to support our generation, transmission and distribution operations, could result in various operational challenges. These challenges may include the lack of appropriate replacements, the loss of institutional and industry knowledge and the increased costs to hire and train new personnel. This has the potential to become more critical over the next several years as a growing number of employees become eligible to retire.
In addition, because a significant portion of our employees are covered under collective bargaining agreements, our success will depend on our ability to successfully renegotiate these agreements as they expire. Inability to do so may result in employee strikes or work stoppages which would disrupt our operations and could also result in increased costs.
ITEM 2. | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
The following table indicates our common share repurchases in the open market to satisfy obligations under various equity compensation awards during the first quarter of 2011:
Three Months Ended March 31, 2011 |
Total Number |
Average |
||||||
January 1-January 31 |
0 | $ | 0 | |||||
February 1-February 28 |
0 | $ | 0 | |||||
March 1-March 31 |
158,328 | $ | 32.15 |
ITEM 5. | OTHER INFORMATION |
Certain information reported under the 2010 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 2010 Annual Report on Form 10-K. References are to the related pages on the Form 10-K as printed and distributed.
EMPLOYEE RELATIONS
December 31, 2010 Form 10-K page 17. One of the collective bargaining agreements at PSE&G was set to expire on April 30, 2011. In an effort to continue negotiations, PSE&G and the union, which represents customer operations employees, have agreed to extend the contract to May 6, 2011.
FEDERAL REGULATION
FERC
Capacity Market Issues
December 31, 2010 Form 10-K page 19. In an attempt to stimulate the development of new generation capacity in New Jersey through a subsidized rate mechanism, on January 28, 2011, New Jersey enacted the LCAPP Act directing the BPU to conduct a process to procure and subsidize up to 2,000 megawatts of baseload or mid-merit electric power generation. On March 29, 2011, the BPU issued a written order approving a form of agreement and selecting three generators to build a total of 1,949 MWs of new combined-cycle generating facilities located in New Jersey. The BPU decision requires the New Jersey electric distribution companies, including PSE&G, to execute the BPU approved financially settled standard offer
67
capacity agreements (SOCAs) with each of the three selected generators. The SOCA requires that the generator bid in and clear the PJM RPM base residual auction in each year of the SOCA term. The SOCA provides for the electric distribution companies (EDCs) to make capacity payments to, or receive capacity payments from, the generators as calculated based on the difference between the RPM clearing price for each year of the term and the price bid and accepted for that generator in the BPU process. The LCAPP Act and the BPU order provide that, once the SOCAs are executed and approved by the BPU, they will be irrevocable and the EDCs will be entitled to full rate recovery of the prudently incurred costs. On April 8, 2011 the EDCs jointly filed a motion for reconsideration of the BPUs March 29 order, arguing that the order violated due process and failed to comply with the LCAPP Act. This motion for reconsideration is pending at the BPU.
Each of the New Jersey EDCs, including PSE&G, executed SOCAs with the three generators in compliance with the BPUs directive, but did so under protest reserving its legal rights. On April 27, 2011, the BPU approved the executed contracts and also announced that it will convene a proceeding to consider whether current mechanisms are adequate to incent needed generation construction in New Jersey.
In an effort to prevent the LCAPP Act and other similar state actions from harming competitive wholesale markets, PSEG joined a group of generators and filed a complaint at FERC on February 1, 2011 which sought to correct a flaw in the PJM tariff that allowed for the artificial suppression of capacity prices by buy side resources. With a similar objective, on February 11, 2011, PJM filed with FERC to update and simplify the minimum offer price rule (MOPR). While there were some differences in the relief sought by the generator complaint and the PJM filing, both filings sought changes to the same MOPR tariff provisions for the purposes of preventing subsidized generation from artificially depressing the wholesale capacity markets. On April 12, 2011, FERC issued an order making effective changes to the PJM Tariff that would require new generation to clear in the RPM at competitive prices. In response to this FERC order, the BPU issued a press release indicating that it may pursue other available options.
The LCAPP Act is also being challenged in court. PSEG joined a group filing a complaint in federal district court arguing that the legislation is unconstitutional and should be invalidated. This court action is pending.
Transmission Regulation Transmission Expansion
December 31, 2010 Form 10-K page 20. We have not received certain environmental approvals that are required for each of the Eastern and Western segments of the Susquehanna-Roseland line and believe that it is now unlikely that we will obtain these approvals until early 2013, at the earliest. The Western portion of the line also requires certain permits from the National Park Service. In May, we received a letter from the National Park Service that postpones the agencys issuance of a Record of Decision for this project until January 2013, which represents a three month delay from the previous schedule. We are currently evaluating this additional delay from the National Park Service and any resulting impact on the previously expected in- service date of June 2014 for the Eastern segment and June 2015 for the Western segment. Further delays are also possible for both portions. Delays in the construction schedule could impact the timing of expected transmission revenues.
FERC has granted our request for incentive rate treatment for the Susquehanna-Roseland line, including an adder of 125 basis points above our base ROE, recovery of 100% of Construction Work in Progress (CWIP) in rate base and authorization to recover 100% of all prudently incurred development and construction costs if the project is abandoned or cancelled, in whole or in part, for reasons beyond our control.
In December 2008, PJM approved another 500 kV transmission project, originating in Branchburg and ending in Hudson County, New Jersey, with an estimated cost of $1.1 billion. In December 2009, FERC granted our request for the same incentive rate treatment on this project as the Susquehanna-Roseland line. Subsequently, PJM approved a modified 230 kV project, in place of the 500 kV line, originating in Roseland and terminating in Hudson County, at an estimated cost of up to $700 million (North East Grid project). The project has an expected in-service date of June 2015. Development and siting activities for this project are expected to commence in 2011. In November 2010, we filed a notice with FERC regarding the change in project scope. The BPU and the New Jersey Division of Rate Counsel each filed objections to the continuation of the previously-awarded rate incentives to the reconfigured project. We have filed responsive pleadings and believe
68
that the modified project should be eligible for the same rate incentives as the original project, but the matter remains pending at FERC.
PJM has approved in its Regional Transmission Expansion Plan several other 230 kV transmission projects to be constructed by PSE&G. PSE&G filed at FERC for recovery of CWIP in rate base for four of these projects (Burlington-Camden project, North Central Reliability project (formerly known as the West Orange project), Middlesex Switch Rack project and Bayonne-Marion project) and 100% abandonment cost recovery for these projects. On December 30, 2010, the FERC denied PSE&Gs request without prejudice, finding that PSE&G had not met the requirements for incentive treatment on a project-by-project basis and affording PSE&G the option to re-file and justify the requested incentives on a project-by-project, rather than on an aggregate, basis. On April 14, 2011, we filed such a petition with FERC seeking incentive rates for the four above-listed projects, as well as the Mickleton-Gloucester-Camden project. The total estimated capital investment for the five projects is approximately $1.3 billion. For each of these projects, PSE&G has requested inclusion of 100% of CWIP in rate base and recovery of 100% of prudently incurred abandonment costs with an effective date of June 14, 2011.
Commodity Futures Trading Commission (CFTC)
December 31, 2010 Form 10-K page 22. In July 2010, the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) was passed in an attempt to reduce systemic risk in the financial markets thereby preventing future financial crises and market issues such as those experienced recently. As part of this new legislation, the SEC and the CFTC will be implementing new rules to enact stricter regulation over swaps and derivatives since many of the issues experienced were caused by derivative trading in connection with mortgage loans. Additionally, the Dodd-Frank Act will require many swaps and other derivative transactions to be standardized and traded on exchanges or other Derivative Clearing Organizations (DCOs).
CFTC has issued Notice of Proposed Rulemakings (NOPRs) on many of the key issues, including:
| defining swaps, |
| defining swap dealers and major swap participants, |
| the end-user exception from clearing requirements, |
| position limits, |
| margin requirements, |
| capital requirements, and |
| reporting requirements. |
Exchanges and DCOs typically require full collateralization of all transactions taking place on the exchange or DCO. Although the Dodd-Frank Act specifically recognizes a commercial end user exemption from posting additional collateral in the bilateral Over the Counter swap and derivative markets, we cannot assess the exact scope of the new rules until the SEC and CFTC issue them. Under the current NOPRs, the broad definition of swap dealer could result in us being classified as a dealer, which would limit the benefits of the commercial end-user exemption recognized in the Act. We believe that any regulatory change that deviates from the original intent would need to be addressed by additional legislation.
Under the margin requirement NOPR, no margin would be applied to any transaction with an end-user, except for a proposal for banks that would impose a one-way margin flowing from the end-user to the bank for any transaction that exceeds a credit threshold set by the bank.
We will carefully monitor these new rules as they are developed to analyze the potential impact on our swap and derivatives transactions, including any potential increase in our collateral requirements.
69
Nuclear Regulatory Commission (NRC)
As a result of events at the Fukushima Daiichi nuclear facility in Japan following the earthquake and tsunami in March 2011, the NRC will be performing additional operational and safety reviews of nuclear facilities in the US. These reviews and the lessons learned from the events in Japan may result in additional regulation for the nuclear industry and could impact future operations and capital requirements for our facilities. We believe that our nuclear plants meet the stringent applicable design and safety specifications of the NRC. In addition, in April 2011, a petition was filed with the NRC seeking suspension of the operating licenses of all General Electric (GE) boiling water reactors (BWRs) utilizing the Mark 1 containment design in the United States, including our Hope Creek and Peach Bottom units, pending completion of the NRC review. The petition names 23 of the total 104 active commercial nuclear reactors in the United States. While we do not believe the petition will be successful, we are unable to predict the outcome of any action that the NRC may take in connection with its operational and safety reviews or any other regulatory or industry responses to the events in Japan.
STATE REGULATION
Rates
Retail Gas Transportation Rates
December 31, 2010 Form 10-K page 23. Several stakeholder meetings have been held and briefs were submitted at the end of January 2011. The matter remains pending at the BPU.
SBC/NGC
December 31, 2010 Form 10-K page 26. In July 2009, a revision was filed requesting an increase in SBC/NGC rates of $104 million and $15 million for electric and gas, respectively. The Administrative Law Judge (ALJ) issued an initial decision in April 2010 that recommended a revenue increase of $119 million and a disallowance of approximately $254,000 in PJM costs from the NGC and approximately $540,000 of interest that accrued on the electric SBC. Although we filed exceptions to the recommendation, the BPU issued a written order in June 2010, adopting the ALJs initial decision. We filed a notice of appeal in August 2010 regarding the disallowances related to the NGC and electric SBC. The appeal was denied by the Superior Court of the New Jersey Appellate Division in March 2011.
In August 2010, we made our 2010 annual SBC/NGC filing requesting an $85.4 million electric increase and a $17.2 million gas decrease. On February 11, 2011, we filed a stipulation of settlement with the ALJ. The stipulation was executed by all parties and will allow us to increase electric SBC/NGC rates by $85.4 million and decrease gas SBC rates by $17.2 million, both on an annual basis. The stipulation was approved by the ALJ and adopted by the BPU by written order dated March 9, 2011, with rates effective April 1, 2011.
Remediation Adjustment Clause (RAC)
December 31, 2010 Form 10-K page 26. In November 2010, we filed a RAC 18 petition with the BPU requesting an increase in electric and gas RAC rates of approximately $3 million and $1 million, respectively. We are engaging in settlement discussions with the various parties.
Energy Supply
BGSS
December 31, 2010 Form 10-K page 27. In July 2010, PSE&G made its annual BGSS filing with the BPU. The filing requested a decrease in annual BGSS revenue of $123 million, excluding sales and use tax, to be effective October 1, 2010. This represented a reduction of approximately 6.8% for a typical residential gas heating customer. The new BGSS rate was approved by the BPU in September 2010, on a provisional basis, and was made effective immediately. Subsequent to these two reductions, we filed and self-implemented an additional reduction to the BGSS rate in December. This reduction targeted an approximate $69 million decrease in the BGSS deferred balance. The reduction in the BGSS-Residential Service Gas Commodity Charge for a typical gas residential heating customer was a decrease of approximately 5%. In March 2011, the BPU approved a stipulation that makes the current rate final and resolves all issues in the proceeding.
70
Energy Policy
New Jersey Energy Master Plan (EMP)
December 31, 2010 Form 10-K page 27. On October 1, 2010, we filed a petition with the BPU for an increase in the RGGI Recovery Charge (RRC), seeking to recover approximately $48 million in electric revenue and $11 million in gas revenue on an annual basis. The required annual filing seeks to reset the RRC rate components for five programs. These include Carbon Abatement, the Energy Efficiency Economic Stimulus Program, the Demand Response Program, Solar 4 All, and the Solar Loan II Program.
During 2010, the Governor of New Jersey directed the BPU to review the States current EMP. We expect the BPU to release a new draft EMP during the first half of 2011 with a final plan expected to be completed later in the year. We cannot predict what modifications or new goals will be included in the new EMP or the potential impacts to our businesses.
Capital Economic Stimulus Infrastructure Program
December 31, 2010 Form 10-K page 29. In January 2009, we filed for approval of a capital economic stimulus infrastructure investment program. Under this initiative, we proposed to undertake $698 million of capital infrastructure investments over a 24 month period. The goal of these accelerated capital investments is to help improve the States economy through the creation of new jobs. We made this filing in response to the Governor of New Jerseys proposal to help revive the economy through job growth and capital spending.
In April 2009, the BPU approved a settlement agreement which identified 38 qualifying projects totaling $694 million. The Capital Adjustment Charge (CAC) will be adjusted each January based on forecasted program expenditures and will be subject to deferred accounting.
We spent $180 million on approved infrastructure projects in 2009 and collected approximately $11 million through the CAC.
The CAC rates were adjusted on a provisional basis on January 1, 2010. At the conclusion of our base rate case in June and July 2010, the infrastructure projects that were placed in service through the end of 2009 were rolled into rate base rate and the CAC rates were adjusted accordingly, again on a provisional basis. We spent $408 million on approved infrastructure projects in 2010 and collected approximately $36 million through the CAC.
In November 2010, we made our second annual filing seeking an update to the CAC rates that would provide for approximately $25 million through June 2011 to cover the remaining $108 million infrastructure investments under the program.
Also in November 2010, we filed for an extension of the gas Capital Stimulus program, seeking BPU approval for approximately $78 million in gas infrastructure investments over a two-year period. We also filed to roll-in to rate base the unrecovered Capital Stimulus expenditures for projects that would be placed in service by June 30, 2011. If approved, this roll-in will result in an increase in the electric and gas base rates of $41 million and $22 million, respectively, with a corresponding reduction in the CAC. We are awaiting a decision on this matter.
In February 2011, we filed for an extension of the electric Capital Stimulus program, seeking BPU approval for approximately $229 million in electric infrastructure investments over a 26-month period.
Carbon Abatement Program
December 31, 2010 Form 10-K page 29. The BPU approved our proposal to invest up to $46 million over four years on a small scale carbon abatement program across specific customer segments. For each year of the program we will file a petition on October 1 to set forth the calculation of the electric and gas recovery charges for the subsequent year. The BPU approved a rate increase in December 2009, which resulted in a net annual revenue increase of $1.9 million in 2010. The petition filed in October 2010 for setting the recovery charges for 2011 is still pending. As of March 31, 2011, $25 million of the approved $46 million investment had been spent on energy efficiency measures.
71
ENVIRONMENTAL MATTERS
Air Pollution Control
Hazardous Air Pollutants Regulation
December 31, 2010 Form 10-K page 32. In accordance with a court ruling, the EPA proposed a Maximum Achievable Control Technology (MACT) regulation in March 2011 which is expected to be finalized by November 2011. This regulation includes mercury reduction and other hazardous air pollutants pursuant to the Clean Air Act. In preparation for this action, the EPA solicited extensive stack-testing information from many coal and oil fired electric generating units through a mandatory Information Collection Request (ICR). We participated in this ICR and submitted the required information in 2010. According to the prescriptive MACT process, the EPA will select an emission rate from the best performing units, by pollutant and/or surrogate, and units within a given category yet to be determined will have to have a lower emission rate than the selected rate by a set date, typically three to five years after the final rule. Until the final rule is adopted, the impact cannot be determined; however, if the rule is adopted as proposed, Power believes the back end technology environmental controls recently installed at its Hudson and Mercer coal facilities should meet the rules requirements. At Powers Connecticut facilities, some additional controls could be necessary, pending engineering evaluation. The impact to Powers jointly owned coal fired generating facilities in Pennsylvania is under evaluation.
Water Pollution Control
Permit Renewals
December 31, 2010 Form 10-K page 33. The use of cooling water is a significant part of the generation of electricity at steam-electric generating stations. Section 316(b) of the Federal Water Pollution Control Act requires that cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impact. The impact of regulations under Section 316(b) can be significant, particularly at steam-electric generating stations which do not have closed cycle cooling through the use of cooling towers to recycle water for cooling purposes. The installation of cooling towers at an existing generating station can impose significant engineering challenges and significant costs, which can affect the economic viability of a particular plant. In late 2010, the EPA entered into a settlement agreement with environmental groups that established a schedule to develop a new 316(b) rule.
On April 20, 2011, the EPA published the proposed rule and comments are due 90 days thereafter. The proposed rule would establish a separate marine life entrainment mortality standard as well as new impingement mortality standards for existing cooling water intake structures with a design flow of more than 2 million gallons per day. The proposed impingement standard requires that such facilities must meet specific numeric criteria to comply, while the proposed entrainment standard provides for a site specific, case-by-case BTA assessment for mortality reduction. If the rule were to be adopted as proposed, the majority of our electric generating could be affected as they employ once-through cooling utilizing tidal river and tidal waters.
We are in the process of reviewing the proposed rule and assessing its potential impact on our generating facilities. We expect to file comments on the proposed rulemaking with the EPA within the prescribed time. We are unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on our future capital requirements, financial condition or results of operations which could be material. See Note 8. Commitments and Contingent Liabilities for additional information.
Conemaugh NPDES permit
In April 2007, a Clean Water Act citizen suit was brought against GenOn Northeast Management Company (then known as Reliant Energy Northeast Management Company) (GenOn), as operator of the 1,711 MW Conemaugh Generating Station (Conemaugh), seeking civil penalties and injunctive relief for alleged violations of Conemaughs National Pollutant Discharge Elimination System (NPDES) permit. We have a 22.5% percent ownership interest in Conemaugh. Pursuant to a Consent Order and Agreement between Pennsylvania Department of Environmental Protection (PADEP) and GenOn, a variety of studies have been
72
conducted, a water treatment facility for cooling tower blowdown has been designed and built, and a second treatment facility for flue gas desulfurization effluent has been designed (awaiting final PADEP approval for construction), in order to comply with the limits set in Conemaughs NPDES permit. On March 21, 2011, the court entered a partial summary judgment in the plaintiffs favor, declaring as a matter of law that discharges from Conemaugh had violated the NPDES permit. The case is set for a non-jury trial starting on June 1, 2011, at which the Court will determine what, if any, civil penalties and injunctive relief might be appropriate. If plaintiffs are ultimately successful, we could incur costs associated with civil penalties and the implementation of additional discharge reductions, in proportion to our share of ownership.
AMENDED EMPLOYMENT AGREEMENT WITH EXECUTIVE OFFICER
In our Proxy Statement for the 2011 Annual Meeting of Stockholders, we reported on a proposed amendment to the employment agreement with Randall E. Mehrberg, Executive Vice PresidentStrategy and Development of PSEG and President and Chief Operating Officer of Energy Holdings, originally effective September 8, 2008. The original agreement provided, among other things, that upon a termination by us without cause Mr. Mehrberg would receive full vesting of restricted stock and restricted stock units awarded under our 2004 Long-Term Incentive Plan (LTIP) unless a change in such provisions of the LTIP is applicable to all employees similar to Mr. Mehrberg. Subsequently, the applicable provisions of such awards under the LTIP provided for forfeiture upon a termination without cause. On May 4, 2011, we entered into the proposed amendment with Mr. Mehrberg and included a provision that provides for full vesting without proration of awards under our LTIP under certain circumstances if Mr. Mehrberg is terminated by us without cause between September 8, 2012 and December 31, 2016. For a complete recitation of all the terms of the amended employment agreement and the conditions under which Mr. Mehrberg may receive full vesting without proration, see Exhibit 10.2.
73
ITEM 6. | EXHIBITS |
A listing of exhibits being filed with this document is as follows:
a. PSEG:
Exhibit 10: | Amended and Restated Key Executive Severance Plan |
Exhibit 10.1: | 2004 Long-Term Incentive Plan, as amended |
Exhibit 10.2: | Amendment to Employment Agreement with Randall Mehrberg, dated as of May 4, 2011 |
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 (1934 Act) |
Exhibit 31.1: | Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act |
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 Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code |
Exhibit 101.INS: | XBRL Instance Document* |
Exhibit 101.SCH: | XBRL Taxonomy Extension Schema* |
Exhibit 101.CAL: | XBRL Taxonomy Extension Calculation Linkbase* |
Exhibit 101.LAB: | XBRL Taxonomy Extension Labels Linkbase* |
Exhibit 101.PRE: | XBRL Taxonomy Extension Presentation Linkbase* |
Exhibit 101.DEF: | XBRL Taxonomy Extension Definition Document* |
* | XBRL information is furnished, not filed. |
b. Power:
Exhibit 10: | Amended and Restated Key Executive Severance Plan |
Exhibit 10.1: | 2004 Long-Term Incentive Plan, as amended |
Exhibit 12.1: | Computation of Ratios of Earnings to Fixed Charges |
Exhibit 31.2: | Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act |
Exhibit 31.3: | Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act |
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 Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code |
c. PSE&G:
Exhibit 10: | Amended and Restated Key Executive Severance Plan |
Exhibit 10.1: | 2004 Long-Term Incentive Plan, as amended |
Exhibit 12.2: | Computation of Ratios of Earnings to Fixed Charges |
Exhibit 12.3: | Computation of Ratios of Earnings to Fixed Charges Plus Preferred Securities Dividend Requirements |
Exhibit 31.4: | Certification by Ralph Izzo Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act |
Exhibit 31.5: | Certification by Caroline Dorsa Pursuant to Rules 13a-14 and 15d-14 of the 1934 Act |
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 Caroline Dorsa Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code |
74
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 | ||
(Registrant) | ||
By: | /S/ DEREK M. DIRISIO | |
Derek M. DiRisio Vice President and Controller (Principal Accounting Officer) |
Date: May 5, 2011
75
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 | ||
(Registrant) | ||
By: | /S/ DEREK M. DIRISIO | |
Derek M. DiRisio Vice President and Controller (Principal Accounting Officer) |
Date: May 5, 2011
76
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 | ||
(Registrant) | ||
By: | /S/ DEREK M. DIRISIO | |
Derek M. DiRisio Vice President and Controller (Principal Accounting Officer) |
Date: May 5, 2011
77