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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 June 30, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission Registrant, State of Incorporation, I.R.S. Employer
File Address, and Telephone Number Identification
Number No.
- ---------- ------------------------------------------ ----------------
1-9120 PUBLIC SERVICE ENTERPRISE GROUP 22-2625848
INCORPORATED
(A New Jersey Corporation)
80 Park Plaza
P.O. Box 1171
Newark, New Jersey 07101-1171
973 430-7000
http://www.pseg.com
1-973 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
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No ___
The number of shares outstanding of Public Service Enterprise Group
Incorporated's sole class of common stock, as of the latest practicable date,
was as follows:
Class: Common Stock, without par value
Outstanding at July 31, 1999: 219,247,118
As of July 31, 1999, 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.
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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TABLE OF CONTENTS
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Page
----
Public Service Enterprise Group Incorporated (PSEG):
Consolidated Statements of Income for the Three and Six
Months Ended June 30, 1999 and 1998............................. 1
Consolidated Balance Sheets as of June 30, 1999
and December 31, 1998........................................... 2
Consolidated Statements of Cash Flows for the Six
Months Ended June 30, 1999 and 1998.............................. 4
Public Service Electric and Gas Company (PSE&G):
Consolidated Statements of Income for the Three and Six
Months Ended June 30, 1999 and 1998............................. 5
Consolidated Balance Sheets as of June 30, 1999
and December 31, 1998........................................... 6
Consolidated Statements of Cash Flows for the Six
Months Ended June 30, 1999 and 1998............................. 8
Notes to Consolidated Financial Statements-- PSEG................. 9
Notes to Consolidated Financial Statements-- PSE&G................ 29
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations
PSEG ........................................................... 30
PSE&G........................................................... 50
Item 3. Qualitative and Quantitative Disclosures About Market Risk.. 50
PART II. OTHER INFORMATION
Item 1. Legal Proceedings........................................... 51
Item 5. Other Information........................................... 53
Item 6. Exhibits and Reports on Form 8-K............................ 54
Forward Looking Statements.......................................... 55
Signatures -- PSEG.................................................. 56
Signatures -- PSE&G................................................. 56
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
<PAGE>
<TABLE>
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars, except for Per Share Data)
(Unaudited)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ---------------------
1999 1998 1999 1998
---------- --------- --------- ---------
<S> <C> <C> <C> <C>
OPERATING REVENUES
Electric $ 1,020 $ 980 $ 1,986 $ 1,882
Gas 277 272 977 884
PSEG Energy Holdings Inc. 139 110 268 255
---------- --------- --------- ---------
Total Operating Revenues 1,436 1,362 3,231 3,021
---------- --------- --------- ---------
OPERATING EXPENSES
Net Interchanged Power and Fuel for Electric Generation 238 241 463 460
Gas Purchased 177 182 626 598
Operation and Maintenance 419 388 857 745
Depreciation and Amortization 122 166 288 323
Taxes:
Income Taxes 121 89 264 221
Other 43 44 99 105
---------- --------- --------- ---------
Total Operating Expenses 1,120 1,110 2,597 2,452
---------- --------- --------- ---------
OPERATING INCOME 316 252 634 569
---------- --------- --------- ---------
OTHER INCOME AND DEDUCTIONS 10 2 16 9
---------- --------- --------- ---------
INCOME BEFORE INTEREST CHARGES AND
DIVIDENDS ON PREFERRED SECURITIES
AND EXTRAORDINARY ITEM 326 254 650 578
---------- --------- --------- ---------
INTEREST CHARGES AND PREFERRED SECURITIES DIVIDENDS
Interest Expense 119 116 233 237
Capitalized Interest and AFDC (2) (3) (4) (7)
Preferred Securities Dividend Requirements of Subsidiaries 28 19 52 35
---------- --------- --------- ---------
Total Interest Charges and Preferred Securities Dividends 145 132 281 265
---------- --------- --------- ---------
INCOME BEFORE EXTRAORDINARY ITEM 181 122 369 313
Extraordinary Item (Net of Tax of $345) (790) - (790) -
---------- --------- --------- ---------
NET INCOME (LOSS) $ (609) $ 122 $ (421) $ 313
========== ========= ========= =========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (000's) 219,571 231,958 221,122 231,958
EARNINGS (LOSSES) PER SHARE (BASIC AND DILUTED)
Income Before Extraordinary Item $ 0.83 $ 0.53 $ 1.67 $ 1.35
Extraordinary Item (Net of Tax) (3.60) - (3.57) -
---------- --------- --------- ---------
Net Income (Loss) $ (2.77) $ 0.53 $ (1.90) $ 1.35
========== ========= ========= =========
DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 0.54 $ 0.54 $ 1.08 $ 1.08
========== ========= ========= =========
See Notes to Consolidated Financial Statements.
</TABLE>
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<TABLE>
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions of Dollars)
<CAPTION>
(Unaudited)
June 30, December 31,
1999 1998
-------------- ----------------
<S> <C> <C>
PROPERTY, PLANT AND EQUIPMENT
Electric - Generation $ 1,763 $ 9,226
Electric - Transmission and Distribution 4,969 4,953
Gas - Distribution 2,946 2,882
Common 265 414
-------------- ----------------
Total 9,943 17,475
Less: Accumulated depreciation and amortization 3,417 7,048
-------------- ----------------
Net 6,526 10,427
Nuclear Fuel in Service, net of accumulated amortization -
1999, $377; 1998, $312 194 187
-------------- ----------------
Net Property, Plant and Equipment in Service 6,720 10,614
Construction Work in Progress, including Nuclear Fuel in
Process - 1999, $34; 1998, $72 98 219
Plant Held for Future Use 21 24
-------------- ----------------
Net Property, Plant and Equipment 6,839 10,857
-------------- ----------------
INVESTMENTS AND OTHER NONCURRENT ASSETS
Long-Term Investments, net of amortization - 1999, $36; 1998,
$28, and net of valuation allowances - 1999, $19; 1998, $18 3,475 3,034
Nuclear Decommissioning Fund 562 524
Other Special Funds 135 125
Other Noncurrent Assets, net of amortization - 1999, $33; 1998,
$29, and net of valuation allowances - 1999, $10; 1998, $10 193 150
-------------- ----------------
Total Investments and Other Noncurrent Assets 4,365 3,833
-------------- ----------------
CURRENT ASSETS
Cash and Cash Equivalents 77 140
Accounts Receivable:
Customer Accounts Receivable 556 506
Other Accounts Receivable 460 219
Less: Allowance for Doubtful Accounts 47 38
Unbilled Revenues 187 255
Fuel - Gas Distribution 226 274
Fuel - Electric Generation 47 57
Materials and Supplies,
net of valuation reserves - 1999, $51; 1998, $12 130 167
Prepayments 307 61
Miscellaneous Current Assets 69 32
-------------- ----------------
Total Current Assets 2,012 1,673
-------------- ----------------
DEFERRED DEBITS
Regulatory Asset - Stranded Costs 4,058 -
SFAS 109 Income Taxes 296 704
OPEB Costs 260 270
Demand Side Management Costs 144 150
Environmental Costs 124 139
Unamortized Loss on Reacquired Debt and Debt Expense 130 135
Other 239 236
-------------- ----------------
Total Deferred Debits 5,251 1,634
-------------- ----------------
TOTAL $ 18,467 $ 17,997
============== ================
See Notes to Consolidated Financial Statements.
</TABLE>
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<TABLE>
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
(Millions of Dollars)
<CAPTION>
(Unaudited)
June 30, December 31,
1999 1998
------------ ---------------
<S> <C> <C>
CAPITALIZATION
Common Stockholders' Equity:
Common Stock, issued; 231,957,608 shares $ 3,603 $ 3,603
Treasury Stock, at cost; 1999 - 12,971,900 shares,
1998 - 5,314,100 shares (507) (207)
Retained Earnings 1,089 1,748
Accumulated Other Comprehensive Income (Loss) (173) (46)
------------ ---------------
Total Common Stockholders' Equity 4,012 5,098
Subsidiaries' Preferred Securities:
Preferred Stock Without Mandatory Redemption 95 95
Preferred Stock With Mandatory Redemption 75 75
Guaranteed Preferred Beneficial Interest in Subordinated
Debentures 1,038 1,038
Long-Term Debt 4,840 4,763
------------ ---------------
Total Capitalization 10,060 11,069
------------ ---------------
OTHER LONG-TERM LIABILITIES
Nuclear Decommissioning 462 -
OPEB Costs 367 344
Cost of Removal - Generation 126 -
Environmental Costs 132 84
Capital Lease Obligations 50 50
Other 127 65
------------ ---------------
Total Other Long-Term Liabilities 1,264 543
------------ ---------------
CURRENT LIABILITIES
Long-Term Debt due within one year 851 418
Commercial Paper and Loans 1,288 1,056
Accounts Payable 789 655
Accrued Taxes 75 41
Other 392 288
------------ ---------------
Total Current Liabilities 3,395 2,458
------------ ---------------
DEFERRED CREDITS AND REGULATORY LIABILITIES
Income Taxes 2,807 3,384
Investment Tax Credits 79 322
Regulatory Liability - Excess Depreciation Reserve 569 -
Other 293 221
------------ ---------------
Total Deferred Credits and Regulatory Liabilities 3,748 3,927
------------ ---------------
COMMITMENTS AND CONTINGENT LIABILITIES - -
------------ ---------------
TOTAL $ 18,467 $ 17,997
============ ===============
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
(Unaudited)
Six Months Ended
<CAPTION>
June 30,
-----------------------
1999 1998
--------- ----------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $(421) $ 313
Adjustments to reconcile net income (loss) to net cash flows from
operating activities:
Extraordinary Loss - net of tax 790 -
Depreciation and Amortization 288 323
Amortization of Nuclear Fuel 42 44
Recovery of Electric Energy and Gas Costs - net 106 94
Provision for Deferred Income Taxes - net (206) 9
Investment Distributions 75 63
Gains on Investments (45) (98)
Leasing Activities (5) (51)
Net Changes in certain current assets and liabilities:
Accounts Receivable and Unbilled Revenues (160) 153
Inventory - Fuel and Materials and Supplies 64 59
Prepayments (246) (297)
Accounts Payable 137 (94)
Accrued Taxes 35 (29)
Other Current Assets and Liabilities 69 18
Other 80 34
--------- ----------
Net Cash Provided By Operating Activities 603 541
--------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment,
excluding Capitalized Interest and AFDC (172) (191)
Net Change in Long-Term Investments (630) (15)
Contribution to Decommissioning Funds and Other Special Funds (31) (61)
Other (37) (24)
--------- ----------
Net Cash Used In Investing Activities (870) (291)
--------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt 232 (379)
Issuance of Long-Term Debt 713 250
Redemption of Long-Term Debt (203) (203)
Issuance of Preferred Securities - 375
Purchase of Treasury Stock (300) -
Cash Dividends Paid on Common Stock (238) (251)
Other - (10)
--------- ----------
Net Cash Provided By (Used In) Financing Activities 204 (218)
--------- ----------
Net Change In Cash And Cash Equivalents (63) 32
Cash And Cash Equivalents At Beginning Of Year 140 83
--------- ---------
Cash And Cash Equivalents At End Of Period $ 77 $ 115
========= =========
Income Taxes Paid $ 307 $ 326
Interest Paid $ 229 $ 204
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars)
(Unaudited)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
--------------------------- --------------------------
1999 1998 1999 1998
------------ ----------- ----------- -----------
<S> <C> <C> <C> <C>
OPERATING REVENUES
Electric $ 1,020 $ 980 $ 1,986 $ 1,882
Gas 277 272 977 884
------------ ----------- ----------- -----------
Total Operating Revenues 1,297 1,252 2,963 2,766
------------ ----------- ----------- -----------
OPERATING EXPENSES
Net Interchanged Power and Fuel for Electric Generation 235 240 456 456
Gas Purchased 165 169 589 560
Operation and Maintenance 365 344 759 667
Depreciation and Amortization 120 166 285 318
Taxes:
Income Taxes 107 80 240 195
Other 43 46 99 104
------------ ----------- ----------- -----------
Total Operating Expenses 1,035 1,045 2,428 2,300
------------ ----------- ----------- -----------
OPERATING INCOME 262 207 535 466
------------ ----------- ----------- -----------
OTHER INCOME AND DEDUCTIONS - 4 3 6
------------ ----------- ----------- -----------
INCOME BEFORE INTEREST CHARGES AND
DIVIDENDS ON PREFERRED SECURITIES
AND EXTRAORDINARY ITEM 262 211 538 472
------------ ----------- ----------- -----------
INTEREST CHARGES AND PREFERRED SECURITIES DIVIDENDS
Interest Expense 94 92 189 188
Capitalized Interest and AFDC (1) (3) (3) (6)
Preferred Securities Dividend Requirements of Subsidiaries 12 11 23 22
------------ ----------- ----------- -----------
Total Interest Charges and Preferred Securities Dividends 105 100 209 204
------------ ----------- ----------- -----------
INCOME BEFORE EXTRAORDINARY ITEM 157 111 329 268
Extraordinary Item (Net of Tax of $345) (790) - (790) -
------------ ----------- ----------- -----------
NET INCOME (LOSS) (633) 111 (461) 268
Preferred Stock Dividend Requirement 2 3 5 5
------------ ----------- ----------- -----------
EARNINGS (LOSSES) AVAILABLE TO
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED $ (635) $ 108 $ (466) $ 263
============ =========== =========== ===========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions of Dollars)
<CAPTION>
(Unaudited)
June 30, December 31,
1999 1998
--------------- ----------------
<S> <C> <C>
PROPERTY, PLANT AND EQUIPMENT
Electric - Generation $ 1,763 $ 9,226
Electric - Transmission and Distribution 4,969 4,953
Gas - Distribution 2,946 2,882
Common 265 414
--------------- ----------------
Total 9,943 17,475
Less: Accumulated depreciation and amortization 3,417 7,048
--------------- ----------------
Net 6,526 10,427
Nuclear Fuel in Service, net of accumulated amortization -
1999, $377; 1998, $312 194 187
--------------- ----------------
Net Property, Plant and Equipment in Service 6,720 10,614
Construction Work in Progress, including Nuclear Fuel in
Process - 1999, $34; 1998, $72 98 219
Plant Held for Future Use 21 24
--------------- ----------------
Net Property, Plant and Equipment 6,839 10,857
--------------- ----------------
INVESTMENTS AND OTHER NONCURRENT ASSETS
Long-Term Investments 78 65
Nuclear Decommissioning Fund 562 524
Other Special Funds 135 125
Other Noncurrent Assets 59 46
--------------- ----------------
Total Investments and Other Noncurrent Assets 834 760
--------------- ----------------
CURRENT ASSETS
Cash and Cash Equivalents 28 42
Accounts Receivable:
Customer Accounts Receivable 494 451
Other Accounts Receivable 356 178
Less: Allowance for Doubtful Accounts 41 34
Unbilled Revenues 187 255
Fuel - Gas Distribution 226 274
Fuel - Electric Generation 47 57
Materials and Supplies,
net of valuation reserves - 1999, $51; 1998, $12 130 165
Prepayments 303 52
Miscellaneous Current Assets 28 32
--------------- ----------------
Total Current Assets 1,758 1,472
--------------- ----------------
DEFERRED DEBITS
Regulatory Asset - Stranded Costs 4,058 -
SFAS 109 Income Taxes 296 704
OPEB Costs 260 270
Demand Side Management Costs 144 150
Environmental Costs 124 139
Unamortized Loss on Reacquired Debt and Debt Expense 127 135
Other 198 182
--------------- ----------------
Total Deferred Debits 5,207 1,580
--------------- ----------------
TOTAL $ 14,638 $ 14,669
=============== ================
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
(Millions of Dollars)
<CAPTION>
(Unaudited)
June 30, December 31,
1999 1998
------------- ----------------
<S> <C> <C>
CAPITALIZATION
Common Stockholder's Equity:
Common Stock, issued; 132,450,344 shares $ 2,563 $ 2,563
Contributed Capital 594 594
Retained Earnings 529 1,386
Accumulated Other Comprehensive Income (Loss) (3) (3)
------------- ----------------
Total Common Stockholder's Equity 3,683 4,540
Preferred Stock Without Mandatory Redemption 95 95
Preferred Stock With Mandatory Redemption 75 75
Subsidiaries' Preferred Securities:
Guaranteed Preferred Beneficial Interest in Subordinated
Debentures 513 513
Long-Term Debt 3,393 4,045
------------- ----------------
Total Capitalization 7,759 9,268
------------- ----------------
OTHER LONG-TERM LIABILITIES
Nuclear Decommissioning 462 -
OPEB Costs 367 344
Cost of Removal - Generation 126 -
Environmental Costs 132 84
Capital Lease Obligations 50 50
Other 127 65
------------- ----------------
Total Other Long-Term Liabilities 1,264 543
------------- ----------------
CURRENT LIABILITIES
Long-Term Debt due within one year 735 100
Commercial Paper and Loans 940 850
Accounts Payable 734 611
Accrued Taxes 40 30
Other 315 223
------------- ----------------
Total Current Liabilities 2,764 1,814
------------- ----------------
DEFERRED CREDITS AND REGULATORY LIABILITIES
Income Taxes 1,952 2,533
Investment Tax Credits 70 313
Regulatory Liability - Excess Depreciation Reserve 569 -
Other 260 198
------------- ----------------
Total Deferred Credits and Regulatory Liabilities 2,851 3,044
------------- ----------------
COMMITMENTS AND CONTINGENT LIABILITIES - -
------------- ----------------
TOTAL $ 14,638 $ 14,669
============= ================
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
(Unaudited)
<CAPTION>
Six Months Ended
June 30,
-----------------------
1999 1998
--------- ----------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $(461) $ 268
Adjustments to reconcile net income (loss) to net cash flows from
operating activities:
Extraordinary Loss - net of tax 790 -
Depreciation and Amortization 285 318
Amortization of Nuclear Fuel 42 44
Recovery of Electric Energy and Gas Costs - net 106 94
Provision for Deferred Income Taxes - net (193) (6)
Net Changes in certain current assets and liabilities:
Accounts Receivable and Unbilled Revenues (146) 79
Inventory - Fuel and Materials and Supplies 64 59
Prepayments (251) (310)
Accounts Payable 126 (88)
Accrued Taxes 11 (12)
Other Current Assets and Liabilities 96 61
Other 69 35
--------- ----------
Net Cash Provided By Operating Activities 538 542
--------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Property, Plant and Equipment,
excluding Capitalized Interest and AFDC (172) (191)
Net Change in Long-Term Investments (13) (8)
Contribution to Decommissioning Funds and Other Special Funds (31) (61)
Other (13) (7)
--------- ----------
Net Cash Used In Investing Activities (229) (267)
--------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Net Change in Short-Term Debt 90 (151)
Issuance of Long-Term Debt - 250
Redemption of Long-Term Debt (17) (103)
Cash Dividends Paid on Common Stock (392) (251)
Other (4) (5)
--------- ----------
Net Cash Used In Financing Activities (323) (260)
--------- ----------
Net Change In Cash And Cash Equivalents (14) 15
Cash And Cash Equivalents At Beginning Of Year 42 17
--------- -----------
Cash And Cash Equivalents At End Of Period $ 28 $ 32
========= ===========
Income Taxes Paid $ 335 $ 296
Interest Paid $ 197 $ 193
See Notes to Consolidated Financial Statements.
</TABLE>
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Basis of Presentation/Summary of Significant Accounting Policies
Basis of Presentation
The consolidated financial statements included herein have been prepared
pursuant to the rules and regulations of the Securities and Exchange Commission
(SEC). Certain information and note disclosures normally included in financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted pursuant to such rules and regulations. However,
in the opinion of management, the disclosures are adequate to make the
information presented not misleading. These consolidated financial statements
and Notes to Consolidated Financial Statements (Notes) should be read in
conjunction with the Registrant's Notes contained in the 1998 Annual Report on
Form 10-K and the Quarterly Report on Form 10-Q for the quarter ended March 31,
1999. These Notes update and supplement matters discussed in the 1998 Annual
Report on Form 10-K, the Quarterly Report on Form 10-Q for the quarter ended
March 31, 1999 and the Current Reports on Form 8-K filed March 18, 1999, April
26, 1999 and July 21, 1999.
The unaudited financial information furnished reflects all adjustments
which are, in the opinion of management, necessary to fairly state the results
for the interim periods presented. The year-end consolidated balance sheets were
derived from the audited consolidated financial statements included in the 1998
Annual Report on Form 10-K. Certain reclassifications of prior period data have
been made to conform with the current presentation.
Summary of Significant Accounting Policies
Effective April 1, 1999, Public Service Electric and Gas Company (PSE&G)
discontinued the application of Statement of Financial Accounting Standards
(SFAS) 71, "Accounting for the Effects of Regulation" (SFAS 71), for the
electric generation portion of its business. PSE&G calculated a one-time charge
consistent with the requirements of Emerging Issues Task Force (EITF) Issue No.
97-4, "Deregulation of the Pricing of Electricity - Issues Related to the
Application of FASB Statements No. 71 and No. 101" (EITF 97-4) and SFAS 101,
"Regulated Enterprises--Accounting for the Discontinuation of Application of
FASB Statement No. 71" (SFAS 101). The portion of the one-time charge related to
an impairment of long-lived assets was calculated in accordance with SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of" (SFAS 121). The discontinuation of the application of SFAS 71
had a material impact on Public Service Enterprise Group Incorporated's (PSEG)
and PSE&G's financial condition and results of operations. For further
discussion, see Note 2. Regulatory Issues and Note 3. Extraordinary Charge and
Other Accounting Impacts of Deregulation. PSE&G's transmission and distribution
businesses, which continue to be regulated, continue to meet the requirements
for the application of SFAS 71.
Effective April 1, 1999, and in concert with the discontinuation of SFAS
71, PSE&G changed its capitalization policy for the electric generation-related
portion of its business. Under its new capitalization policy, PSE&G will only
capitalize costs which increase either the capacity or the life of an asset and
represent the replacement of a retired asset. All other costs will be expensed
as incurred.
Also, effective April 1, 1999, and in conjunction with the discontinuation
of SFAS 71, PSE&G changed its depreciation policy for the electric
generation-related portion of its business. Under this new depreciation policy,
PSE&G will calculate depreciation on generation-related assets consistent with
new asset lives determined by PSE&G policy rather than using depreciation rates
prescribed by the New Jersey Board of Public Utilities (BPU) in rate
proceedings.
<PAGE>
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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Additionally, effective April 1, 1999, and in concert with the
discontinuation of SFAS 71, PSE&G changed its policy for the treatment of
electric generation-related asset retirements. Under this new retirement policy,
the portion of future retirements of generation-related assets which have not
been fully depreciated will impact earnings.
In the past, fuel revenue and expense flowed through the Electric Levelized
Energy Adjustment Clause (LEAC) mechanism and variances in fuel revenues and
expenses were subject to deferral accounting and thus had no direct effect on
earnings. Due to the discontinuation of the LEAC mechanism on August 1, 1999,
earnings volatility may increase since the unregulated electric generation
portion of PSEG's business will cease to follow deferral accounting and will
bear the full risks and rewards of changes in nuclear and fossil generating fuel
costs and replacement power costs. For further discussion, see Note 4.
Regulatory Assets and Liabilities.
Effective January 1, 1999, PSEG and PSE&G adopted EITF 98-10, "Accounting
for Contracts Involved in Energy Trading and Risk Management Activities" (EITF
98-10). EITF 98-10 requires that energy trading contracts be marked to market
with gains and losses included in earnings and separately disclosed in the
financial statements or footnotes. Previously, the gains and losses associated
with those contracts were recorded upon settlement. The adoption of EITF 98-10
did not have a material impact on the financial condition, results of operations
or net cash flows of PSEG or PSE&G.
Effective January 1, 1999, PSEG and PSE&G adopted Statement of Position
(SOP) 98-1, "Accounting for the Costs of Computer Software Developed or Obtained
for Internal Use" (SOP 98-1), which provides criteria for capitalizing certain
internal-use software costs. The adoption of SOP 98-1 did not have a material
impact on the financial condition, results of operations or net cash flows of
PSEG or PSE&G.
Effective January 1, 1999, PSEG and PSE&G adopted SOP 98-5, "Reporting on
the Costs of Start-Up Activities" (SOP 98-5). SOP 98-5 requires the expensing of
the costs of start-up activities as incurred. Additionally, previously
capitalized start-up costs must be written off as a Cumulative Effect of a
Change in Accounting Principle. The adoption of SOP 98-5 did not have a material
impact on the financial condition, results of operations or net cash flows of
PSEG or PSE&G.
Note 2. Regulatory Issues
New Jersey Energy Master Plan Proceedings and Related Orders
Following the passage of the New Jersey Electric Discount and Energy
Competition Act (Energy Competition Act), the BPU rendered its summary decision
relating to PSE&G's rate unbundling, stranded costs and restructuring
proceedings (Summary Order) on April 21, 1999. It is expected that the BPU will
issue a more detailed Decision and Order (Final Order) in these matters during
the third quarter of 1999, which will provide a full discussion of the issues as
well as the reasoning for the BPU's determinations. The Energy Competition Act,
the BPU's Summary Order and Final Order and the related BPU proceedings are
hereinafter referred to as the Energy Master Plan Proceedings. These proceedings
provide that all New Jersey retail electric customers may select their electric
supplier commencing August 1, 1999 and all New Jersey retail gas customers may
select their gas supplier commencing December 31, 1999, thus opening the New
Jersey energy markets to competition. Under New Jersey law, a 45-day period is
available for a party to the proceedings and ratepayers to appeal the Final
Order once it is issued. PSEG and PSE&G cannot predict whether any appeals will
be filed with respect to the Final Order by any of the parties entitled to do
so. For discussion of the extraordinary charge to earnings recorded as a result
of the deregulation of PSE&G's generation business, see Note 3. Extraordinary
Charge and Other Accounting Impacts of Deregulation.
<PAGE>
The Summary Order provides for the following:
---------------------------------------------
Transition Period
o A four-year transition period beginning August 1, 1999 and ending July
31, 2003. During this transition period, rates will be capped for all
customers who remain with PSE&G.
Rate Reductions
o Customers will receive the following reductions from current rates
through July 2003 according to this schedule:
August 1, 1999: 5%
January 1, 2000 (or at the time
of securitization): increasing to 7%
August 1, 2001: increasing to 9%
August 1, 2002: increasing to 13.9% average
(10% off rates in effect in
April 1997)
The BPU, in finding that the 2000 and 2001 incremental rate reductions
assume achievement of 2% overall savings from securitization (in
addition to the 1% assumed in the initial 5% reduction), conditioned
these additional interim rate reductions upon implementation of
securitization. The BPU further determined that the final aggregate
rate reduction in 2002 of 13.9% is required by the Energy Competition
Act and is not contingent on the implementation of securitization.
On July 26, 1999, the BPU approved PSE&G's compliance tariff filing
reflecting the 5% decrease in rates on a provisional basis (see Note 2.
Regulatory Issues). On August 1, 1999, PSE&G implemented this rate
reduction as required by the BPU under the Energy Master Plan
Proceedings.
Shopping Credits
o Shopping credits (credits which a customer electing a new supplier of
electricity will receive from PSE&G) will be established for four
years and will include the cost of energy, capacity, transmission,
ancillary services, losses, taxes and a retail adder. The average
overall credits will be as follows:
1999: 4.95 cents per kilowatt hour (kWh)
2000: 5.03 cents per kWh
2001: 5.06 cents per kWh
2002: 5.10 cents per kWh
2003: 5.10 cents per kWh
Stranded Costs
o The BPU concluded that PSE&G should be provided the opportunity to
recover up to $2.94 billion (net of tax) of stranded costs, through
securitization of $2.4 billion (discussed below) and an opportunity to
recover up to $540 million (net of tax) of its unsecuritized
generation-related stranded costs on a present value basis. The $540
million would be recovered by various means, including an explicit
market transition charge (MTC). The stranded costs recovery is subject
to a reconciliation on the collection of the unsecuritized
generation-related stranded costs.
o PSE&G was directed to use the overrecovered balance in the Electric
Levelized Energy Adjustment Clause (LEAC) as of July 31, 1999 as a
mitigation tool for stranded cost recovery associated with non-utility
generation (NUG) contracts. PSE&G will apply the overrecovery as a
credit to the starting deferred balance of the non-utility generation
market transition charge (NTC) to offset future above market costs
and/or contract buyouts otherwise recoverable from ratepayers.
Securitization
o The BPU will issue an irrevocable Bondable Stranded Costs Rate Order
(Finance Order), consistent with the provisions of the Energy
Competition Act and the Summary and Final Orders, to authorize PSE&G
to issue up to $2.525 billion of transition bonds, with a scheduled
amortization upon issuance of 15 years, representing $2.4 billion of
generation-related stranded costs (net of tax) and an estimated $125
million of transaction costs. A transition bond charge will be
collected from all customers via a single per kWh "wires charge" to be
subject to adjustment at least annually. For an update, see
Securitization Filing below.
o The BPU determined that the taxes related to securitization, which
reflect the grossed up revenue requirements associated with the $2.4
billion in net of tax stranded costs being securitized, are
recoverable stranded costs. The BPU determined that such taxes should
not be collected through the transition bond charge; rather, such
taxes will be collected via a separate MTC. The duration of this
separate MTC shall be identical to the duration of the transition bond
charge.
o The BPU clarified the language concerning the use of the net proceeds
of securitization to indicate that the refinancing or retirement of
debt and/or equity shall be done in a manner that will not
substantially alter PSE&G's overall capital structure.
Sale of Generation-Related Assets
o The BPU directed the sale by PSE&G of its generation-related assets to
a separate unregulated subsidiary of PSEG at a price of $2.443
billion. Such separate company will become an exempt wholesale
generator (EWG) under the Public Utility Holding Company Act (PUHCA)
upon receipt of Federal Energy Regulatory Commission (FERC) approval.
Any gains resulting from any sale of the generation-related assets to
a third party which occurs within five years from August 1, 1999 will
be shared equally between ratepayers and shareholders. For further
discussion, see Generation-Related Asset Sale to PSEG Power below.
Basic Generation Service
o PSE&G is obligated to provide basic generation service (BGS) to
customers who do not choose another electric supplier. PSE&G will
contract with PSEG Power LLC (PSEG Power) to provide the energy and
capacity required to meet its BGS and Off-Tariff Rate Agreements
(OTRA) obligations for the first three years of retail choice (see
Generation-Related Asset Sale to PSEG Power below). PSEG will be
prohibited from promoting such service as a competitive alternative to
other electricity suppliers and marketers. BGS will be competitively
bid for the fourth year and annually thereafter. Any payments to PSE&G
resulting from BGS being bid out for year 4 of the transition period
is required to be credited to the deferred societal benefit costs
balance for purposes of establishing the societal benefit clause (SBC)
rate in year 5, and may not be retained by PSE&G or otherwise utilized
to recover unsecuritized generation-related stranded costs.
Societal Benefit Clause and Non-utility Generation Market Transition Clause
o Societal benefit costs and stranded costs associated with NUG
contracts will be collected through separate charges. Both charges
will remain constant through the four-year transition period and PSE&G
will use deferred accounting, including interest on any
over/underrecoveries. The charges will be reset annually thereafter.
The charge for the stranded NTC will be initially set at the 1999
level of $183 million annually and will also use deferred accounting
on any over/underrecoveries. Any NUG contract buyouts will also be
charged to the NTC and will be subject to deferral accounting. The SBC
will include costs related to: 1) social programs which include the
universal service fund; 2) nuclear plant decommissioning; 3) demand
side management (DSM) programs (see Other Regulatory Issues); 4)
manufactured gas plant remediation; and 5) consumer education.
Electric Distribution Depreciation
o PSE&G was directed by the BPU to record a regulatory liability by
reducing its depreciation reserve for its electric distribution assets
by $568.7 million. This regulatory liability will be amortized over
the period from January 1, 2000 to July 31, 2003 (see Note 3.
Extraordinary Charge and Other Accounting Impacts of Deregulation).
Securitization Filing
---------------------
On June 8, 1999, PSE&G filed a petition with the BPU relating to the
proposed securitization transaction. PSE&G petitioned the BPU for an irrevocable
Finance Order to authorize, among other things, the imposition of an irrevocable
non-bypassable transition bond charge on PSE&G's customers; the sale of PSE&G's
property right in such charge created by the Energy Competition Act to a
bankruptcy-remote financing entity; the issuance and sale of $2.525 billion of
transition bonds by such entity in payment therefor; and the application by
PSE&G of the transition bond proceeds to retire outstanding debt and/or equity.
Subject to the receipt of the Finance Order and required State and Federal
approvals and market conditions then prevailing, PSE&G currently anticipates
that such securitization will occur in the Fall of 1999, as to which no
assurances can be given. This proceeding is currently in the discovery phase.
Under New Jersey law, a 45-day period is available for a party to the
proceedings and ratepayers to appeal the Finance Order once it is issued. PSEG
and PSE&G cannot predict whether any appeals will be filed with respect to the
Finance Order by any of the parties entitled to do so.
In anticipation of the Finance Order and required State and Federal
approvals, PSE&G created PSE&G Transition Funding LLC, a wholly owned subsidiary
of PSE&G, to issue such transition bonds. PSE&G Transition Funding LLC submitted
an initial filing for registration of its transition bonds with the Securities
and Exchange Commission on July 23, 1999.
Generic Issues
--------------
Additionally, the BPU is expected to issue a series of orders that will
decide generic issues related to the deregulation of the electric and gas
industry in New Jersey. Proposed standards were issued by the BPU for comment on
March 31, 1999. These include affiliate relationships (including fair
competition and affiliate transactions), environmental issues, anti-slamming and
accounting and reporting standards. Hearings on the proposed affiliate
relationships standards were held during April 1999 and an order is expected in
the third quarter of 1999.
On July 26, 1999, the BPU approved Interim Environmental Information
Disclosure Standards which require electric power suppliers or basic generation
service providers serving retail customers to disclose to such customers,
including residential, commercial and industrial customers, a uniform, common
set of information about the environmental characteristics of the energy
purchased by the customer. The standards prescribe a label format which must be
used to disclose the environmental information and must be distributed as part
of the customer's billing materials or in other mailings, as determined by the
BPU, and on customer contracts and marketing materials. The environmental
information to be disclosed includes, but is not limited to, fuel mix, air
emissions and the electric power supplier's support of energy efficiency.
On June 21, 1999, the BPU approved Interim Government Energy Aggregation
Program Standards to apply to all government aggregators and third party
suppliers. These rules provide bidding specifications, guidelines for
cooperative purchasing of electric generation service and/ or gas supply service
and required contract provisions for government energy aggregation programs.
On May 12, 1999, the BPU approved Interim Anti-Slamming Standards. These
rules include specific methods to verify all requests to switch providers. Under
the interim rules, written confirmation will be the only acceptable method for
electric and gas customers to switch suppliers, although other methods could be
added later. The Energy Competition Act set fines of up to $10,000 per slamming
incident. In addition, power marketers must clearly identify themselves and
their rates in all solicitations. Electricity suppliers also must include only
those discounts they provide, not those mandated by the State.
Also on May 12, 1999, the BPU approved Interim Retail Choice Consumer
Protection Standards. These standards include advertising standards, marketing
standards and credit and contract requirements including the requirement to
obtain a customer's written signature on a contract before a third party
supplier would be allowed to provide electric generation service or gas supply
service to a retail customer. The standards require that customer bills contain
sufficient information to allow customers to determine the components of their
bills. Also, customer information shall not be disclosed, sold or transferred to
a third party without the affirmative written consent of the customer and
complaint rules are delineated. The standards also contain rules regarding when
termination for non-payment can be made.
Also on May 12, 1999, the BPU approved Interim Licensing and Registration
Standards. Electric power suppliers and gas suppliers must apply for and obtain
a license from the BPU pursuant to these standards following the procedures
therein. Energy agents and private aggregators must also register with the BPU
under such standards. These standards establish guidelines for obtaining the
license which allows contracting, offering to contract, enrolling, providing
generation service or gas supply service or arranging for a contract for the
provision of those services. Rules for maintaining and renewing a license are
also contained in these standards.
Retail Choice
-------------
With the opening of retail choice in New Jersey, and to comply with
legislative requirements, customer billing will be changing throughout 1999.
These changes began on August 1, 1999 with the introduction of a 5% rate
reduction and a "Price to Compare" (Shopping Credit) message on all customer
bills using the current bill format. PSE&G will introduce a new customer bill
format on October 1, 1999 that will present the customer with unbundled electric
components, the 5% rate reduction and the Price to Compare. Once securitization
proceeds are obtained, securitization charges will also be included on customer
bills.
PSE&G will provide a single bill option in November that will include third
party supplier charges. Customer payments will be applied as directed by the BPU
and distributed to third party suppliers as appropriate.
Gas Unbundling
--------------
The Energy Competition Act requires that all residential customers have the
ability to choose a competitive gas supplier by December 31, 1999. As a result,
on March 17, 1999, the BPU issued its Order requiring each natural gas utility
to submit a rate unbundling filing.
The BPU established a gas rate unbundling filing deadline of April 30,
1999, to include the following:
o A proposed basic supply rate(s) applicable to each customer class.
o A proposed unbundled billing credit(s) applicable to customers who
receive billing services from a third party.
o A separate SBC to recover all Remediation Adjustment Clause (RAC)
expenses, DSM program expenses and other expenses reasonably incurred
and currently in rates recoverable via the SBC.
o A proposed regulatory asset charge, if applicable.
o A proposed transportation rate.
On April 30, 1999, PSE&G submitted its gas unbundling compliance filing
with the BPU as required by the BPU's March 17, 1999 Order. As required, this
filing completes the unbundling of PSE&G's gas rates. Unbundled rates were
developed for PSE&G's remaining bundled gas Rate Schedules: RSG (Residential
Service Gas), SLG (Street Lighting Gas Service), CFG (Cogeneration Firm Gas
Service) and UVNG (Uncompressed Vehicular Natural Gas Service). These bundled
rates will cease to exist when the new applicable unbundled FT (Firm
Transportation) and CS (Firm Commodity Service) rates are approved. Hearings are
expected in September 1999 with the BPU expected to render a decision by the end
of November 1999. The discovery process has been completed and intervenor
testimony has been filed. PSE&G cannot predict the outcome of this proceeding.
The Energy Competition Act also mandated similar rules for the gas industry
as those for the electric industry addressing affiliate relations, consumer
protections, among others. The standards adopted by the BPU for generic issues
also apply to the competitive gas industry (see Generic Issues).
Generation-Related Asset Sale to PSEG Power
-------------------------------------------
In anticipation of the Final Order directing the sale of generation-related
assets, in June 1999, PSEG organized PSEG Power and its subsidiaries, which will
purchase PSE&G's electric generation-related assets. PSEG Power will manage such
assets through its wholly owned subsidiaries, PSEG Fossil LLC (PSEG Fossil),
PSEG Nuclear LLC (PSEG Nuclear) and PSEG Energy Resources and Trade LLC (PSEG
ER&T). It is currently anticipated that such transaction will occur during the
fourth quarter of 1999.
Certain regulatory approvals are required prior to the sale of the
generation-related assets to PSEG Power. PSEG Power must obtain final approval
from the BPU, the Nuclear Regulatory Commission (NRC) (to transfer PSE&G's
nuclear licenses) and the FERC (to be recognized as an EWG). PSEG and PSE&G will
also have to resolve a number of other issues related to taxes, environmental
restrictions and financing.
Requests for transfer of the NRC licenses from PSE&G to PSEG Nuclear were
filed with the NRC on June 4, 1999 for the Salem Generating Station, Units 1 and
2 (Salem 1 and 2) and for the Hope Creek Generating Station (Hope Creek).
Requests for transfer of the NRC licenses from PSE&G to PSEG Nuclear were filed
with the NRC on July 1, 1999 for PSE&G's ownership in the Peach Bottom Atomic
Power Station, Units 2 and 3 (Peach Bottom 2 and 3). PSE&G's target approval
date is October 1, 1999, as to which no assurances can be given.
Additionally, filings were made to the FERC in June 1999 to transfer FERC
jurisdictional assets to PSEG Fossil and PSEG Nuclear; to approve rates for the
services of PSEG Fossil, PSEG Nuclear and PSEG ER&T; to approve the transfer of
contracts to PSEG ER&T from PSE&G and to approve the interconnection agreements
between PSEG Fossil and PSE&G and between PSEG Nuclear and PSE&G. PSE&G's target
approval date is October 1, 1999, as to which no assurances can be given. Once
the Final Order is received, PSE&G plans to apply to the FERC for EWG status for
PSEG Nuclear and PSEG Fossil.
As noted previously and as directed by the Summary Order, PSE&G will sell
its generation property, plant and equipment for $2.443 billion plus the net
book value of other generation-related assets and liabilities transferred at the
time of purchase, currently estimated to be between $200 million and $400
million, and will transfer all rights and obligations associated with those
assets and liabilities. PSE&G will record contributed capital for the difference
between the net book value of the generation property, plant and equipment and
the $2.443 billion of sale proceeds. In addition to those assets identifiable on
the consolidated balance sheets, PSE&G had $79 million of Materials and
Supplies, $53 million of Environmental Costs, $419 million of Deferred Taxes and
Investment Tax Credits and certain other liabilities related to its generation
business at June 30, 1999. All of these generation-related assets reflect the
impairment recorded in the second quarter of 1999 (see Note 3. Extraordinary
Charge and Other Accounting Impacts of Deregulation).
Other Regulatory Issues
Energy Efficiency and Renewable Energy (Formerly DSM)
-----------------------------------------------------
The BPU adopted rules in 1991 to encourage utilities to offer DSM-related
load management and conservation services. These rules were re-adopted in 1996
and are designed to treat DSM on equal regulatory footing with supply side or
energy production investments. The Energy Competition Act requires the
continuation of these energy efficiency programs and the initiation of renewable
energy programs. The costs for energy efficiency and renewable energy programs
are to be recovered through a societal benefits charge on all electric and gas
customers' bills, initially set at the level in rates for DSM cost recovery in
place on February 9, 1999, which was approximately $190 million, annually.
Within the subsequent twelve months, the BPU is required to complete a statewide
comprehensive resource analysis of energy efficiency and renewable energy
programs and determine the appropriate level of funding for each utility based
on such analysis. On June 9, 1999, the BPU formally initiated these proceedings.
In April 1998, the BPU approved $180.5 million per year of DSM cost
recovery for PSE&G's electric DSM programs via an increase of $150.8 million in
the demand side adjustment factor (DSAF) component of the LEAC. The Division of
the Ratepayer Advocate (Ratepayer Advocate) appealed the BPU's order, seeking to
overturn the BPU's decision. On July 2, 1999, the Appellate Division of the
Superior Court of New Jersey filed an opinion affirming the BPU's DSAF decision
and thus, rejecting the Ratepayer Advocate's DSAF appeal. PSE&G cannot predict
whether the Ratepayer Advocate will pursue a further appeal. If such an appeal
were successful, there could be a material adverse impact on PSEG's and PSE&G's
financial condition, results of operations or net cash flows.
Non-utility Generation Buydown
------------------------------
Under Federal and State regulations, utilities were required to enter into
long-term power purchase agreements with NUGs at prices which have subsequently
proven to be above market. PSE&G is seeking to restructure certain of its BPU
approved contracts with NUGs, which are estimated to be $1.6 billion above
assumed future market prices. In July 1999, PSE&G and American Ref-Fuel Company
announced an agreement to amend a NUG contract originally signed in 1985 for the
Essex County Resource Recovery Facility, a waste incinerator located in Newark,
New Jersey. Under the terms of the agreement, PSE&G ratepayers will receive a
cost reduction of up to $100 million over the remaining 20 years of the
contract. The agreement has been filed with the BPU and is pending BPU approval
of its terms. If the BPU does not grant approval by September 30, 1999, either
party has the option to withdraw it. If approved by the BPU, the costs to
terminate this contract will be recovered through the NTC.
Note 3. Extraordinary Charge and Other Accounting Impacts of Deregulation
As a result of the BPU's issuance of the Summary Order in April 1999, PSE&G
determined that SFAS 71 was no longer applicable to the electric generation
portion of its business, in accordance with EITF 97-4. Accordingly, in the
second quarter, PSE&G recorded an extraordinary charge to earnings of $790
million (after tax). PSE&G accounted for this charge consistent with the
requirements of SFAS 101. This charge was based on an assumption that the Final
Order would not be materially different from the Summary Order. If the Final
Order were to be materially different from the Summary Order, the extraordinary
charge could change.
The extraordinary charge consisted primarily of the write down of PSE&G's
nuclear and fossil generating stations in accordance with SFAS 121. PSE&G
performed a discounted cash flow analysis on a unit-by-unit basis to determine
the amount of the impairment. The estimated net cash flows for each unit
included estimated future revenues. As a result of this impairment analysis, the
net book value of the generating stations was reduced by approximately $5.0
billion (pretax) or approximately $3.09 billion (after-tax). This amount was
offset by the creation of a regulatory asset related to the future receipt of
securitization proceeds, as provided for in the Summary Order. The amount of the
regulatory asset is approximately $4.058 billion, pretax, or $2.4 billion
after-tax.
In addition to the impairment of PSE&G's electric generating stations, the
extraordinary charge related to the discontinuation of SFAS 71 and consisted of
various accounting adjustments to reflect the absence of cost of service
regulation in the electric generation portion of the business in the future. The
adjustments primarily related to materials and supplies, general plant items and
liabilities for certain contractual and environmental obligations.
Other accounting impacts of the discontinuation of SFAS 71 included
reclassifying the Accrued Nuclear Decommissioning Reserve and the Accrued Cost
of Removal for generation-related assets from Accumulated Depreciation to
Long-Term Liabilities. PSE&G also reclassified a $568.7 million excess
depreciation reserve related to PSE&G's electric distribution assets from
Accumulated Depreciation to a Regulatory Liability, pursuant to the Summary
Order. Such amount will be amortized in accordance with the terms of the Summary
Order over the period from January 1, 2000 to July 31, 2003.
Note 4. Regulatory Assets and Liabilities
Regulatory assets and liabilities are recorded in accordance with the
provisions of SFAS 71. In general, SFAS 71 recognizes that accounting for
rate-regulated enterprises should reflect the relationship of costs and revenues
as determined by regulators. As a result, a regulated utility may defer
recognition of costs (a regulatory asset) or recognize obligations (a regulatory
liability) if it is probable that, through the ratemaking process, there will be
a corresponding increase or decrease in revenues. Accordingly, PSE&G has
deferred certain costs, which are being amortized over various periods. To the
extent that collection of such costs or payment of liabilities is no longer
probable as a result of changes in regulation and/or PSE&G's competitive
position, the associated regulatory asset or liability has been charged or
credited to income.
Starting in the second quarter of 1999, PSE&G no longer met the
requirements for the application of SFAS 71 to the electric generation portion
of its business. In accordance with SFAS 101 and EITF 97-4, regulatory assets
and liabilities related to the generation portion of PSE&G's business were
written off, except to the extent the Summary Order provided for future recovery
through regulated operations. Additionally, certain new regulatory assets and
regulatory liabilities were recorded, in compliance with the Summary Order. The
items listed below were impacted by the Energy Master Plan Proceedings. For
discussion of the Energy Master Plan Proceedings, see Note 2. Regulatory Issues
and Note 3. Extraordinary Charge and Other Accounting Impacts of Deregulation.
SFAS 109 Income Taxes: This amount represents the regulatory asset related
to the implementation of SFAS 109, "Accounting for Income Taxes" (SFAS 109). Due
to the discontinuation of SFAS 71 for the electric generation portion of PSE&G's
business, the deferred taxes related to these assets have been reduced and
included as an offset to the Extraordinary Item. At June 30, 1999, SFAS 109
Income Taxes were $296 million as compared to the balance at March 31, 1999 of
$690 million. For additional information on the discontinuation of SFAS 71 and
the Extraordinary Item, see Note 3. Extraordinary Charge and Other Accounting
Impacts of Deregulation.
Regulatory Asset - Stranded Costs: In anticipation of securitization, PSE&G
has recorded this regulatory asset to reflect the future revenues which will be
collected via the securitization transition charge which is expected to be
authorized by the BPU's Finance Order. At June 30, 1999, Deferred Stranded Costs
were $4.058 billion. See Note 3. Extraordinary Charge and Other Accounting
Impacts of Deregulation.
Regulatory Liability - Excess Depreciation Reserve: In connection with the
Energy Master Plan, the BPU has required PSE&G to reduce its depreciation
reserve for its electric distribution assets by $568.7 million and to amortize
such reserve over the period from January 1, 2000 to July 31, 2003. In 2000 and
2001, $125 million will be amortized each year. In 2002 and 2003, $135 million
and $183.7 million will be amortized, respectively.
Regulatory Liability - Overrecovered Electric Energy Costs: As provided by
the BPU in its Summary Order, PSE&G continued to follow deferred accounting
treatment for the LEAC through July 31, 1999. At June 30, 1999, Overrecovered
Electric Energy Costs were $79 million. Per the Summary Order, the overrecovered
balance as of July 31, 1999 will be applied as a credit to the starting deferred
balance of the NTC.
Note 5. Commitments and Contingent Liabilities
Nuclear Operating Performance Standard (OPS)
PECO Energy Company (PECO Energy), Delmarva Power & Light Company (DP&L)
and PSE&G, three of the co-owners of Salem 1 and 2 and Peach Bottom 2 and 3,
have agreed to an OPS through December 31, 2011 for Salem and through December
31, 2007 for Peach Bottom. Under the OPS, the station operator is required to
make payments to the non-operating owners (excluding Atlantic City Electric
Company (ACE)) commencing in January 2001 if the three-year historical average
net maximum dependable capacity factor for that station, calculated as of
December 31 of each year commencing with December 31, 2000, falls below 40%. Any
such payment is limited to a maximum of $25 million per year. The parties have
further agreed to forego litigation in the future, except for limited cases in
which the operator would be responsible for damages of no more than $5 million
per year.
Year 2000 Readiness Disclosure
Many of PSEG's and PSE&G's systems, which include information technology
applications, plant control and telecommunications infrastructure systems, must
be modified due to computer program limitations in recognizing dates beyond
1999. Management estimates the total cost related to Year 2000 readiness will
approximate $83 million, to be incurred through 2001, of which $8 million was
incurred in 1997, $27 million was incurred in 1998 and approximately $36 million
is expected to be incurred in 1999. During the six months ended June 30, 1999,
$12 million was incurred. A portion of these costs is not likely to be
incremental to PSEG or PSE&G, but rather, represents a redeployment of existing
personnel/resources.
PSE&G and PSEG Energy Holdings Inc. (Energy Holdings), which are wholly
owned subsidiaries of PSEG, are continuing their installation of computer
software programs (SAP) from SAP America, Inc. to replace certain major business
systems. SAP America, Inc. has represented that SAP is Year 2000 compliant, and
thus, installation of SAP will eliminate the need to modify those business
systems for Year 2000 compliance. The phased implementation of SAP to replace
those systems is scheduled to be completed before January 1, 2000. The cost of
implementing SAP is not included in the above cost estimates since SAP
implementation has not been accelerated for Year 2000 purposes. For its newly
acquired companies, PSEG Energy Technologies Inc. (Energy Technologies), a
wholly owned subsidiary of Energy Holdings, is replacing the infrastructure
systems and applications with Energy Technologies' standard infrastructure
systems and applications, which are Year 2000 compliant.
If PSEG, PSE&G, their domestic and international subsidiaries, their
project affiliates, other members of the PJM Interconnection, LLC (PJM), PJM
trading partners supplying power through PJM, PSEG's or PSE&G's critical vendors
and/or customers or the capital markets are unable to meet the Year 2000
deadline, such inability could have a material adverse impact on PSEG's and
PSE&G's operations, financial condition, results of operations or net cash
flows.
Combustion Turbines
PSEG has entered into contracts to purchase combustion turbines. PSEG's
commitment under these contracts is approximately $392 million to be expended
through December 2001. Through July 31, 1999, payments of approximately $56
million were made under these contracts.
Construction and Fuel Supplies - PSE&G
PSE&G has substantial commitments as part of its ongoing construction
program. PSE&G's construction program is continuously reviewed and periodically
revised as a result of changes in economic conditions, revised load forecasts,
scheduled retirement dates of existing facilities, business strategies, site
changes, cost escalations under construction contracts, requirements of
regulatory authorities and laws, the timing of and amount of electric and gas
rate changes and the ability of PSE&G to raise necessary capital.
In concert with separating the electric generation portion of the business
from PSE&G's regulated transmission and distribution businesses and with
reviewing PSE&G's strategic initiatives, PSEG is in the process of assessing the
construction requirements of its businesses. This will include a breakdown of
anticipated construction expenditures between the generation-related and the
transmission and distribution businesses. For discussion of the Energy Master
Plan Proceedings and their impacts, see Note 2. Regulatory Issues.
Construction and Investment Expenditures - Energy Holdings
Through June 30, 1999, Energy Holdings' subsidiaries made investments
totaling approximately $640 million. This included the acquisition in June by
PSEG Global Inc. (Global) of an interest in a Chilean distribution company
serving customers in Chile and Peru. Global invested $268 million including fees
and closing costs, and financed an additional $160 million with project debt
consolidated on Energy Holdings' balance sheet that is non-recourse to Global,
Energy Holdings and PSEG. Projected investment expenditures for the second half
of 1999 are approximately $400 million, comprised of investments in generation
and distribution facilities and leveraged lease transactions. Energy Holdings
has approximately $35 million of debt maturing in November 1999, all of which is
expected to be refinanced through existing credit facilities.
Sale of Generation Plant in Newark, New Jersey
In July 1999, Global entered into an agreement for the sale of its 50%
partnership interest in a 137 megawatt (MW) gas-fired combined-cycle
co-generation facility in Newark, New Jersey. Global expects to close this
transaction in the third quarter of 1999 and recognize an after-tax gain of
approximately $40 million.
Site Restorations and Other Environmental Costs
It is difficult to estimate the future financial impact of environmental
laws, including potential liabilities. PSEG and PSE&G accrue environmental
liabilities when it is probable that a liability has been incurred and the
amount of the liability is reasonably estimable. Depending on the site,
provisions for estimated losses from environmental remediation are based
primarily on internal and third party environmental studies, estimates as to the
number and participation level of any other Potentially Responsible Parties
(PRP), the extent of the contamination and the nature of required remedial and
restoration actions.
Certain environmental costs are currently recoverable through the RAC and
are expected to be recoverable in accordance with the Summary Order, through the
SBC. Other environmental costs may be recoverable through future recovery
mechanisms, including the SBC; however, no assurances can be given. To the
extent these costs are material and not recoverable, they could have a material
adverse impact on PSEG's and PSE&G's financial condition, results of operations
or net cash flows.
Hazardous Waste
Certain Federal and state laws authorize the U.S. Environmental Protection
Agency (EPA) and the New Jersey Department of Environmental Protection (NJDEP),
among other agencies, to issue orders and bring enforcement actions to compel
responsible parties to investigate and take remedial actions at any site that is
determined to present an actual or potential threat to human health or the
environment because of an actual or threatened release of one or more hazardous
substances. Because of the nature of PSEG's and PSE&G's business, including the
production of electricity, the distribution of gas and, formerly, the
manufacture of gas, various by-products and substances are or were produced or
handled which contain constituents classified as hazardous. PSE&G generally
provides for the disposal or processing of such substances through licensed
independent contractors. However, these statutory provisions impose joint and
several responsibility without regard to fault on all responsible parties,
including the generators of the hazardous substances, for certain investigative
and remediation costs at sites where these substances were disposed of or
processed. PSE&G has been notified with respect to a number of such sites and
the investigation and remediation of these potentially hazardous sites is
receiving attention from the government agencies involved. Generally, actions
directed at funding such site investigations and remediation include all
suspected or known responsible parties. Based on current information, except as
discussed below with respect to its manufactured gas plant Remediation Program,
PSEG and PSE&G do not expect its expenditures for any such site, individually or
all such current sites in the aggregate, to have a material effect on financial
condition, results of operations or net cash flows.
The NJDEP has recently revised regulations concerning site investigation and
remediation. These regulations will require an ecological evaluation of
potential injuries to natural resources in connection with a remedial
investigation of contaminated sites. The NJDEP is presently working with the
utility industry to develop procedures for implementing these regulations. These
regulations may substantially increase the costs of remedial investigations and
remediations, where necessary, particularly at sites situate on surface water
bodies. PSE&G and predecessor companies owned and/or operated certain facilities
situate on surface water bodies, certain of which are currently the subject of
remedial activities. The financial impact of these regulations on these projects
is not currently estimable. PSE&G does not anticipate that the compliance with
these regulations will have a material adverse effect on its financial position,
results of operations or net cash flows.
PSE&G Manufactured Gas Plant Remediation Program
In 1988, NJDEP notified PSE&G that it had identified the need for PSE&G,
pursuant to a formal arrangement, to systematically investigate and, if
necessary, resolve environmental concerns existing at PSE&G's former
manufactured gas plant sites. To date, NJDEP and PSE&G have identified 38 former
manufactured gas plant sites. PSE&G is currently working with NJDEP under a
program to assess, investigate and, if necessary, remediate environmental
concerns at these sites. The Remediation Program is periodically reviewed and
revised by PSE&G based on regulatory requirements, experience with the
Remediation Program and available remediation technologies. The cost of the
Remediation Program cannot be reasonably estimated, but experience to date
indicates that costs of approximately $20 million per year could be incurred
over a period of about 30 years and that the overall cost could be material to
PSEG's and PSE&G's financial condition, results of operations or net cash flows.
The Energy Competition Act provides for the continuation of RAC programs. The
Summary Order provides for the recovery of costs for this remediation effort
through the SBC.
Air Pollution Control
In June 1998, NJDEP adopted regulations implementing a memorandum of
understanding among 11 Northeastern states and the District of Columbia,
establishing a regional plan for reducing nitrogen oxide (NOx) emissions from
utilities and large industrial boilers. The extent of investment in control
technologies, operational changes and purchases of allowances required to comply
with these regulations will be directly related to the number of allowances
PSE&G receives. PSE&G received a preliminary allocation of allowances in March
1999, which are sufficient for the Summer of 1999. The final allocation will be
determined in accordance with the NJDEP regulations in November 1999, which is
subsequent to the May 1 through September 30, 1999 period governed by the
regulations. It is currently anticipated that the NOx allowances will be
transferred to PSEG Power.
PSE&G has attempted to minimize the uncertainty associated with the timing
of the final allocation by purchasing allowances, upgrading control technologies
and estimating the expected allocation with as much precision as is practicable
using available data. According to PSE&G's present analysis, the potential costs
for purchasing additional NOx budget allowances should not exceed a total of $10
million through December 31, 2002. Expenditures associated with installing
control technology could result in an additional $72 million. However, PSE&G is
currently analyzing alternatives which could preclude the necessity of capital
improvements.
Passaic River Site
The EPA has determined that a six mile stretch of the Passaic River in
Newark, New Jersey is a "facility" within the meaning of that term under the
Federal Comprehensive Environmental Response, Compensation and Liability Act of
1980 (CERCLA) and that, to date, at least thirteen corporations, including
PSE&G, may be potentially liable for performing required remedial actions to
address potential environmental pollution at the facility. The EPA anticipates
identifying other PRPs. One PRP (Cooperating Party) entered into a consent
decree with the EPA in 1994 obligating it to conduct a remedial investigation
and feasibility study of available and applicable corrective actions for the
site. Future costs for prospective remedial actions may be material to PSE&G.
In a separate matter, PSE&G and certain of its predecessors operated
industrial facilities at properties along the stretch of the Passaic River
designated as the site. In April 1996, the EPA directed PSE&G to provide
information concerning the nature and quantity of raw materials, by-products and
wastes which may have been generated, treated, stored or disposed at certain of
these facilities. The facilities are PSE&G's former Harrison Gas Plant and Essex
Generating Station. PSE&G submitted responses to the EPA requests for these
sites in August 1996. In July 1997, the EPA named PSE&G as a PRP for this site.
PSE&G cannot predict what action, if any, the EPA or any third party may take
against PSE&G with respect to this site, or in such event, what costs PSE&G may
incur to address any such claims. However, such costs may be material.
Subsurface Contamination
Potential environmental liabilities related to subsurface contamination at
certain generating stations have been identified. The law that led to the
identification is the Industrial Site Recovery Act (ISRA) that applies to the
sale of certain assets. Although the sale of generation-related assets to PSEG
Power will trigger an ISRA review, PSEG and PSE&G will make an application for
an exemption on the basis that the sale is being made as part of a corporate
reorganization. In the second quarter of 1999, PSEG recorded a $31 million,
after tax, liability related to these obligations (see Note 3. Extraordinary
Charge and Other Accounting Impacts of Deregulation).
Note 6. Financial Instruments and Risk Management
PSEG's operations give rise to exposure to market risks from changes in
commodity prices, interest rates, foreign currency exchange rates and securities
prices. PSEG's policy is to use derivative financial instruments for the purpose
of managing market risk consistent with its business plans and prudent business
practices.
Fair Value of Financial Instruments
The estimated fair value was determined using the market quotations or
values of instruments with similar terms, credit ratings, remaining maturities
and redemptions at June 30, 1999 and December 31, 1998, respectively. Note that
certain future events in connection with securitization and the sale by PSE&G of
generation-related assets to PSEG Power will trigger certain redemption features
of certain PSE&G mortgage bonds.
<TABLE>
<CAPTION>
June 30, 1999 December 31, 1998
------------------------- ----------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
------------ ----------- ------------- ------------
(Millions of Dollars)
<S> <C> <C> <C> <C>
Long-Term Debt (A):
PSEG.................................................. $575 $575 $275 $275
Energy Holdings....................................... 987 981 762 769
PSE&G................................................. 4,128 4,174 4,145 4,389
Preferred Securities Subject to Mandatory Redemption:
PSE&G Cumulative Preferred Securities................. 75 74 75 77
Monthly Guaranteed Preferred Beneficial Interest in
PSE&G's Subordinated Debentures.................... 210 213 210 213
Quarterly Guaranteed Preferred Beneficial Interest in
PSE&G's Subordinated Debentures.................... 303 306 303 315
Quarterly Guaranteed Preferred Beneficial Interest in
PSEG's Subordinated Debentures..................... 525 484 525 518
<FN>
(A) Includes current maturities. Includes interest rate swaps of $33 million
and $150 million for Energy Holdings and PSEG, respectively, for the period
ended June 30, 1999 and interest rate swaps of $44 million and $150 million
for Energy Holdings and PSEG, respectively, for the period ended December
31, 1998.
</FN>
</TABLE>
Commodity-Related Instruments--PSE&G
At June 30, 1999 and December 31, 1998, PSE&G held or issued commodity and
financial instruments that reduce exposure to market fluctuations from factors
such as weather, environmental policies, changes in demand, changes in supply,
state and Federal regulatory policies and other events. These instruments, in
conjunction with owned electric generating capacity and physical gas supply
contracts, are designed to cover estimated electric and gas customer
commitments. PSE&G uses futures, forwards, swaps and options to manage and hedge
price risk related to these market exposures.
At June 30, 1999, PSE&G had outstanding commodity financial instruments
with a notional contract quantity of 8.9 million megawatt-hours (MWH) of
electricity and 49.2 million MMBTU (million British thermal units) of natural
gas. At December 31, 1998, PSE&G had outstanding commodity financial instruments
with a notional contract quantity of 1.6 million MWH of electricity and 65.2
million MMBTU of natural gas. Notional amounts are indicative only of the volume
of activity and are not a measure of market risk.
As discussed in Note 1. Basis of Presentation/Summary of Significant
Accounting Policies, PSE&G implemented EITF 98-10 effective January 1, 1999. As
a result, PSE&G's energy trading contracts were marked to market and gains and
losses from such contracts were included in earnings. Previously, such gains and
losses were recorded upon settlement of the contracts. PSE&G recorded $6 million
and $13 million of gains in the quarters ended June 30, 1999 and 1998,
respectively. PSE&G recorded $17 million and $18 million of gains in the six
months ended June 30, 1999 and 1998, respectively.
Commodity-Related Instruments--Energy Holdings
Energy Technologies' policy is to enter into natural gas and electricity
futures contracts and forward purchases to lock in prices related to future
fixed sales commitments. Whenever possible, Energy Technologies attempts to be
100% covered on its electric and gas sales positions during periods of peak
volatility. During the six months ended June 30, 1999 and 1998, Energy
Technologies entered into futures contracts to buy natural gas and electricity
related to fixed-price sales commitments. Energy Technologies had 99% and 90% of
its fixed price natural gas sales commitments hedged and 97% and 63% of its
fixed price electric commodity sales commitments hedged at June 30, 1999 and
December 31, 1998, respectively. As of June 30, 1999 and December 31, 1998,
Energy Technologies had a net unrealized hedge gain of approximately $2 million
and net unrealized hedge loss of $5 million, respectively, for its electric and
gas hedges.
Equity Securities--Energy Holdings
PSEG Resources Inc. (Resources) directly and indirectly has investments in
equity securities. Resources carries its investments in equity securities at
their approximate fair value as of the reporting date. Consequently, the
carrying value of these investments is affected by changes in the fair value of
the underlying securities. Fair value is determined by adjusting the market
value of the securities for liquidity and market volatility factors, where
appropriate. The aggregate fair values of such investments which had available
market prices at June 30, 1999 and December 31, 1998 were $166 million and $204
million, respectively. A sensitivity analysis has been prepared to estimate
Energy Holdings' exposure to market volatility of these investments. The
potential change in fair value resulting from a hypothetical 10% change in
quoted market prices of these investments amounted to $15 million at June 30,
1999 and $17 million at December 31, 1998.
<PAGE>
Foreign Currencies--Energy Holdings
In accordance with their growth strategies, Global and Resources have made
approximately $1.2 billion and $0.8 billion, respectively, of international
investments. As of June 30, 1999, these investments represented 11% of PSEG's
consolidated assets and contributed 8% of consolidated revenues for the six
months ended June 30, 1999. Resources' international investments are primarily
leveraged leases of assets located in Australia, the Netherlands and the United
Kingdom with associated revenues denominated in U.S. dollars and, therefore, not
subject to foreign currency risk.
Global's international investments are primarily in projects that generate
or distribute electricity in Argentina, Brazil, Chile, China and Peru. Investing
in foreign countries involves certain risks. Economic conditions that result in
higher comparative rates of inflation in foreign countries likely result in
declining values in such countries' currencies. As currencies fluctuate
vis-a-vis the U.S. dollar, there is a corresponding change in Global's
investment value in terms of the U.S. dollar. Such change is reflected as an
increase or decrease in comprehensive income, a separate component of
stockholders' equity. Net foreign currency devaluations have reduced the
reported amount of PSEG's total stockholders' equity by $170 million, $166
million of which was caused by the devaluation of the Brazilian Real, as of June
30, 1999.
In January 1999, Brazil abandoned its managed devaluation strategy and
allowed its currency, the Real, to float against other currencies. As of June
30, 1999, the Real had devalued approximately 33% against the U.S. dollar since
December 31, 1998, affecting the carrying value of Global's investment in a
Brazilian distribution company. PSEG cannot predict to what extent, if any,
further devaluation of the Brazilian Real or other currencies may occur, and,
therefore, cannot predict the impact of potential devaluation of currencies on
its financial condition, results of operations or net cash flows. For additional
information, see Note 8. Financial Information by Business Segments.
Higher comparative rates of inflation in foreign economies also means that
borrowing costs in local currency will be higher than in the United States. When
warranted, Global has financed certain foreign investments with U.S. dollar
denominated debt. While less costly to service in terms of U.S. dollars, such
debt is exposed to currency risk because a devaluation would cause repayment to
be more expensive in local currency terms since more units of local currency
would be required to repay the debt. Dollar denominated debt was incurred by
Global in Argentina, Chile and Peru to finance the acquisition of interests in
rate regulated distribution entities. These entities may be able to recover
higher costs incurred as a result of a devaluation specifically through the
terms of the concession agreement or as a pass through of higher inflation costs
in rates over time, although no assurances can be given that this will occur. In
evaluating its investment decisions, Global considers the social, economic,
political and currency risks associated with each potential project, and if
warranted, assumes a certain level of currency devaluation when making its
investment decisions. In Argentina, the currency is pegged 1:1 with the U.S.
dollar and a legislative act is required to de-couple the currency from the
dollar. Management cannot predict whether devaluation in local economies will
occur or determine the ultimate impact of such devaluation on PSEG's financial
condition, results of operations or net cash flows.
Global had consolidated project debt totaling $102 million as of June 30,
1999 associated with Global's investment in the Brazilian distribution company
noted above that is non-recourse to Global, Energy Holdings and PSEG. The debt
is denominated in the Brazilian Real and is indexed to a basket of currencies,
approximately 50% of which is the U.S. dollar. As a result, Global is subject to
foreign currency exchange rate risk which would result from exchange rate
movements between the indexed foreign currencies and the U.S. dollar. Exchange
rate changes ultimately impact the debt level outstanding in the reporting
currency and result in foreign currency gains or losses in accordance with
generally accepted accounting principles. Any related gains or losses resulting
from such exchange rate movements are included in net income for the period and
amounted to a gain of $2 million and a loss of $0.1 million in the quarters
ended June 30, 1999 and 1998 and gains of $6 million and $3 million in the six
months ended June 30, 1999 and 1998, respectively.
Although Global generally seeks to structure power purchase contracts and
other project revenue agreements to provide for payments to be made in, or
indexed to, U.S. dollars or a currency freely convertible into U.S. dollars, its
ability to do so in all cases may be limited. As Energy Holdings continues to
invest internationally, the financial statements of PSEG will be increasingly
affected by changes in the global economy.
Interest Rates--PSE&G
PSE&G is subject to the risk of fluctuating interest rates in the normal
course of business. PSE&G's policy is to manage interest rate risk through the
use of fixed and, to a lesser extent, floating rate debt. Additionally, PSE&G
may also use interest rate swap instruments to hedge interest rate risk, when
appropriate. As of June 30, 1999, a hypothetical 10% change in market interest
rates would result in a $10 million change in interest costs related to
short-term and floating rate debt.
Interest Rates--Energy Holdings
Energy Holdings is subject to the risk of fluctuating interest rates in the
normal course of business. Energy Holdings' policy is to manage interest rate
risk through the use of fixed rate debt, floating rate debt and interest rate
swaps. As of June 30, 1999, a hypothetical 10% change in market interest rates
would result in a $2 million change in interest costs related to short-term and
floating rate debt.
Global has $67 million of project debt that is non-recourse to Global and
Energy Holdings associated with investments in Argentina that was refinanced in
June 1999 for a term of one year. An interest rate swap was entered into which
effectively converts 50% of the floating rate obligation into a fixed rate
obligation. The interest rate differential to be received or paid under the
agreement is recorded over the life of the agreement as an adjustment to
interest expense. The pricing on the loan is indexed to LIBOR.
Nuclear Decommissioning Trust Funds
Contributions made to the Nuclear Decommissioning Trust Funds are invested
in debt and equity securities. The carrying values of these funds of $562
million and $524 million approximates their fair market values as of June 30,
1999 and December 31, 1998, respectively.
<PAGE>
Note 7. Income Taxes
PSEG's effective income tax rate is as follows:
<TABLE>
Quarter Ended Six Months Ended
June 30, June 30,
------------------------ --------------------------
1999 (A) 1998 1999 (A) 1998
----------- --------- ----------- ----------
<S> <C> <C> <C> <C>
Federal tax provision at statutory rate................... 35.0% 35.0% 35.0% 35.0%
New Jersey Corporate Business Tax, net of Federal benefit. 5.9% 5.9% 5.9% 5.9%
Other-- net............................................... (0.9)% 1.3% 0.7% 0.7%
----------- --------- ----------- ----------
Effective Income Tax Rate............................ 40.0% 42.2% 41.6% 41.6%
=========== ========= =========== ==========
<FN>
(A) Excludes the impact of the extraordinary charge recorded in the second
quarter of 1999. The effective income tax rate applicable to the
extraordinary charge was 30.4%. This rate is below the statutory rate of
40.85% primarily due to income taxes that were flowed through to ratepayers
in prior periods under regulated accounting methods partially offset by the
investment tax credit being credited to the benefit of PSEG's stockholders
pursuant to the proposed stipulation filed with the BPU by PSE&G and seven
other parties on March 17, 1999 (Stipulation) and the Summary Order.
</FN>
</TABLE>
Note 8. Financial Information by Business Segments
The reportable segments disclosed herein were determined based on a variety
of factors including the regulatory environment and the types of products and
services offered. Effective with the unbundling of PSE&G's rates on August 1,
1999 and the deregulation of the electric generation portion of PSE&G's
business, the basis of segment reporting will change beginning with the third
quarter of 1999. The generation portion of PSE&G's business, including energy
trading, will then be a separate reportable segment.
Information related to the segments of PSEG's business is detailed below:
<TABLE>
<CAPTION>
Other Consolidated
Electric Gas Resources Activities Total
(A)
----------- ---------- ------------ -------------- ----------------
(Millions of Dollars)
<S> <C> <C> <C> <C> <C>
For the Quarter Ended June 30, 1999:
Total Operating Revenues............. $1,020 $277 $51 $88 $1,436
Segment Income before Extraordinary Item. 161 (4) 23 1 181
Segment Net Income (Loss)............ (629) (4) 23 1 (609)
=========== ========== ============ ============== ================
For the Quarter Ended June 30, 1998:
Total Operating Revenues............. $980 $272 $43 $73 $1,368
Segment Net Income (Loss)............ 123 (12) 18 (7) 122
=========== ========== ============ ============== ================
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Other Consolidated
Electric Gas Resources Activities Total
(A)
----------- ---------- ------------ -------------- ----------------
(Millions of Dollars)
<S> <C> <C> <C> <C> <C>
For the Six Months Ended June 30, 1999:
Total Operating Revenues............. $1,986 $977 $97 $171 $3,231
Segment Income before Extraordinary Item. 259 70 42 (2) 369
Segment Net Income (Loss)............ (531) 70 42 (2) (421)
=========== ========== ============ ============== ================
For the Six Months Ended June 30, 1998:
Total Operating Revenues............. $1,882 $884 $113 $148 $3,027
Segment Net Income (Loss)............ 235 34 54 (10) 313
=========== ========== ============ ============== ================
As of June 30, 1999:
Total Assets......................... $12,202 $2,436 $1,948 $1,881 $18,467
=========== ========== ============ ============== ================
As of December 31, 1998:
Total Assets...................... $12,200 $2,469 $1,809 $1,519 $17,997
=========== ========== ============ ============== ================
<FN>
(A) Other Activities include amounts applicable to PSEG, the parent
corporation, and Energy Holdings, excluding Resources.
</FN>
</TABLE>
<PAGE>
Geographic information for PSEG is disclosed below. PSE&G does not have
foreign investments or operations.
<TABLE>
<CAPTION>
Revenues (1) Identifiable Assets
--------------------------------------------------- -------------------------------
Quarter Ended Six Months Ended
June 30, June 30, June 30, December 31,
1999 1998 1999 1998 1999 1998
--------- --------- ---------- --------- ----------- ---------------
<S> <C> <C> <C> <C> <C> <C>
United States................. $1,397 $1,348 $3,165 $2,983 $16,409 $16,395
Foreign Countries (2)......... 39 20 66 44 2,058 1,602
--------- --------- ---------- --------- ----------- ---------------
Total.................... $1,436 $1,368 $3,231 $3,027 $18,467 $17,997
========= ========= ========== ========= =========== ===============
</TABLE>
Identifiable investments in foreign countries include amounts from:
Argentina $306 $304
Brazil (3) 342 480
Chile and Peru 429 --
Netherlands 524 400
(1) Revenues are attributed to countries based on the locations of the
investments.
(2) Total assets are net of foreign currency translation adjustment of
$(189) million (pretax) as of June 30, 1999 and $(48) million
(pretax) as of December 31, 1998.
(3) Amount is net of foreign currency translation adjustment of $(184)
million (pretax) as of June 30, 1999 and $(43) million (pretax) as
of December 31, 1998.
<PAGE>
================================================================================
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
================================================================================
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
Note 9. Accounting Matters
In June 1999, the FASB issued SFAS 137, "Accounting for Derivative
Instruments and Hedging Activities--Deferral of the Effective Date of FASB
Statement No. 133" (SFAS 137) to defer the effective date of SFAS 133,
"Accounting for Derivative Instruments and Hedging Activities" (SFAS 133) for
one year. Consequently, SFAS 133 will now be effective for all fiscal quarters
of all fiscal years beginning after June 15, 2000. The FASB also decided to
defer by one year the transition date regarding embedded derivatives in SFAS
133.
SFAS 133, which was issued in June 1998, establishes accounting and
reporting standards for derivative instruments and hedging activities. It
requires an entity to recognize all derivatives, within the scope of this
statement, as assets or liabilities on the balance sheet at fair value. Also,
derivatives that are not hedges must be adjusted to fair value through income.
If a derivative is a hedge, changes in the fair value of the derivative will
either be offset against the change in fair value of the hedged asset, liability
or firm commitment through earnings or be recognized in other comprehensive
income until the hedged item is recognized in earnings, depending on the nature
of the hedge. The ineffective portion of a hedge will be immediately recognized
in earnings. PSEG and PSE&G are currently evaluating the impact of SFAS 133 and
developing an implementation plan.
Note 10. Comprehensive Income (Loss)
Comprehensive Income (Loss), Net of Tax:
<TABLE>
<CAPTION>
Quarter Ended Six Months Ended
June 30, June 30,
------------------------------ -----------------------
1999 1998 1999 1998
----------- ------------ --------- ----------
(Millions of Dollars)
<S> <C> <C> <C> <C>
Net income (loss)................................... $(609) $122 $(421) $313
Foreign currency translation, net of tax (A) ....... (2) (6) (127) (12)
----------- ------------ --------- ----------
Comprehensive income (loss)......................... $(611) $116 $(548) $301
=========== ============ ========= ==========
<FN>
(A) Net of tax of $(0.2) million and $(1) million for the quarters ended June
30, 1999 and 1998, respectively, and $(14) million and $(2) million for the
six months ended June 30, 1999 and 1998, respectively.
</FN>
</TABLE>
<PAGE>
================================================================================
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
================================================================================
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Notes to Consolidated Financial Statements of PSEG are incorporated by
reference insofar as they relate to PSE&G and its subsidiaries:
Note 1. Basis of Presentation/Summary of Significant Accounting Policies
Note 2. Regulatory Issues
Note 3. Extraordinary Charge and Other Accounting Impacts of Deregulation
Note 4. Regulatory Assets and Liabilities
Note 5. Commitments and Contingent Liabilities
Note 6. Financial Instruments and Risk Management
Note 8. Financial Information by Business Segments
Note 9. Accounting Matters
Note 7. Income Taxes
PSE&G's effective income tax rate is as follows:
<TABLE>
<CAPTION>
Quarter Ended Six Months Ended
June 30, June 30,
------------------------ -------------------------
1999 (A) 1998 1999 (A) 1998
----------- --------- ----------- ---------
<S> <C> <C> <C> <C>
Federal tax provision at statutory rate.................. 35.0% 35.0% 35.0% 35.0%
New Jersey Corporate Business Tax, net of Federal benefit 5.9% 5.9% 5.9% 5.9%
Other-- net.............................................. (0.1)% 1.7% 1.5% 1.8%
----------- --------- ----------- ---------
Effective Income Tax Rate............................ 40.8% 42.6% 42.4% 42.7%
=========== ========= =========== =========
<FN>
(A) Excludes the impact of the extraordinary charge recorded in the second
quarter of 1999. The effective income tax rate applicable to the
extraordinary charge was 30.4%. This rate is below the statutory rate of
40.85% primarily due to income taxes that were flowed through to
ratepayers in prior periods under regulated accounting methods partially
offset by the investment tax credit being credited to the benefit of
PSEG's stockholders pursuant to the Stipulation and the Summary Order.
</FN>
</TABLE>
Note 10. Comprehensive Income (Loss)
For the quarters and six months ended June 30, 1999 and 1998, PSE&G's
comprehensive income (loss) equaled the consolidated net income (loss) of PSE&G.
<PAGE>
================================================================================
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
================================================================================
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Following are the significant changes in or additions to information
reported in the Public Service Enterprise Group Incorporated (PSEG) 1998 Annual
Report on Form 10-K, the Quarterly Report on Form 10-Q for the quarter ended
March 31, 1999 and the Current Reports on Form 8-K filed March 18, 1999, April
26, 1999 and July 21, 1999 affecting the consolidated financial condition and
the results of operations of PSEG and its subsidiaries. This discussion refers
to the Consolidated Financial Statements (Statements) and related Notes to
Consolidated Financial Statements (Notes) of PSEG and should be read in
conjunction with such Statements and Notes.
Overview and Future Outlook
Following the passage of the New Jersey Electric Discount and Competition
Act (Energy Competition Act), the New Jersey Board of Public Utilities (BPU)
rendered its summary decision relating to Public Service Electric and Gas
Company's (PSE&G) rate unbundling, stranded costs and restructuring proceedings
(Summary Order) on April 21, 1999. It is expected that the BPU will issue a more
detailed Decision and Order (Final Order) in these matters during the third
quarter of 1999, which will provide a full discussion of the issues as well as
the reasoning for the BPU's determinations. The Energy Competition Act, the
BPU's Summary Order and Final Order and the related BPU proceedings are
hereinafter referred to as the Energy Master Plan Proceedings (Energy Master
Plan Proceedings). These proceedings provide that all New Jersey retail electric
customers may select their electric supplier commencing August 1, 1999 and all
New Jersey retail gas customers may select their gas supplier commencing
December 31, 1999, thus opening the New Jersey energy markets to competition.
After analysis of the Summary Order, PSE&G concluded that it no longer met
the requirements of Statement of Financial Accounting Standards (SFAS) 71,
"Accounting for the Effects of Certain Types of Regulation" (SFAS 71), for the
electric generation portion of its business. As a result, PSE&G recorded a net
extraordinary charge to earnings of $790 million, after tax, in the second
quarter. This one-time loss reflects the impairment of PSE&G's electric
generation-related assets and related fuel, equipment, materials and supplies as
well as recording certain liabilities stemming from the deregulation of PSE&G's
electric generation business. The impairment reflects the difference in the
level of stranded costs computed under SFAS 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS 121),
and the recovery of such stranded costs that was approved by the BPU. For
further discussion of the Energy Master Plan Proceedings and the related
extraordinary charge to earnings, see Note 2. Regulatory Issues and Note 3.
Extraordinary Charge and Other Accounting Impacts of Deregulation of Notes.
As set forth in the Summary Order, PSE&G will sell its electric
generation-related assets and all associated rights and liabilities to a
separate corporate entity to be owned by PSEG. The Summary Order specifies a
sale price of $2.443 billion plus the book value of PSE&G's other
generation-related assets, including materials, supplies and fuel. To effectuate
the sale, PSEG organized PSEG Power LLC (PSEG Power), a Delaware limited
liability company (LLC), as a wholly owned subsidiary in June 1999. PSEG Power
will purchase the electric generation-related assets from PSE&G and will manage
such assets through its subsidiaries, PSEG Fossil LLC (PSEG Fossil), PSEG
Nuclear LLC (PSEG Nuclear) and PSEG Energy Resources & Trade LLC (PSEG ER&T),
all of which are also Delaware LLCs. It is currently anticipated that the sale
of such assets will occur sometime in the fourth quarter of 1999. Prior to the
execution of such sale, PSEG Power must obtain final approval from the BPU, the
Federal Energy Regulatory Commission (FERC) (to be recognized as an exempt
wholesale generator (EWG) under the Public Utility Holding Company Act (PUHCA))
and the Nuclear Regulatory Commission (NRC) (to transfer PSE&G's licenses). PSEG
Power will also have to resolve a number of other issues related to taxes,
environmental restrictions and financing (see Liquidity and Capital Resources
and Note 2. Regulatory Issues of Notes). Pending receipt and review of the Final
Order, PSEG and PSE&G cannot determine the applicability and impact of other
regulatory and/or legal requirements.
<PAGE>
================================================================================
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
================================================================================
The Summary Order requires PSE&G to provide basic generation service (BGS)
for all customers who do not elect a different service provider. Pursuant to a
contractual relationship, PSEG Power will provide PSE&G with the energy and
capacity required to meet its BGS and off-tariff rate agreement (OTRA)
obligations under the Summary Order. PSEG Power, through its wholly owned
subsidiary PSEG ER&T, will provide such energy and capacity under the BGS
contract rate for the first three years of the transition period, beginning
August 1, 1999. BGS will be competitively bid for the fourth year and annually
thereafter. PSEG ER&T will obtain the energy and capacity to supply PSE&G's BGS
and OTRA requirements from its affiliates, PSEG Nuclear and PSEG Fossil,
supplemented as necessary with energy purchased in the competitive wholesale
electricity market. PSEG Power's earnings and its contribution to PSEG's
earnings will be exposed to the risks of the competitive wholesale electricity
market to the extent that PSEG Power has to purchase energy and/or capacity to
meet its BGS and OTRA obligations at market prices which approach or exceed the
BGS contract rate (see PJM and Item 3. Qualitative and Quantitative Disclosures
About Market Risk). PSEG ER&T's policy will be to use derivatives to manage this
risk consistent with its business plans and prudent practices. PSEG Power will
also participate in the competitive wholesale electricity market for other items
such as energy, capacity and ancillary services.
The Energy Master Plan Proceedings have dramatically reshaped the utility
industry in New Jersey and have directly affected how PSEG will conduct business
and its financial prospects in the future. PSEG is realigning its organizational
structure to address the competitive environment brought about by the
deregulation of the electric generation industry in New Jersey. PSEG has already
been engaged in the competitive energy business for a number of years through
certain of its unregulated subsidiaries and, in 1998, generated approximately
10% of its earnings from these subsidiaries. However, due to the regulatory
changes outlined above, competitive businesses will constitute a much larger
portion of PSEG's activities in 1999 and beyond. It is expected that by the end
of the transition period, PSEG's unregulated subsidiaries (comprised of PSEG
Energy Holdings Inc. (Energy Holdings) and PSEG Power) will contribute between
60% and 70% of PSEG's earnings. Additionally, PSEG will be more dependent on
cash flows generated from its unregulated operations to fund its financing
needs. As the unregulated portion of the business continues to grow, potential
financial risks and rewards will be greater, financial requirements will change
and the volatility of earnings and cash flows will increase.
Going forward, PSEG will continue to pursue its strategies to grow its
family of energy-related businesses. As previously reported, more emphasis will
be placed on finding opportunities for expansion outside of its traditional
utility services and markets. PSEG Power's business strategy is to size its
fleet of generation assets to take advantage of market opportunities, while
seeking to increase its value and manage commodity price risk through its
wholesale trading activity. PSE&G's transmission and distribution objective,
both gas and electric, is to provide cost-effective, high quality, reliable
service. PSEG Global Inc.'s (Global) strategy is to focus on generation and
distribution investments within targeted high-growth areas of the worldwide
energy market. PSEG Resources Inc.'s (Resources) strategy is to utilize its
market access, industry knowledge and transaction structuring capabilities to
expand its energy-related investment portfolio. PSEG Energy Technologies Inc.'s
(Energy Technologies) strategy is to assess prospects in its emerging regional
energy service business before committing additional capital. Energy
Technologies plans to grow existing operations and utilize the recently acquired
companies to deliver expanded energy-related services and products, including
gas and electricity, to existing and new customers. In addition to internal
growth, PSEG expects to pursue opportunities for expansion through business
combinations.
To the extent that the discussion that follows reports on business
conducted under full monopoly regulation of the utility business, it must be
understood that such business will change during the second half of 1999 and
beyond, and that past results are not an indication of future business prospects
or financial results.
<PAGE>
Results of Operations
<TABLE>
<CAPTION>
Net Income (Loss)
---------------------------------------------------------------
Quarter Ended Six Months Ended
June 30, June 30,
--------------------------- ----------------------------
1999 1998 1999 1998
------------ ----------- ------------ ------------
<S> <C> <C> <C> <C>
PSE&G, Before Extraordinary Item $155 $108 $324 $263
PSE&G Extraordinary Item (790) -- (790) --
------------ ----------- ------------ ------------
Total PSE&G (635) 108 (466) 263
Energy Holdings 26 14 45 50
------------ ----------- ------------ ------------
Total PSEG $(609) $122 $(421) $313
============ =========== ============ ============
</TABLE>
<TABLE>
<CAPTION>
Contribution to Earnings Per Share (Basic and Diluted)
---------------------------------------------------------------
Quarter Ended Six Months Ended
June 30, June 30,
--------------------------- ----------------------------
1999 1998 1999 1998
------------ ----------- ------------ ------------
<S> <C> <C> <C> <C>
PSE&G, Before Extraordinary Item $0.71 $0.47 $1.47 $1.14
PSE&G Extraordinary Item (3.60) -- (3.57) --
------------ ----------- ------------ ------------
Total PSE&G (2.89) 0.47 (2.10) 1.14
Energy Holdings 0.12 0.06 0.20 0.21
------------ ----------- ------------ ------------
Total PSEG $(2.77) $0.53 $(1.90) $1.35
============ =========== ============ ============
</TABLE>
Basic and diluted earnings per share of PSEG common stock (Common Stock)
were $(2.77) for the quarter ended June 30, 1999, representing a decrease of
$3.30 per share from the comparable 1998 period. Basic and diluted earnings per
share of Common Stock were $(1.90) for the six months ended June 30, 1999,
representing a decrease of $3.25 per share from the comparable 1998 period.
In the second quarter of 1999, PSE&G recorded an extraordinary charge to
earnings of $790 million, net of tax, as a result of the BPU's Summary Order in
the Energy Master Plan Proceedings. For further discussion, see Note 2.
Regulatory Issues and Note 3. Extraordinary Charge and Other Accounting Impacts
of Deregulation of Notes. Excluding that extraordinary charge, basic and diluted
earnings per share of Common Stock were $0.83 for the quarter ended June 30,
1999, representing an increase of $0.30 per share over the comparable 1998
period. Excluding that extraordinary charge, basic and diluted earnings per
share of Common Stock were $1.67 for the six months ended June 30, 1999,
representing an increase of $0.32 per share over the comparable 1998 period.
Excluding the extraordinary charge, PSE&G's contribution to earnings per
share of Common Stock for the quarter ended June 30, 1999 increased $0.24 from
the comparable 1998 period. The increase for the quarter ended June 30, 1999 was
partially due to lower generation-related depreciation expenses due to the lower
net book value of generation-related assets as a result of their write down
effective April 1, 1999, under SFAS 121. These lower depreciation expenses were
partially offset by a change in the capitalization policy for PSE&G's electric
generation business and by the effects of depreciation policy changes stemming
from the discontinuation of SFAS 71 (see Note 1. Basis of Organization/Summary
of Significant Accounting Policies). Additionally, electric revenues increased
due to higher sales resulting from favorable weather in the second quarter of
1999 augmented by positive economic factors in New Jersey and profits realized
from wholesale energy activities. The increase was partially offset by higher
operating expenses, including higher transmission, distribution and wholesale
energy costs than those incurred in the second quarter of 1998.
<PAGE>
Excluding the extraordinary charge, PSE&G's contribution to earnings per
share of Common Stock for the six months ended June 30, 1999 increased $0.33
from the comparable 1998 period. The increase for the six months ended June 30,
1999 was primarily due to increased sales of gas and electricity resulting from
favorable weather in the first and second quarters of 1999 augmented by positive
economic factors in New Jersey and profits realized from wholesale energy
activities. In addition, generation-related depreciation expenses were lower as
a result of the impairment write down, partially offset by a change in the
capitalization policy for PSE&G's electric generation business and by the
effects of depreciation policy changes stemming from the discontinuation of SFAS
71. The increase in earnings was partially offset by higher operating expenses,
including higher transmission, distribution and wholesale energy costs, than
those incurred in the six months ended June 30, 1998.
PSEG Energy Holdings Inc.'s (Energy Holdings) contribution to earnings per
share of Common Stock for the quarter ended June 30, 1999 increased $0.06 from
the comparable 1998 period, primarily due to the better overall performance of
Resources, Global and Energy Technologies.
Energy Holdings' contribution to earnings per share of Common Stock for the
six months ended June 30, 1999 decreased $0.01 from the comparable 1998 period,
primarily due to lower unrealized gains in Resources' financial investment
portfolio in the first quarter of 1999. In the six months ended June 30, 1998,
Resources recognized significant gains from its beneficial interest in a
leveraged buy-out (LBO) fund. The lower comparative contribution from Resources
was partially offset by increased contributions from Global and Energy
Technologies.
As a result of PSEG's stock repurchase program which began in September
1998, earnings per share of Common Stock for the quarter and six months ended
June 30, 1999 increased $0.04 and $0.07, respectively, from the comparable 1998
periods. As of June 30, 1999, approximately 13 million shares had been
repurchased at a cost of approximately $507 million under this program.
PSE&G -- Revenues
Certain of the below listed year to year variances did not impact earnings
as there was an offsetting variance in expense. To the extent fuel revenue and
expense flowed through the Electric Levelized Energy Adjustment Clause (LEAC)
and the Levelized Gas Adjustment Clause (LGAC) mechanisms, variances in fuel
revenues and expenses offset and thus had no direct effect on earnings. These
include base fuel revenues, demand side management (DSM) revenue and Remediation
Adjustment Charge (RAC) revenue. On August 1, 1999, the LEAC mechanism was
eliminated as a result of the Energy Master Plan Proceedings. This is likely to
increase earnings volatility since PSEG will bear the full risks and rewards of
changes in nuclear and fossil generating fuel costs and replacement power costs.
See Note 2. Regulatory Issues and Note 4. Regulatory Assets and Liabilities of
Notes for a discussion of LEAC, LGAC, RAC and DSM and their status under the
Energy Master Plan Proceedings.
Electric
Revenues increased $40 million or 4% and $104 million or 6% for the quarter
and six months ended June 30, 1999 from the comparable periods in 1998,
respectively, primarily due to profits realized from wholesale energy activities
and DSM revenues being higher in the quarter and six months ended June 30, 1999
than in the comparable 1998 periods. Additionally, favorable weather in the
first and second quarters of 1999 augmented by positive economic factors in New
Jersey contributed to the increases.
On July 26, 1999, the BPU approved PSE&G's compliance tariff filing
reflecting the 5% decrease in rates on a provisional basis (see Note 2.
Regulatory Issues of Notes). On August 1, 1999, PSE&G implemented this rate
reduction as required by the BPU under the Energy Master Plan Proceedings. In
1999, this rate reduction is expected to decrease revenues by approximately $80
million. A further revenue reduction could occur in 1999 depending upon the
timing of the receipt of securitization proceeds (see Note 2. Regulatory Issues
of Notes). Additionally, the probable loss of customers through the opening of
competition could reduce future revenues.
Gas
Revenues increased $5 million or 2% and $93 million or 11% for the quarter
and six months ended June 30, 1999 from the comparable periods in 1998,
respectively. The increases were primarily due to increased revenues from gas
service contracts and DSM revenues being higher in the quarter and six months
ended June 30, 1999 than in the comparable 1998 periods. Additionally, favorable
weather in the first and second quarters of 1999 contributed to the increases.
Additionally, the probable loss of customers through the opening of competition
could reduce future revenues.
PSE&G -- Expenses
Net Interchanged Power and Fuel for Electric Generation
Net Interchanged Power and Fuel for Electric Generation decreased $5
million or 2% for the quarter ended June 30, 1999 and had no change for the six
months ended June 30, 1999 from the comparable 1998 periods, respectively.
Due to the elimination of the LEAC on August 1, 1999, these historical
trends are not to be considered an indication of future Net Interchanged Power
and Fuel for Electric Generation costs. Given the elimination of the LEAC, the
lifting of the requirements that electric energy offered for sale in PJM not
exceed the variable cost of producing such energy and that such transactions are
now capped at $1,000 per MWH (see Competitive Environment), the absence of a PJM
price cap in situations involving emergency purchases and the potential for
plant outages; price movements could have a material impact on PSEG's and
PSE&G's financial condition, results of operations or net cash flows. For a
discussion of market risks, see Item 3. Qualitative and Quantitative Disclosures
About Market Risk. Additionally, it is expected that the probable loss of
customers through the opening of competition could reduce future expenses.
Gas Purchased
Gas Purchased decreased $4 million or 2% for the quarter ended June 30,
1999 from the comparable 1998 period. Gas purchased for the six months ended
June 30, 1999 increased $29 million or 5% primarily due to increased sales of
gas resulting from colder weather in the first quarter of 1999. Additionally, it
is expected that the probable loss of customers through the opening of
competition could reduce future expenses.
Operation and Maintenance
Operation and Maintenance expense increased $21 million or 6% and $92
million or 14% for the quarter and six months ended June 30, 1999 from the
comparable 1998 periods, respectively. The increase was primarily due to higher
costs related to wholesale power activities and higher transmission and
distribution costs, including higher material and outside services in 1999 and
increased PJM restructuring expenses. Additionally, higher Other Post Retirement
Benefits (OPEB) costs were incurred in the quarter and six months ended June 30,
1999 than in the comparable 1998 periods. Also, in the quarter and six months
ended June 30, 1999, there was higher DSM recovery of previously deferred
expenses.
With an increasingly competitive energy market as an outcome of the Energy
Master Plan Proceedings and energy industry restructuring, the composition and
level of Operation and Maintenance expense is likely to change. Additionally,
the change in capitalization policy will likely yield a material increase in the
Operation and Maintenance expenses associated with the electric generation
business (see Note 1. Basis of Presentation/Summary of Significant Accounting
Policies). This increase in Operation and Maintenance expense is not expected to
exceed $75 million after tax per year and will be offset by lower depreciation
expense in the future.
<PAGE>
Depreciation and Amortization
Depreciation and Amortization expense decreased $46 million or 28% and $33
million or 10% for the quarter and six months ended June 30, 1999 from the
comparable 1998 periods, respectively. The decreases were due to lower net book
value balances of PSE&G's generation-related assets which were reduced as of
April 1, 1999 as a result of the impairment calculated pursuant to SFAS 121.
This decrease was partially offset by higher depreciation expense related to
transmission and distribution assets having higher net book values in the
quarter and six months ended June 30, 1999 than in the comparable 1998 periods.
Also, higher depreciation rates for generation-related assets were used in the
second quarter of 1999 due to the change in depreciation policy for
generation-related assets (see Note 1. Basis of Presentation/Summary of
Significant Accounting Policies).
Despite the higher depreciation rates for generation-related assets, the
decrease in generation-related depreciation expense will be ongoing due to the
reduced asset balances. Such reductions are currently anticipated to approximate
$230 million per year, pretax. Additionally, beginning in 2000, electric
distribution asset-related depreciation will be further reduced due to the
amortization of the excess electric distribution depreciation reserve over the
period from January 1, 2000 to July 31, 2003. See Note 4. Regulatory Assets and
Liabilities of Notes for a discussion of the amortization schedule.
Income Taxes
Income Taxes increased $27 million or 34% and $45 million or 23% for the
quarter and six months ended June 30, 1999 from the comparable 1998 periods,
respectively. This increase is primarily due to higher pretax operating income.
Energy Holdings -- Earnings/(Losses)
<TABLE>
<CAPTION>
Quarter Ended Six Months Ended
June 30, June 30,
--------------------------- ---------------------------
1999 1998 1999 1998
----------- ----------- ----------- -----------
(Millions of Dollars)
<S> <C> <C> <C> <C>
Earnings Before Interest and Taxes:
Resources $48 $40 $92 $107
Global 22 16 40 35
Energy Technologies (2) (5) (5) (8)
=========== =========== =========== ===========
Earnings:
Energy Holdings $26 $14 $45 $50
=========== =========== =========== ===========
</TABLE>
Energy Holdings' earnings for the quarter ended June 30, 1999 and 1998 were
$26 million and $14 million, respectively. The increase in Energy Holdings'
earnings was primarily due to higher investment gains and higher leveraged lease
income from Resources augmented by higher revenue from Global's operating
projects and Energy Technologies' recent acquisition activity partially offset
by higher operating expenses.
Energy Holdings' earnings for the six months ended June 30, 1999 and 1998
were $45 million and $50 million, respectively. Lower earnings for the six
months ended June 30, 1999 were primarily due to lower investment gains in
Resources' financial investment portfolio. In the six months ended June 30,
1998, Resources recognized significant gains from its beneficial interest in an
LBO. The lower comparative contribution from Resources was partially offset by
increased contributions from Global and Energy Technologies. Improved revenue at
Global was partially offset by higher expenses associated with project
development. Energy Technologies' losses narrowed due to higher revenues from
recent acquisition activities partially offset by higher operating expenses.
Energy Holdings-Revenues
Revenues increased $29 million to $139 million from $110 million for the
quarter ended June 30, 1999 as compared to the same period in 1998. The increase
was due to a $5 million increase in revenues at Global primarily due to
improvement in revenues from the Latin American electric distribution companies
as well as the addition of revenues from investments made in June 1999 in two
energy distribution companies in Chile and Peru, a $15 million increase in
revenues at Energy Technologies due to the addition of revenues from recent
acquisitions and an increase of $8 million at Resources due to higher investment
income from its limited partnership investments.
Revenues increased $13 million to $268 million from $255 million for the
six months ended June 30, 1999 as compared to the same period in 1998. The
increase was due to a $6 million increase in revenues at Global primarily due to
improvement in revenues from the Latin American electric distribution companies
as well as the addition of revenues from two energy distribution companies
acquired in June 1999 and a $22 million increase in revenues at Energy
Technologies due to the addition of revenues from acquisitions in 1999,
partially offset by a decrease of $16 million at Resources due to lower
investment income from its limited partnership investments.
Global is a 50% partner in six generating facilities in California.
Beginning in 2000, revenue from these facilities will be reduced due to lower
energy prices to be paid by the purchaser under the energy contracts associated
with the plants. Energy prices under such contracts will be reduced from the
current fixed rates to short-run avoided cost (SRAC) energy prices approved by
the California Public Utilities Commission (CPUC). The CPUC is considering the
issue of transitioning SRAC energy payments under contracts of this type to the
clearing price of the California Power Exchange (PX). Although the CPUC has not
yet initiated a proceeding, Global anticipates that eventually energy prices
under these contracts will be based upon the PX clearing price. Two-thirds of
the primary California facilities in which Global has an interest will change
from fixed energy pricing by December 31, 2000, with the remainder changing in
2001. Both the SRAC and the PX energy prices are currently substantially lower
than the fixed energy prices charged in these contracts. Based on current SRAC
and PX energy prices, Global's share of annual income before income taxes from
these facilities is projected to decrease by approximately $30 million to $35
million when all such contracts reflect SRAC or PX energy pricing. Actual
revenues over the remaining contract terms, which begin to expire in 2011, will
depend on a number of factors, including the actual SRAC or PX prices in effect
in the applicable future periods. Global's projects in construction and
development are expected to offset this revenue shortfall; however, no
assurances can be given.
PSEG--Preferred Securities Dividend Requirements of Subsidiaries
Preferred Securities Dividend Requirements increased $9 million or 47% and
$17 million or 49% for the quarter and six months ended June 30, 1999 as
compared to the same periods in 1998. The increase was due to the issuance of
trust preferred securities by three special purpose statutory business trusts
controlled by PSEG, Enterprise Capital Trust I, II and III, in January, June and
July 1998 of $525 million.
Liquidity and Capital Resources
PSEG and PSE&G
PSEG is an exempt public utility holding company and, as such, has no
operations of its own. The following discussion of PSEG's liquidity and capital
resources is on a consolidated basis, noting the uses and contributions of
PSEG's two direct operating subsidiaries, PSE&G and Energy Holdings.
PSEG and PSE&G believe that the deregulation of the utility industry will
impact the sources and uses of cash in 1999 and beyond. Also, as a result of
deregulation and related corporate structure reorganizations, the capital
structure of PSEG and PSE&G will likely change. As of June 30, 1999, PSEG's
capital structure consisted of 39.9% common equity, 48.1% long-term debt and
12.0% preferred stock and other preferred securities. As of June 30, 1999,
PSE&G's capital structure consisted of 47.5% common equity, 43.7% long-term debt
and 8.8% preferred stock and other preferred securities. The BPU, in its Summary
Order, required that the use of the net proceeds of securitization shall be done
in a manner that will not substantially alter PSE&G's overall capital structure.
It is anticipated that PSE&G will receive securitization proceeds of $2.4
billion (net of transaction costs of up to $125 million). Additionally, PSE&G
will receive proceeds of $2.443 billion (plus the net book value of other
generation-related assets and liabilities transferred at the time of purchase,
currently estimated to be between $200 million and $400 million) for the sale of
PSE&G's generation-related assets to PSEG Power.
In anticipation of receipt of the Final Order confirming the terms of the
Summary Order, PSEG has organized a new wholly owned subsidiary, PSEG Power.
Subject to the timely receipt of certain required Federal and State regulatory
approvals, the receipt of which cannot be assured, and receipt of the net
proceeds from its stranded asset securitization, PSE&G anticipates completing
the sale of its generation-related assets during the fourth quarter of 1999. See
Note 2. Regulatory Issues of Notes for a discussion of the status of PSE&G's
filings seeking regulatory approvals to date.
In June 1999, also in anticipation of receipt of the BPU's Final Order and
in accordance with New Jersey's Electric Discount and Energy Competition Act
(Energy Competition Act), PSE&G petitioned the BPU for an irrevocable Bondable
Stranded Costs Rate Order (Finance Order) to authorize, among other things, the
imposition of a non-bypassable transition bond charge on its customers; the sale
of PSE&G's property right in such charge created by the Energy Competition Act
to a bankruptcy-remote financing entity (SPE); the issuance and sale of $2.525
billion of transition bonds by such entity in payment therefor and the
application by PSE&G of the transition bond proceeds to retire outstanding debt
and/or equity. Subject to the receipt of the required State and Federal
approvals, the receipt of which cannot be assured, and market conditions then
prevailing, PSE&G anticipates that such securitization could occur in Fall 1999.
Both the right of PSE&G to receive the bondable transition charge pursuant
to the securitization transaction and the proceeds from the sale of its
generation-related assets to PSEG Power are property subject to the lien of
PSE&G's First and Refunding Mortgage (Mortgage). All such property will be
released from the lien of the Mortgage at the time of sale. In accordance with
the provisions of the Mortgage, the net proceeds from the sale of such released
property will be deposited with the Trustee.
As previously reported, the Mortgage authorizes PSE&G to exercise one or
more of the following options as to the application of proceeds of such released
property, at its sole discretion:
1. Withdraw funds for corporate use by utilizing additions and
improvements. (Option 1)
2. Direct the Trustee to invest the proceeds in U.S. Government
Securities. (Option 2)
3. Direct the Trustee to purchase its Mortgage Bonds at the lowest prices
obtainable, at or below par value. If the Trustee is unable to
purchase sufficient Mortgage Bonds to exhaust such proceeds deposited
with it, the balance may be applied on a pro rata basis towards the
redemption of eligible series of Mortgage Bonds outstanding at par.
(Option 3)
At June 30, 1999, PSE&G had a total of $4.130 billion of Mortgage Bonds
outstanding, of which $3.335 billion are taxable registered Mortgage Bonds
subject to special redemption provisions, outlined in Option 3 (Redeemable
Bonds). $780 million are tax-exempt Pollution Control Bonds and $15 million are
two series of taxable coupon Mortgage Bonds due 2037 (Coupon Bonds). Both the
Pollution Control Bonds and the Coupon Bonds are not subject to Option 3.
PSE&G has not yet made a final decision as to the amount and the manner in
which it will retire or redeem its Mortgage Bonds. Such a decision will be made
on or about the time the proceeds from securitization and the sale of the
generation-related assets to PSEG Power are deposited with the Trustee, on the
basis of market conditions and other factors existing at that time. However,
based on current information, a likely utilization of the options available to
PSE&G, as noted above, could be as follows:
1. Withdraw $2.4 billion of net proceeds from securitization under Option
1, above. These proceeds would be used to:
(a) Tender for all Coupon Bonds;
(b) Redeem $126.5 million of Pollution Control Bonds now redeemable;
(c) Make open market purchases and/or tender for approximately $500
million to $800 million of Redeemable Bonds; and
(d) Reduce PSE&G common and/or preferred equity with the balance of
proceeds.
2. Apply proceeds ($2.4 billion to $2.8 billion) from the
generation-related asset sale to PSEG Power under Option 3 against any
remaining taxable Mortgage Bonds outstanding.
As previously reported, in anticipation of securitization, PSEG's Board of
Directors authorized the repurchase of up to an aggregate of 20 million shares
of Common Stock in the open market. The repurchased shares have been held as
treasury stock. At June 30, 1999, PSEG had repurchased approximately 13 million
shares of Common Stock at a cost of approximately $507 million, under these
authorizations. No additional shares have been repurchased since May 20, 1999.
Market conditions and the availability of alternative investments will dictate
if and when more shares of Common Stock will be repurchased under this
authorization. Additionally, PSE&G may also make open market purchases of its
outstanding preferred stock and Mortgage Bonds pending receipt of securitization
and generation sale proceeds.
Going forward, cash generated from PSE&G's regulated business is expected
to provide the majority of the funds for PSE&G's regulated business needs. PSEG
Power's capital needs will be dictated by its strategy to size its generation
fleet, and will likely require cash generated from operations and external
financings. Energy Holdings' growth will be funded through external financings,
equity infusions from PSEG and cash generated from operations.
Dividend payments on Common Stock were $0.54 per share and totaled
approximately $238 million and $251 million for the six months ended June 30,
1999 and 1998, respectively. Amounts and dates of such dividends on Common Stock
as may be declared in the future will necessarily be dependent upon PSEG's
future earnings, cash flows, financial requirements, the receipt of dividend
payments from its subsidiaries and other factors. Since 1986, PSE&G has made
regular cash payments to PSEG in the form of dividends on outstanding shares of
PSE&G's common stock. PSEG has not increased its dividend rates in seven years
in order to retain additional capital for reinvestment and to reduce its payout
ratio.
PSE&G paid common stock dividends of $392 million and $251 million to PSEG
during the six months ended June 30, 1999 and 1998, respectively. These amounts
were used to fund PSEG's Common Stock dividends, and in 1999, to support a
portion of PSEG's stock repurchase program. Based on its analysis of the Summary
Order, PSEG believes that its dividend payments can be maintained at their
current level (see Note 2. Regulatory Issues of Notes). In the future, PSEG
expects to fund its dividend payments through cash generated by the operations
of PSE&G and PSEG Power. Note that due to the competitive environment in which
PSEG Power will operate and due to reduced revenues at PSE&G resulting from
mandated rate reductions, such dividend payments will be at a greater risk. Due
to the growth in Energy Holdings investment activities, no dividends on Energy
Holdings' common stock were paid in the six months ended June 30, 1999 and 1998.
PSEG and PSE&G have each issued Deferrable Interest Subordinated Debentures
in connection with the issuance of their respective tax deductible preferred
securities. If, and for as long as, payments on those Deferrable Interest
Subordinated Debentures have been deferred, or PSEG or PSE&G has defaulted on
the applicable indenture related thereto or its guarantee thereof, neither PSEG
nor PSE&G may pay any dividends on its common or preferred stock.
As a result of the 1992 focused audit of PSEG's non-utility businesses
(Focused Audit), the BPU approved a plan which, among other things, provides
that: (1) PSEG will not permit Energy Holdings' non-utility investments to
exceed 20% of PSEG's consolidated assets without prior notice to the BPU (such
investments at June 30, 1999 were approximately 20% of PSEG's consolidated
assets); (2) the PSE&G Board of Directors will provide an annual certification
that the business and financing plans of Energy Holdings will not adversely
affect PSE&G; (3) PSEG will (a) limit debt supported by the minimum net worth
maintenance agreement between PSEG and PSEG Capital Corporation (PSEG Capital)
to $650 million and (b) make a good-faith effort to eliminate such support over
a six to ten year period from April 1993; and (4) Energy Holdings will pay PSE&G
an affiliation fee of up to $2 million a year to be applied by PSE&G through its
LGAC and its LEAC to reduce utility rates. PSEG and Energy Holdings and its
subsidiaries continue to reimburse PSE&G for the costs of all services provided
to them by employees of PSE&G.
Capital resources and capital requirements will be affected by the outcome
of the Energy Master Plan Proceedings and the requirements of the Focused Audit.
As a result of the final outcome and the accounting impacts resulting from the
deregulation of the generation of electricity and the unbundling of the utility
business, PSEG and PSE&G do not believe that the Focused Audit provision
requiring notification of the BPU if PSEG's non-utility investments exceed 20%
of its consolidated assets remains appropriate and believe that modifications
will be required. However, regulatory oversight by the BPU to ensure that there
is no harm to utility ratepayers from PSEG's non-utility investments is expected
to continue. PSEG and PSE&G believe that these issues will be satisfactorily
resolved, although no assurances can be given. Inability to achieve satisfactory
resolution of these matters could impact the future relative size and financing
activities of Energy Holdings and PSEG Power and accordingly, their future
prospects. Consequently, this could have a material adverse impact on PSEG's and
PSE&G's financial condition, results of operations or net cash flows. For
discussion of the Energy Master Plan Proceedings, see Note 2. Regulatory Issues
of Notes.
Energy Holdings
As noted above, it is intended that Global and Resources provide earnings
and cash flow for long-term growth for Energy Holdings and PSEG. Resources'
investments are designed to produce immediate earnings and cash flow that enable
Global and Energy Technologies to focus on longer investment horizons.
Energy Holdings plans to continue the growth of Global and Resources
through further investments made by these subsidiaries. Energy Technologies is
not expected to be a significant consumer of capital. Investing activity in 1999
will be subject to periodic review and revision and may vary depending on the
opportunities presented. During the next five years, Energy Holdings' will
likely require significant capital to fund its planned growth. Factors affecting
actual expenditures and investments include availability of suitable investment
opportunities, market volatility and local economic trends. The anticipated
sources of funds for such growth opportunities are additional equity from PSEG,
cash flow from operations and external financings. A significant portion of
Global's growth is expected to occur internationally due to the current and
anticipated growth in electric capacity required in certain regions of the
world. Resources will continue its focus on investments related to energy
infrastructure. Energy Technologies is expected to expand upon the
energy-related services currently being provided to industrial and commercial
customers.
In June 1999, PSEG contributed approximately $200 million of additional
equity to Energy Holdings, which was applied by Energy Holdings to pay down
short-term debt that was used to acquire its interest in distribution companies
in Chile and Peru.
For a discussion of the source of Energy Holdings' funds, see External
Financings. Over the next several years, Energy Holdings and its subsidiaries
will be required to refinance their maturing debt and provide additional debt
and equity financing for growth. Any inability to obtain required additional
external capital or to extend or replace maturing debt and/or existing
agreements at current levels and reasonable interest rates may affect PSEG's and
Energy Holdings' financial condition, results of operations or net cash flows.
As of June 30, 1999 and 1998, Energy Holdings' embedded cost of debt of its
finance subsidiaries was approximately 6.6% and 7.9%, respectively.
Capital Requirements
PSEG's and PSE&G's capital resources and capital requirements are affected
by the Energy Master Plan Proceedings. For a discussion of the impact of the
Energy Master Plan Proceedings on PSEG's and PSE&G's future prospects, including
financial condition, results of operations or net cash flows, see Note 2.
Regulatory Issues of Notes.
PSEG
PSEG has entered into contracts to purchase combustion turbines. PSEG's
commitment under these contracts is approximately $392 million to be expended
through December 2001. Through July 31, 1999, payments of approximately $56
million were made under these contracts.
PSE&G
For the six months ended June 30, 1999, PSE&G had plant additions,
including capitalized interest and Allowance for Funds Used During Construction
(AFDC), of $175 million, a $22 million decrease from the corresponding 1998
period. This decrease is primarily due to PSE&G's capitalization policy change
for the electric generation portion of its business. See Note 1. Basis of
Presentation/Summary of Significant Accounting Policies of Notes for further
discussion regarding the capitalization policy change.
PSE&G's regulated business expects to be able to internally generate the
majority of its construction and capital requirements over the next five years,
assuming adequate and timely recovery of costs, as to which no assurances can be
given, with the balance to be provided by issuance of debt to replace
maturities. The unregulated generation portion of PSE&G's current operations
(i.e., PSEG Power) may incur capital requirements based on its growth strategy.
For discussion of the Energy Master Plan Proceedings and their impacts, see Note
2. Regulatory Issues and Note 5. Commitments and Contingent Liabilities of
Notes.
Energy Holdings
Global
In August 1999, Global and its partners expect to close project financing
for a 487 MW gas-fired combined-cycle electric generating facility in Rades,
Tunisia. Construction is expected to begin in August 1999 and to be completed in
the Summer of 2001 at a total cost of approximately $261 million. Upon
completion, the facility is expected to qualify as a foreign utility company
(FUCO). Global's equity investment for its 35% interest is expected to be
approximately $27 million.
In July 1999, Global entered into an agreement for the sale of its 50%
partnership interest in a 137 MW gas-fired combined-cycle co-generation facility
in Newark, New Jersey. Global expects to close this transaction in the third
quarter of 1999 and recognize an after-tax gain of approximately $40 million.
In June 1999, Global and a partner acquired 90% of a Chilean distribution
company, which also owns 37% of a distribution company in Peru, together
providing electric and gas service to approximately one million customers in
Chile and Peru. Global paid approximately $268 million including fees and
closing costs. The acquisition was also financed with project debt that is
non-recourse to Global, Energy Holdings and PSEG, totaling $160 million, which
is consolidated on Global's balance sheet.
Also in June 1999, Global and a partner closed the project financing for an
845 MW gas-fired combined-cycle electric generating facility to be constructed
in San Nicolas, Argentina. The new facility will be adjacent to an existing 650
MW facility also owned by Global and its partner. Global expects construction to
begin in August 1999 and to be completed by 2001 at a total cost of
approximately $448 million. Global's equity investment, including contingencies,
is expected to be approximately $86 million.
In May 1999, Global acquired a 63% equity interest in a company which is
developing a 525 MW coal-fired electric generating facility to be constructed in
North Chennai, India. Upon scheduled completion in 2003, Global will be the
operator of the plant. The total project cost is expected to be approximately
$633 million, of which Global's maximum equity investment, including
contingencies, is expected to be approximately $180 million. Financial closure
is expected in the Fall of 1999.
In April 1999, Global and a partner entered into a joint venture agreement
to develop, construct and operate a 1,000 MW gas-fired combined-cycle electric
generating facility in Guadalupe County in south central Texas. The facility is
expected to be operational in 2001 and is expected to qualify as an EWG.
Global's maximum equity investment is expected to be approximately $193 million
including loans and guarantees.
Also in April 1999, Global and a partner announced the formation of a joint
venture to construct and operate three gas-fired electric generating facilities
with total installed capacity of 200 MW and associated distribution systems to
serve, under contract, industrial customers in Venezuela. Global expects two of
these facilities, which are in construction, to be operational in late 1999 with
the third facility expected to be operational in early 2001. The total cost of
these facilities is expected to be approximately $140 million and Global's
equity investment is expected to be approximately $70 million.
Resources
In June 1999, Resources sold its ownership interest in an electric
generating facility in California that was subject to a leveraged lease and
recognized an after-tax gain of $9 million. Resources received proceeds of $58
million on July 1, 1999 related to this sale.
In 1999, Resources has invested approximately $137 million in three
leveraged lease transactions of energy-related assets: two gas distribution
networks in the Netherlands and a liquefied natural gas plant in the United
States.
In 1999, Resources, through its investment in a leveraged buyout fund, has
received cash of $59 million resulting in an after-tax gain of $12 million from
the fund's sale of a portion of its equity interests. In the third quarter of
1999, Resources expects to receive additional distributions totaling
approximately $40 million from announced liquidations in the fund.
<PAGE>
Energy Technologies
During 1999, Energy Technologies acquired five mechanical and building
service contractors in New Jersey and Rhode Island for a total cost of
approximately $43 million including debt assumed. The latest acquisition was
completed in July 1999.
External Financings
The changes in the utility industry are attracting increased attention of
bond rating agencies which regularly assess business and financial matters
including how utility companies are meeting competition and competitive
initiatives, especially as they affect potential stranded costs. Bond ratings
affect the cost of capital and the ability to obtain external financing. Given
the changes in the industry and the anticipated use of securitization, attention
and scrutiny of PSEG's and PSE&G's competitive strategies by rating agencies
will likely continue. These changes could affect the bond ratings, cost of
capital and market prices of the respective securities of both PSEG and PSE&G.
PSEG and PSE&G are analyzing their future capital and financing needs in
light of securitization, the sale of generation-related assets to PSEG Power and
their business strategies. However, it is expected that following completion of
securitization and the generation-related asset sale, PSE&G will refinance a
portion of its debt and equity, which will not substantially alter its existing
capitalization ratios and PSEG Power and Energy Holdings will likely issue debt
through the capital markets to fund their acquisitions and projects.
PSEG
At June 30, 1999, PSEG had a committed $150 million revolving credit
facility which expires in December 2002. At June 30, 1999, PSEG had $18 million
outstanding under this revolving credit facility. At June 30, 1999, PSEG had a
$25 million uncommitted line of credit with a bank with no debt outstanding
under this line of credit.
In June 1999, PSEG issued $300 million of Extendible Notes, Series C, due
June 15, 2001 with interest at the three-month LIBOR plus 0.40%, reset
quarterly. These Notes will be automatically tendered to the remarketing agent
for remarketing on March 15, 2000. PSEG used the net proceeds to make an equity
investment in Energy Holdings and to reimburse its treasury for expenditures
made to repurchase shares of its Common Stock.
PSE&G
PSE&G filed a petition with the BPU to effectuate the securitization
transaction. In addition, PSE&G will need to file petitions with the BPU for
authorization for any additional debt financing needed. PSE&G is currently
evaluating the potential uses of the proceeds of securitization (see Liquidity
and Capital Resources).
Under its Mortgage, PSE&G may issue new First and Refunding Mortgage Bonds
against previous additions and improvements and/or retired Mortgage Bonds
provided that its ratio of earnings to fixed charges calculated in accordance
with its Mortgage is at least 2:1. As of June 30, 1999, the Mortgage would
permit up to $3.8 billion aggregate principal amount of new Mortgage Bonds to be
issued against previous additions and improvements, the level of which could be
impacted by the actions ultimately taken in connection with securitization and
the sale of generation-related assets to PSEG Power. At June 30, 1999, PSE&G's
Mortgage coverage ratio was 4.282:1. PSE&G expects to apply for and receive
necessary BPU authorization for external financings to meet its requirements
over the next five years, as needed. For a related discussion, see Liquidity and
Capital Resources and Generation-Related Asset Sale to PSEG Power of Note 2.
Regulatory Issues of Notes.
In May 1999, PSE&G purchased in the open market $18.5 million principal
amount of its 6 3/4% Series VV Mortgage Bonds due January 1, 2016. The remaining
principal amount of the 6 3/4% Series VV Bonds is $181.5 million.
To provide liquidity for its commercial paper program, PSE&G has an $850
million revolving credit agreement expiring in June 2000 and a $650 million
revolving credit agreement expiring in June 2002 with a group of commercial
banks, which provide for borrowings of up to one year. On June 30, 1999, there
were no borrowings outstanding under these credit agreements.
The BPU has authorized PSE&G to issue and have outstanding at any one time
through January 4, 2000, not more than $1.5 billion of short-term obligations,
consisting of commercial paper and other unsecured borrowings from banks and
other lenders. On June 30, 1999, PSE&G had $876 million of short-term debt
outstanding, including $65 million borrowed against its uncommitted bank lines
of credit which lines of credit totaled $100 million at that date.
PSE&G Fuel Corporation (Fuelco) has a $125 million commercial paper program
to finance a 42.49% share of Peach Bottom Atomic Power Station (Peach Bottom)
nuclear fuel, supported by a $125 million revolving credit facility with a group
of banks, which expires on June 28, 2001. PSE&G has guaranteed repayment of
Fuelco's respective obligations under this program. As of June 30, 1999, Fuelco
had commercial paper of $64 million outstanding.
Energy Holdings
The availability and cost of external capital could be affected by the
performance of Energy Holdings and PSE&G and by the actions taken by the BPU
with regard to the Energy Master Plan Proceedings as well as by rating agencies'
views of such matters including the degree of structural or regulatory
separation between the utility and its non-utility affiliates and the potential
impact of affiliate ratings on the consolidated credit quality of PSEG and
PSE&G.
The minimum net worth maintenance agreement between PSEG Capital and PSEG
provides, among other things, that PSEG (1) maintain its ownership, directly or
indirectly, of all outstanding common stock of PSEG Capital, (2) cause PSEG
Capital to have at all times a positive tangible net worth of at least $100,000
and (3) make sufficient contributions of liquid assets to PSEG Capital in order
to permit it to pay its debt obligations. In 1993, PSEG agreed with the BPU to
make a good-faith effort to eliminate such PSEG support within six to ten years.
Effective January 31, 1995, PSEG Capital notified the BPU of its intention not
to have more than $650 million of debt outstanding at any time. PSEG Capital has
a $650 million Medium Term Note (MTN) program which provides for the
private-placement of MTNs without registration.
PSEG Capital's assets consist principally of demand notes of Global and
Resources. Intercompany borrowing rates are established based upon PSEG
Capital's cost of funds. In February and June 1999, PSEG Capital issued $252
million of 6.25% MTNs due May 2003 and $35 million of 6.73% MTNs due June 2001,
respectively. The proceeds were used to repay $100 million of PSEG Capital MTNs
which matured in February 1999 and $35 million which matured in May 1999 and to
reduce Energy Holdings' short-term debt. At June 30, 1999, PSEG Capital had
total debt outstanding of $650 million, all of which was comprised of MTNs with
maturities between 1999 and 2003. Energy Holdings believes it is capable of
eliminating PSEG support of PSEG Capital debt within the time period set forth
in the Focused Audit.
In May 1999, Energy Holdings closed on two separate senior revolving credit
facilities, with a syndicate of banks, a $165 million, 364 day revolving credit
facility and a $495 million, five year revolving credit and letter of credit
facility. These facilities replaced existing facilities at Enterprise Capital
Funding Corporation (Funding), a financing subsidiary of Energy Holdings,
totaling $450 million. Effective May 1999, Funding is no longer being used as a
financing vehicle for Energy Holdings.
Financial covenants contained in this new facility include the ratio of
cash flow available for debt service (CFADS) to fixed charges. At the end of any
quarterly financial period such ratio shall not be less than 1.50x. As a
condition of borrowing, the pro-forma CFADS to fixed charges ratio shall not be
less than 1.75x as of the quarterly financial period ending immediately
following the first anniversary of each borrowing or letter of credit issuance.
CFADS includes, but is not limited to, operating cash before interest and taxes,
pretax cash distributions from all asset liquidations and equity capital from
PSEG to the extent not used to fund investing activity. In addition, the ratio
of consolidated recourse indebtedness to recourse capitalization, at the end of
any quarterly financial period, shall not be greater than 0.60 to 1.00. This
ratio is calculated by dividing the total recourse indebtedness of Energy
Holdings by the total recourse capitalization. This ratio excludes the debt of
PSEG Capital supported by PSEG. As of June 30, 1999, the latest 12 months CFADS
was 11.5x and the ratio of recourse indebtedness to recourse capitalization was
0.20 to 1.00.
Compliance with applicable financial covenants will depend upon future
financial position and levels of earnings and cash flow, as to which no
assurances can be given. In addition, Energy Holdings' ability to continue to
grow its business will depend to a significant degree on PSEG's ability to
access capital and Energy Holdings' ability to obtain additional financing
beyond current levels. At June 30, 1999, Energy Holdings had $330 million
outstanding under existing credit facilities totaling $660 million.
In June 1999, project financing, which is non-recourse to Global, Energy
Holdings and PSEG, for Global's equity investment in two Argentine distribution
companies was refinanced. Approximately $67 million of an $87 million loan was
refinanced for a total of one year maturing in June 2000. The original loan was
paid down with $11 million of operating cash flow from the Argentine
distribution companies and approximately $9 million from Global. An interest
rate swap was entered into which effectively converts a portion of the floating
rate obligation into fixed rate obligations. The interest rate differential to
be received or paid under the agreement is recorded over the life of the
agreement as an adjustment to interest expense.
In July 1999, an Argentine distribution company, in which Global has a 33%
interest, refinanced a portion of project debt that is non-recourse to Global,
Energy Holdings and PSEG. The arrangement required Global to make an additional
equity investment of approximately $25 million to repay a portion of the
original loan. The new loan is floating rate for a term of three years.
Foreign Operations
In accordance with their growth strategies, Global and Resources have made
approximately $1.2 billion and $0.8 billion, respectively, of international
investments. As of June 30, 1999, these investments represented 11% of PSEG's
consolidated assets and contributed 8% of consolidated revenues for the six
months ended June 30, 1999. Resources' international investments are primarily
leveraged leases of assets located in Australia, the Netherlands and the United
Kingdom with associated revenues denominated in U.S.dollars and, therefore, not
subject to foreign currency risk.
Global's international investments are primarily in projects that generate
or distribute electricity in Argentina, Brazil, Chile, China and Peru. Investing
in foreign countries involves certain risks. Economic conditions that result in
higher comparative rates of inflation in foreign countries likely result in
declining values in such countries' currencies. As currencies fluctuate
vis-a-vis the U.S. dollar, there is a corresponding change in Global's
investment value in terms of the U.S. dollar. Such change is reflected as an
increase or decrease in comprehensive income, a separate component of
stockholders' equity. Net foreign currency devaluations, $166 million of which
was caused by the Brazilian Real, have reduced the reported amount of PSEG's
total stockholders' equity by $170 million as of June 30, 1999. For further
discussion of foreign currency risk and the devaluation of the Brazilian Real,
see Note 6.Financial Instruments and Risk Management of Notes.
Competitive Environment
Generation
PSE&G will be required to provide basic generation service (BGS) for all
customers who do not elect a different service provider. PSEG Power will provide
PSE&G with the energy and capacity required to meet its BGS and OTRA obligations
under the Summary Order. PSEG Power, through its wholly owned subsidiary PSEG
ER&T, will provide such energy and capacity under the BGS contract rate for the
first three years of the transition period, beginning August 1, 1999. BGS will
be competitively bid for the fourth year and annually thereafter. PSEG ER&T will
obtain the energy and capacity to supply PSE&G's BGS and OTRA requirements from
its affiliates, PSEG Nuclear and PSEG Fossil, supplemented as necessary with
energy purchased in the competitive wholesale electricity market. PSEG Power's
earnings will be exposed to the risks of the competitive wholesale electricity
market to the extent that PSEG Power has to purchase energy and/or capacity to
meet its BGS and OTRA obligations at market prices which approach or exceed the
BGS contract rate (see PJM and Item 3. Qualitative and Quantitative Disclosures
About Market Risk). PSEG ER&T's policy will be to use derivatives to manage this
risk consistent with its business plans and prudent practices. PSEG Power will
also participate in the competitive wholesale electricity market for other items
such as energy, capacity and ancillary services. For further discussion of the
sale of generation-related assets, see Note 2. Regulatory Issues of Notes.
State Regulatory Matters
For discussions of the Energy Master Plan Proceedings, Gas Unbundling, the
LEAC and other rate matters, see Note 2. Regulatory Issues of Notes.
PJM Interconnection, LLC (PJM)
PSE&G is a member of PJM and participates on the PJM Members Committee as
part of its governance structure. PSE&G is also a member of the Mid-Atlantic
Area Reliability Council which provides for review and evaluation of plans for
generation and transmission facilities and other matters relevant to the
reliability of the bulk electric supply systems in the Mid-Atlantic area.
On July 6, 1999, both PSE&G and PJM broke all-time demand records. PSE&G
customer demand reached more than 9,800 MW, surpassing PSE&G's prior energy
demand record set on July 17, 1997 of 9,548 MW. PJM also set an all-time high of
51,550 MW.
As of April 1, 1999, FERC lifted the requirement that bids for electric
energy offered for sale in the PJM interchange energy market from utility-owned
generation located within the PJM control area not exceed the variable cost of
producing such energy. FERC found that no single market participant can unduly
influence market prices. Additionally, a market monitoring function is provided
by the PJM Independent System Operator (ISO). Transactions that are bid into the
PJM pool are now capped at $1,000 per megawatt hour. The current PJM market
structure, which includes this price cap on offers into the spot market and an
installed capacity obligation, is being studied by a PJM user group and may be
modified in the future.
All power providers are paid the locational marginal price (LMP) set
through power providers' bids. Furthermore, in the event that all available
generation within the PJM control area is insufficient to satisfy demand, PJM
may institute emergency purchases from adjoining regions. The cost of such
emergency purchases is not subject to any PJM price cap. Since the LEAC was
discontinued as of August 1, 1999, to the extent PSEG's generation business
produces less energy than required to supply PSE&G's BGS customers and
off-tariff rate agreement customers, the lifting of such caps could present
additional risks with respect to the difference between the LMP and the BGS
rate. For further discussion of price volatility of electricity, see Item 3.
Qualitative and Quantitative Disclosures About Market Risk.
On May 12, 1999, FERC issued a Notice of Proposed Rulemaking regarding
Regional Transmission Organizations (RTO). Although PJM is consistent with the
proposed requirements for a RTO, the proposed rulemaking, which PSE&G believes
is in conflict with the Federal Power Act, may restrict PSE&G's ability to
recover its transmission related revenue requirements. Also, under some RTO
structures, ownership of transmission assets would be limited to a de minimus
level. Both of these possible restrictions could have a material adverse impact
on PSEG's and PSE&G's financial condition, results of operations or net cash
flows. PSE&G expects to actively participate in this rulemaking proceeding to
advocate positions favorable to PSE&G, although no assurances on the outcome of
these proceedings can be given.
On April 13, 1999, FERC approved PJM's market enhancements which provide
the ability to auction residual and released Fixed Transmission Rights (FTRs).
An FTR is a financial instrument which under certain circumstances hedges the
holder against transmission congestion charges. The PJM ISO administers this
system. The FTR auction market has not had a material impact on PSEG's and
PSE&G's financial condition, results of operations or net cash flows.
Year 2000 Readiness Disclosure
Many of PSEG's and PSE&G's systems, which include information technology
applications, plant control and telecommunications infrastructure systems, must
be modified due to computer program limitations in recognizing dates beyond
1999. PSEG and PSE&G have had a formal project in place since 1997 to address
Year 2000 issues. Based upon project progress to date, all mission critical
systems are expected to be ready before January 1, 2000. Future progress is
dependent on a wide number of variables, including the continued availability of
trained resources and vendors meeting commitments to PSEG and PSE&G.
Year 2000 Readiness Status
PSEG and PSE&G have established a three-phase program to achieve Year 2000
readiness. The initial phase (Inventory) identified systems having potential
Year 2000 issues and set priorities for assessing and remediating those systems.
The second phase (Assessment) determined whether systems are digital/date
sensitive and the extent of date related issues. The third phase
(Remediation/Testing) repairs programming code, upgrades or replaces systems and
validates that code repairs were implemented as intended. Year 2000 readiness
work is considered finished upon completion of all three phases.
PSEG and PSE&G have completed required Year 2000 readiness work for more
than 99% of their critical systems as of June 30, 1999, except for certain
systems at PSE&G's nuclear facilities. The majority of these system upgrades are
scheduled beyond July 1999 in order to coincide with planned refueling outages
at these facilities. Certain systems at the Hope Creek Generating Station (Hope
Creek) and the Salem Generating Station Unit 2 (Salem 2) were remediated during
their respective first quarter 1999 and second quarter 1999 refueling outages.
The remaining nuclear systems will be remediated before or during Salem Unit 1's
(Salem 1) planned refueling outage in the third quarter 1999 with completion
expected by the end of November 1999. By the end of 1999, a majority of PSEG's
and PSE&G's non-critical systems are also expected to be Year 2000 ready with
the remainder of such non-critical systems to be ready in 2000.
<PAGE>
Energy Holdings and its subsidiaries have essentially completed Inventory
on all systems impacted by Year 2000 readiness issues and substantial Assessment
work has been completed on such systems. Remediation/Testing is expected to be
completed in 1999 on all critical systems and a majority of non-critical systems
and in 2000 on remaining non-critical systems. Energy Holdings (parent company),
Energy Technologies and Resources have completed required Year 2000 readiness
work for 100% of their critical systems and such systems are Year 2000 ready as
of June 30, 1999. Global has completed required Year 2000 readiness work for 90%
of its critical systems through June 1999.
As previously reported, on May 11, 1998, the NRC issued a Generic Letter to
all nuclear facilities requiring submission of a written response within 90 days
of that date which addressed the status of their Year 2000 programs. This
response was required to address the facility's project scope, assessment
process, plans for corrective actions, quality assurance measures, contingency
plans and regulatory compliance. Additionally, the Generic Letter required
submission of a written response upon completion of the facility's Year 2000
programs or no later than July 1, 1999 confirming their Year 2000 readiness
status and defining when their facilities would be Year 2000 ready. On July 23,
1998, PSE&G provided its written response to the first requirement noted above,
outlining for the NRC its nuclear facility Year 2000 program. In this response,
PSE&G indicated that planned implementation will allow PSE&G's nuclear
facilities to be Year 2000 ready and in compliance with the terms and conditions
of their licenses and NRC regulation by January 1, 2000. Additionally, during
the week of October 26, 1998, the NRC conducted an audit of the nuclear
operations' Hope Creek Year 2000 Project. The audit report states that the
nuclear operations' Year 2000 project plan is comprehensive and is receiving the
appropriate management support and oversight.
On June 30, 1999, PSE&G provided its written response to the second
requirement of the NRC Generic Letter, noted above. In this response, PSE&G
reaffirmed its plan to have all mission critical systems ready and in compliance
with the terms and conditions of their license and NRC regulation by January 1,
2000. PSE&G has identified no Year 2000 problem that could affect the proper
functioning of any nuclear safety system. All safety-related systems that could
have a Year 2000 issue have already been identified and, where necessary,
corrected and tested. PSE&G advised the NRC that Salem and Hope Creek will be
fully Year 2000 ready once scheduled work on eleven non-safety mission critical
systems is completed by November 1999. PSE&G will continue to monitor the Year
2000 issue to ensure that it is prepared for any issues, internal or external to
the plants, which could impact PSE&G. Additionally, PSE&G has developed
contingency plans to address issues that may arise during the December 31, 1999
through January 1, 2000 rollover. Additionally, PECO informed PSE&G that it
provided the required July 1999 response to the NRC confirming that Peach
Bottom's Year 2000 effort is on schedule to also be Year 2000 ready and in
compliance with the terms and conditions of their license and NRC regulation by
January 1, 2000.
PSEG, PSE&G and their subsidiaries are continuing to work with their
supplier base to assess the Year 2000 readiness status of vendors who provide
critical materials and services (key vendors). PSEG and PSE&G have indications
from more than 95% of their key vendors that they are making or have made
preparations for the Year 2000. To date, all key vendors responding indicate
that their business operations will be ready. Global's vendors are not included
in that statistic; however, Global's key vendors have also indicated that they
expect to be able to meet Year 2000 requirements. Strategies are being put into
place to minimize the impact of potential vendor failures on PSEG's and PSE&G's
operations. However, failure of key vendors to be Year 2000 ready could result
in material adverse impacts to PSEG's and PSE&G's operations, financial
condition, results of operations or net cash flows.
Year 2000 Costs
For a discussion of Year 2000 Costs, see Note 5. Commitments and Contingent
Liabilities of Notes.
<PAGE>
Year 2000 Risks
PSEG and PSE&G have identified some scenarios and will continue working to
determine the most reasonably likely, worst case scenarios arising from Year
2000 readiness issues. PSEG and PSE&G see "most reasonably likely" and "worst
case" scenarios as two ends of a continuum of possible events:
o Most reasonably likely scenarios include operating conditions similar
to those experienced routinely for electric and gas utilities during
that time of year. Service disruptions can, and most likely will,
occur during critical periods because of automobile accidents, animal
intervention in transformers, etc. Because of increased media
attention, some of these incidents may be misinterpreted as being Year
2000 related.
o At the other end of the continuum, PSEG and PSE&G are planning for
both low demand and increased volatility in demand because of customer
actions. It is possible that many customers will revert to their own
back-up generation during critical Year 2000 periods (primarily around
December 31, 1999 through January 1, 2000). Their individual decisions
could aggregate to unpredictable demand patterns. PSEG and PSE&G are
preparing for this scenario by having their most "agile" generating
units (typically peaking units) in a high state of readiness.
Energy Holdings has identified some scenarios and will continue to
determine the most reasonably likely, worst case scenarios arising from Year
2000 readiness issues. Global's most reasonably likely, worst case scenarios may
include potential external disturbances of its systems including, but not
limited to, fuel supply or transmission interruptions or telecommunications
systems outages. Global's contingency plans are being developed to address these
scenarios.
Further analysis will depend, in part, on the results of information
currently being obtained from key vendors as to their Year 2000 readiness and
the readiness of PJM and trading partners, among others.
PSEG and PSE&G have no outstanding litigation relating to Year 2000 issues.
The likelihood of future Year 2000 related liabilities cannot be determined at
this time. PSEG and PSE&G have been subject to the following Year 2000
regulatory action:
o The BPU has issued a specific order requiring a number of customer
related disclosures, including bill inserts, establishment of an "800"
number, and others.
o The BPU has issued an interim report assessing Year 2000 program
progress by PSE&G up to June 15, 1999. The report indicated that the
BPU agreed with the overall status of the project, and that based on
reported progress, the Year 2000 program should come to a successful
termination.
o On a general level, the BPU has required PSEG and PSE&G to participate
in periodic status meetings with other utilities.
Additionally, Energy Holdings is subject to international Year 2000
regulatory initiatives which include:
o The Argentine Secretariat of Energy has enacted a resolution
establishing certain guidelines and due dates in relation to Year 2000
compliance. Lack of compliance with the guidelines may cause sanctions
to be imposed.
o The Brazil Ministry of Justice has issued a ruling requiring all
Brazilian companies to indemnify consumers for damages resulting from
Year 2000 non-compliance.
Contingency Plans
PSEG and PSE&G have adopted the North American Electric Reliability
Council's (NERC) timetable, guidelines and detailed requirements for developing
these contingency plans. The planning process is an iterative one. PSEG and
PSE&G have completed their preliminary contingency plans. The second version of
their contingency plans was completed by June 30, 1999, consistent with NERC's
timetable. PSEG and PSE&G conducted a limited scope internal drill on March 19,
1999. The scope of the drill involved using alternate communication capabilities
(i.e., radio) to monitor electric generation and transmission should the public
switched phone network become unavailable. The drill showed the basic
feasibility of preliminary plans and it identified needed procedural
enhancements.
On April 9, 1999, PSEG and PSE&G participated in a NERC
industry-coordinated Year 2000 readiness drill. It involved a scope similar to
the March 19, 1999 drill plus the involvement of PJM. The drill had similar
results in that it showed the basic feasibility of using the radio system and it
identified some needed procedural enhancements. Going forward, PSEG and PSE&G
will build on the results of these exercises to participate in the NERC-led
drill on September 9, 1999, may conduct other drills and may use other
communications capabilities such as satellite-based telephones. Further plan
updates will be evaluated, as needed, from September 1999 through January 2000.
PSEG and PSE&G expect that with completion of the Year 2000 readiness work
and implementation of programs from SAP America, Inc. (SAP), the possibility of
significant interruptions of normal operations should be reduced. However, if
PSEG, PSE&G, their domestic and international subsidiaries, their project
affiliates, the other members of PJM, PJM trading partners supplying power
through PJM, PSEG's or PSE&G's critical vendors and/or customers or the capital
markets are unable to meet the Year 2000 deadline, such inability could have a
material adverse impact on PSEG's and PSE&G's operations, financial condition,
results of operations or net cash flows.
Environmental Costs
For discussion of potential environmental and other remediation costs, see
Note 5. Commitments and Contingent Liabilities of Notes.
Accounting Issues
For a discussion of significant accounting matters including SFAS 71; SFAS
121; Emerging Issues Task Force (EITF) Issue No. 97-4, "Deregulation of the
Pricing of Electricity-Issues Related to the Application of FASB Statements No.
71 and No. 101" (EITF 97-4); SFAS 101, "Regulated Enterprises-Accounting for the
Discontinuation of Application of FASB Statement No. 71" (SFAS 101); changes in
capitalization, depreciation and asset retirement policies; discontinuation of
deferred accounting for fuel revenues and expenses; EITF 98-10, "Accounting for
Energy Trading and Risk Management Activities" (EITF 98-10); Statement of
Position (SOP) 98-1, "Accounting for the Costs of Computer Software Developed or
Obtained for Internal Use" (SOP 98-1) and SOP 98-5, "Reporting on the Costs of
Start-Up Activities" (SOP 98-5), see Note 1. Basis of Presentation/Summary of
Significant Accounting Policies of Notes.
Impact of New Accounting Pronouncements
For a discussion of the impact of new accounting pronouncements including
SFAS 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS
133) and SFAS 137, "Accounting for Derivative Instruments and Hedging Activities
- - Deferral of the Effective Date of FASB Statement No. 133" (SFAS 137), see Note
9. Accounting Matters of Notes.
<PAGE>
PSE&G
The information required by this item is incorporated herein by reference
to the following portions of PSEG's Management's Discussion and Analysis of
Financial Condition and Results of Operations, insofar as they relate to PSE&G
and its subsidiaries: Overview and Future Outlook; Results of Operations;
Liquidity and Capital Resources; External Financings; Foreign Operations;
Competitive Environment; Year 2000 Readiness Disclosure; Environmental Costs;
Accounting Issues and Impact of New Accounting Pronouncements.
ITEM 3. QUALITATIVE AND QUANTITATIVE
DISCLOSURES ABOUT MARKET RISK
The market risk inherent in PSEG's market risk sensitive instruments and
positions is the potential loss arising from adverse changes in commodity
prices, equity security prices, interest rates and foreign currency exchange
rates as discussed below. PSEG's policy is to use derivatives to manage risk
consistent with its business plans and prudent practices. PSEG has a Risk
Management Committee made up of executive officers and an independent risk
oversight function to ensure compliance with corporate policies and prudent risk
management practices.
PSEG is exposed to credit losses in the event of non-performance or
non-payment by counterparties. PSEG also has a credit management process which
is used to assess, monitor and mitigate counterparty exposure for PSE&G and
Energy Holdings. In the event of non-performance or non-payment by a major
counterparty, there may be a material adverse impact on PSEG's and PSE&G's
financial condition, results of operations or net cash flows.
Commodity Instruments--PSE&G
The availability and price of energy commodities are subject to
fluctuations from factors such as weather, environmental policies, changes in
supply and demand, state and Federal regulatory policies and other events. To
reduce price risk caused by market fluctuations, PSE&G enters into derivative
contracts, including forwards, futures, swaps and options with approved
counterparties, to hedge its anticipated demand. These contracts, in conjunction
with owned electric generating capacity and physical gas supply contracts, are
designed to cover estimated electric and gas customer commitments.
Prior to August 1, 1999, PSE&G had levelized energy adjustment clauses in
its rate structure in place for both electricity (LEAC) and natural gas (LGAC).
These clauses were established to minimize the impact of major commodity price
swings on customer prices. They also reduced the risk to PSE&G by permitting
PSE&G to defer price increases and decreases until regulatory treatment could be
determined. In accordance with the BPU's Summary Order, effective August 1,
1999, the LEAC was discontinued and the full costs of electricity will be
recorded as an expense. For further discussion, see Note 2. Regulatory Issues
and Note 4. Regulatory Assets and Liabilities of Notes and Net Interchanged
Power and Fuel for Electric Generation of Item 2. Management's Discussion and
Analysis of Financial Condition and Results of Operations (MD&A). For discussion
of changes in the pricing of electric energy offered for sale in the PJM
interchange energy market, see PJM Interconnection, LLC (PJM) of MD&A.
PSE&G uses a value-at-risk model to assess the market risk of its commodity
business. This model includes fixed price sales commitments, owned generation,
native load requirements, physical contracts and financial derivative
instruments. Value-at-risk represents the potential gains or losses for
instruments or portfolios due to changes in market factors, for a specified time
period and confidence level. PSE&G estimates value-at-risk across its commodity
business using a model with historical volatilities and correlations.
During June 6 and 7, 1999, the Northeast was faced with a record setting
heat wave which drove the PJM spot prices up as high as $850 per MWH. During the
July 4, 1999 weekend, records were again set when PSE&G's customer demand
reached more than 9,800 MW due to another heat wave. Prices during July 5 and 6,
1999 hit highs of $920 per MWH. Note that in the future, the full cost of
electricity will be recorded as an expense due to the discontinuation of the
LEAC, as previously discussed.
The measured value-at-risk using a variance/co-variance model with a 95%
confidence level and assuming a one week horizon at June 30, 1999 was
approximately $11 million, compared to the December 31, 1998 level of $4
million. This increase is mainly due to the increase in price volatility
illustrated above. PSE&G's calculated value-at-risk exposure represents an
estimate of potential net losses that could be recognized on its portfolio of
physical and financial derivative instruments assuming historical movements in
future market rates. These estimates, however, are not necessarily indicative of
actual results which may occur, since actual future gains and losses will differ
from those historical estimates based upon actual fluctuations in market rates,
operating exposures, and the timing thereof, and changes in PSE&G's portfolio of
hedging instruments during the year.
Commodity Instruments--Energy Holdings
For discussion of Energy Holdings' commodity instruments, see Note 6.
Financial Instruments and Risk Management of Notes.
Equity Securities--Energy Holdings
For discussion of equity securities of Energy Holdings, see Note 6.
Financial Instruments and Risk Management of Notes.
Foreign Currencies--Energy Holdings
For discussion of foreign currency risks, see Note 6. Financial Instruments
and Risk Management of Notes.
Interest Rates--PSE&G
For discussion of interest rates of PSE&G, see Note 6. Financial
Instruments and Risk Management of Notes.
Interest Rates--Energy Holdings
For discussion of interest rates of Energy Holdings, see Note 6. Financial
Instruments and Risk Management of Notes.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Certain information reported under Item 3 of Part I of Public Service
Enterprise Group Incorporated's (PSEG) and Public Service Electric and Gas
Company's (PSE&G) 1998 Annual Report on Form 10-K, the Quarterly Report on Form
10-Q for the Quarter ended March 31, 1999 and the Current Reports on Form 8-K
filed March 18, 1999, April 26, 1999 and July 21, 1999 is updated below.
<PAGE>
(1) Form 10-K, Page 29. As previously disclosed, by complaints filed in 1995
and 1996, shareholder derivative actions on behalf of PSEG shareholders
were commenced by purported shareholders against certain directors and
officers. The four complaints generally sought recovery of damages for
alleged losses purportedly arising out of PSE&G's operation of the Salem
and Hope Creek generating stations, together with certain other relief,
including removal of certain executive officers of PSE&G and PSEG and
certain changes in the composition of PSEG's Board of Directors. By letter
dated July 9, 1999, the Court advised the parties in the actions of its
determination to grant the defendants' motion for summary judgement
dismissing all four derivative actions. A written order has not yet been
issued. Public Service Enterprise Group Inc. by G. E. Stricklin,
derivatively v. E. James Ferland, et. al., Superior Court of New Jersey,
Chancery Division, Essex County, Docket No. C-160-96. Dr. Steven Fink and
Dr. David Friedman, P.C. Profit Sharing Plan, derivatively, et. al. v.
Lawrence R. Codey, et. al., Superior Court of New Jersey, Chancery
Division, Essex County, Docket No. C-65-96. A. Harold Datz Pension and
Profit Sharing Plan derivatively, et. al., v. Lawrence R. Codey, et. al.,
Superior Court of New Jersey, Chancery Division, Essex County, Docket No.
C-68-96. Tillie Greenberg, derivatively v. E. James Ferland, et. al.,
Superior Court of New Jersey, Chancery Division, Essex County, Docket No.
C-188-96.
(2) March 31, 1999 Form 10-Q, Page 38. As previously disclosed, a complaint was
received by PSEG naming as defendants the current directors of PSEG, and
naming PSEG as a nominal defendant, from the same purported shareholder of
PSEG who instituted the December 1995 shareholder derivative suit and who
instituted the June 1998 proxy litigation, alleging that the 1999 proxy
statement provided to shareholders of PSEG was false and misleading by
reason, among other things, of failure to disclose certain material facts
relating to (i) the controls over and oversight of PSEG's nuclear
operations, (ii) the condition of problems at and reserves with respect to
PSEG's nuclear operations and (iii) the demand letter and derivative
litigation described above. The complaint seeks to have the 1999 proxy
statement declared to be in violation of law, to set aside the election of
directors of PSEG and the ratification of the selection of Deloitte &
Touche LLP as PSEG's auditors at the 1999 annual shareholder meeting, and
to require PSEG to conduct a special meeting of shareholders providing for
election of directors following timely dissemination of a proxy statement
approved by the Court hearing the matter, which should include as nominees
for election as directors persons having no previous relationship with PSEG
or the current directors, and other relief. PSEG cannot predict the outcome
of this matter. A motion to dismiss the complaint was filed by the
defendants on June 28, 1999. On August 2, 1999, the Court issued an order
granting the defendants' motion to dismiss the complaint. G. E. Stricklin
v. I. Lerner, et. al., United States District Court for the Eastern
District of Pennsylvania. Civil Action No. 99-1950.
In addition, see the following at the pages hereof indicated:
(1) Pages 10 through 16, 30 through 31 and 37. Proceedings before the BPU
in the matter of the Energy Master Plan Phase II Proceeding to
investigate the future structure of the Electric Power Industry,
Docket Nos. EX94120585Y, EO97070461, EO97070462 and EO97070463.
(2) Page 14. Proceedings before the BPU in the Matter of the Filings of
the Comprehensive Resource Analysis of Energy Programs pursuant to
Section 12 of the Electric Discount and Energy Competition Act of
1999, Docket Nos. EX99050347, EO99050348, EO99050349, EO99050350,
EO99050351, EO99050352, EO99050353 and EO99050354.
(3) Page 14. Proceeding before the BPU approving Interim Licensing and
Registration Standards, Docket No. EX99030182.
(4) Page 15. Proceeding before the BPU Establishing Procedures for gas
unbundling, Docket Nos. GX99030121, GO99030122, GO99030123, GO99030124
and GO99030125.
(5) Page 21. Investigation by the U.S. Environmental Protection Agency
(EPA) regarding the Passaic River site.
(6) Page 21. Additional investigation by the U.S. Environmental Protection
Agency (EPA) regarding the Passaic River site.
ITEM 5. OTHER INFORMATION
Certain information reported under PSEG's and PSE&G's 1998 Annual Report
and March 31, 1999 Quarterly Report to the SEC is updated below. References are
to the related pages of the Form 10-K and the Quarterly Report for the quarter
ended March 31, 1999 as printed and distributed.
Impact of Drought Emergency
New Matter. Continuing dry weather in the northeastern United States has
caused a state of water emergency to be declared in New Jersey on August 5,
1999. The operation of the condenser cooling water systems for PSE&G's
generating stations should not be adversely affected due to the drought
emergency. Only units located in the Delaware River Basin (Mercer, Burlington,
Hope Creek and Salem) are on a fresh water body where public drinking water
supplies could be potentially impacted by an upriver movement of the salt line.
The Merrill Creek Reservoir was built by seven electric utility companies in the
Delaware River Basin, including PSE&G, so that power reduction would not be
necessary during drought warnings or drought emergency conditions. The Merrill
Creek Reservoir releases water during low flow conditions to offset consumptive
water use from the operation of the cooling systems of those units and, as a
result, these units do not have to reduce power levels or shut down.
However, all other water uses at PSE&G's generating stations (including
Delaware River Basin units), distribution facilities and other PSEG and PSE&G
locations do come under the jurisdiction of the Delaware River Basin Commission
(DRBC) and NJDEP and are subject to mandatory curtailments and reductions during
a drought emergency. PSEG and PSE&G are taking appropriate actions to reduce
water consumption and to mitigate the potential impacts which could arise from
the drought emergency condition. PSEG and PSE&G cannot predict what actions the
DRBC or NJDEP may take if the drought conditions worsen; however, such actions
could have a material adverse effect on PSEG's and PSE&G's financial condition,
results of operations or net cash flows.
Credit Ratings
Form 10-K, page 6. Energy Holdings' revolving credit facility which was
entered into in May 1999 has been rated as follows:
Standard & Poor's BBB- Outlook: Stable
Moody's Ba1
Toxic Release Inventory
Form 10-K, page 20. The United States Environmental Protection Agency (EPA)
has revised its Toxic Release Inventory (TRI) program to expand it to include
electric generating facilities. By July 1, 1999, electric generating facilities
were required to report their toxic release numbers for 1998 to the EPA. PSE&G
filed its first report under this program on June 2, 1999 reporting PSE&G's 1998
emissions of acid gases and heavy metals. Because this is solely a disclosure
requirement, PSEG and PSE&G do not expect a material impact on their financial
condition, results of operations or net cash flows; however, PSEG and PSE&G are
pursuing options to reduce toxic releases.
<PAGE>
Air Pollution Control
Form 10-K, page 20 and March 31, 1999 Form 10-Q, Page 40. For discussion of
NOx allowances, see Note 5. Commitments and Contingent Liabilities of Notes.
Generation Properties
Form 10-K, page 27. Conectiv, parent of Atlantic City Electric Company
(ACE) and Delmarva Power & Light Company (DP&L), has announced that it will sell
its generating assets. Those assets include Conectiv's 5% share in Hope Creek
Generating Station (Hope Creek), its 15% share in the Salem Generating Stations
(Salem) and its 15% share in the Peach Bottom Atomic Power Station (Peach
Bottom). Conectiv also plans to sell its ownership shares in the coal-fired
Conemaugh and Keystone plants in western Pennsylvania.
PSE&G owns approximately 23% of those stations.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) A listing of exhibits being filed with this document is as follows:
PSEG
------------------------------------------------------------------------------
Exhibit Number Document
---------------- ------------------------------------------------------------
12 Computation of Ratios of Earnings to Fixed Charges (PSEG)
27(A) Financial Data Schedule (PSEG)
4 Form of Notes for PSEG Series C Extendible Notes
PSE&G
------------------------------------------------------------------------------
Exhibit Number Document
---------------- ------------------------------------------------------------
12(A) Computation of Ratios of Earnings to Fixed Charges (PSE&G)
12(B) Computation of Ratios of Earnings to Fixed Charges plus
Preferred Stock Dividend Requirements (PSE&G)
27(B) Financial Data Schedule (PSE&G)
(B) Reports on Form 8-K:
Registrant Date of Report Items Reported
----------------- --------------------------- -----------------------
PSEG and PSE&G April 26, 1999 Item 5
PSEG and PSE&G July 21, 1999 Items 5 and 7
<PAGE>
FORWARD LOOKING STATEMENTS
Except for the historical information contained herein, certain of the
matters discussed in this report are forward-looking statements which are
subject to risks and uncertainties which could cause actual results to differ
materially from those anticipated. Such statements are based on management's
beliefs as well as assumptions made by and information currently available to
management. When used herein, the words "will", "anticipate", "intend",
"estimate", "believe", "expect", "plan", "hypothetical", "potential", variations
of such words and similar expressions are intended to identify forward-looking
statements. For those statements, PSEG and PSE&G claim the protection of the
safe harbor for forward-looking statements contained in the Private Securities
Litigation Reform Act of 1995.
In addition to any assumptions and other factors referred to specifically
in connection with such forward-looking statements, factors that could cause
actual results to differ materially from those contemplated in any
forward-looking statements include, among others, the following: deregulation
and the unbundling of energy supplies and services and the establishment of a
competitive energy marketplace for products and services; managing rapidly
changing wholesale energy trading operations in conjunction with electricity and
gas production, transmission and distribution systems; managing foreign
investments and electric generation and distribution operations in locations
outside of the traditional utility service territory; political and foreign
currency risks; an increasingly competitive energy marketplace; sales retention
and growth potential in a mature PSE&G service territory; ability to complete
development or acquisition of current and future investments; partner and
counterparty risk; exposure to market price fluctuations and volatility of fuel
and power supply, power output, marketable securities, among others; ability to
obtain adequate and timely rate relief, cost recovery, and other necessary
regulatory approvals; ability to obtain securitization proceeds; Federal, state
and foreign regulatory actions; regulatory oversight with respect to utility and
non-utility affiliate relations and activities; Year 2000 issues; operating
restrictions, increased cost and construction delays attributable to
environmental regulations; nuclear decommissioning and the availability of
reprocessing and storage facilities for spent nuclear fuel; licensing and
regulatory approval necessary for nuclear and other operating stations; the
ability to economically and safely operate nuclear facilities in accordance with
regulatory requirements; environmental concerns; and market risk and debt and
equity market concerns associated with these issues.
PSEG and PSE&G undertake no obligation to publicly update or revise any
forward-looking statements, whether as a result of new information, future
events or otherwise. The foregoing review of factors should not be construed as
exhaustive or as any admission regarding the adequacy of disclosures made by
PSEG and PSE&G prior to the effective date of the Private Securities Litigation
Reform Act of 1995.
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrants have duly caused these reports to be signed on their respective
behalf by the undersigned thereunto duly authorized.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
---------------------------------------
(Registrants)
By: PATRICIA A. RADO
---------------------------------------
Patricia A. Rado
Vice President and Controller
(Principal Accounting Officer)
Date: August 16, 1999
REGISTERED REGISTERED
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
EXTENDIBLE NOTE DUE JUNE 15, 2001, SERIES C
NO. __ PRINCIPAL AMOUNT:
$----------
CUSIP: 744 573 AE 6
Unless and until it is exchanged in whole or in
part for Notes in definitive form, this Note may not be
transferred except as a whole by the Depositary to a nominee
of the Depositary or by a nominee of the Depositary to the
Depositary or another nominee of the Depositary or by the
Depositary or any such nominee to a successor Depositary or
a nominee of such successor Depositary. Unless this
certificate is presented by an authorized representative of
The Depository Trust Company (55 Water Street, New York, New
York) ("DTC"), to the issuer or its agent for registration
of transfer, exchange or payment, and any certificate issued
is registered in the name of Cede & Co. or such other name
as requested by an authorized representative of DTC and any
payment is made to Cede & Co., ANY TRANSFER, PLEDGE OR OTHER
USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS
WRONGFUL since the registered owner hereof, Cede & Co., has
an interest herein.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED, a
corporation duly organized and existing under the laws of
the State of New Jersey (herein referred to as the
"Company"), for value received, hereby promises to pay to
CEDE & CO., or registered assigns, the principal amount
of____________ Million Dollars ($___,000,000), on June 15,
2001 ("Stated Maturity") (unless and to the extent earlier
redeemed or repaid prior to such date) and to pay interest
thereon from June 15, 1999 or from the most recent Interest
Payment Date (as defined below) to which interest has been
paid or duly provided for in arrears on September 15, 1999,
December 15, 1999 and March 15, 2000, and any other date as
shall be established by the Company as an interest payment
date in accordance with the provisions set forth below
(each, an "Interest Payment Date"), and at maturity or
earlier redemption, until the principal hereof is paid or
made available for payment. Interest payments for this Note
shall include interest accrued to but excluding each
Interest Payment Date. The interest so payable, and
punctually paid or duly provided for, on any Interest
Payment Date shall, as provided in the Indenture (as defined
below), be paid to the Person in whose name this Note (or
one or more Predecessor Securities) is registered at the
close of business on the Regular Record Date, which shall be
the 15th calendar day (whether or not a Business Day) next
preceding such Interest Payment Date. Except as otherwise
provided in the Indenture, any interest not punctually paid
or duly provided for on any Interest Payment Date
("Defaulted Interest") shall forthwith cease to be payable
to the Holder on the Regular Record Date with respect to
such Interest Payment Date by virtue of having been such
Holder and may either (1) be paid to the Person in whose
name this Note (or one or more Predecessor Securities) is
registered at the close of business on a Special Record Date
for the payment of such Defaulted Interest to be fixed by
the Trustee (as defined below), notice of which shall be
given to Holders of Notes not less than 10 days prior to
such Special Record Date, or (2) be paid at any time in any
other lawful manner not inconsistent with the requirements
of any securities exchange on which the Notes may be listed,
and upon such notice as may be required by such exchange,
all as more fully provided in the Indenture. Payment of the
principal of and interest, if any, on this Note shall be
made at the Corporate Trust Office of the Trustee or at the
office or agency of the Trustee maintained for that purpose
in the Borough of Manhattan, The City of New York, and at
any other office or agency maintained by the Company for
such purpose, in such coin or currency of the United States
of America as at the time of payment is legal tender for
payment of public and private debts; provided, however, that
at the option of the Company, payment of interest may be
made by check mailed to the address of the Person entitled
thereto as such address shall appear in the Security
Register and provided, further, that the Holder of this Note
shall be entitled to receive payments of principal of and
interest, if any, on this Note by wire transfer of
immediately available funds if appropriate wire transfer
instructions have been received in writing by the Trustee
not less than 15 days prior to the applicable payment date.
Reference is hereby made to the further provisions
of this Note set forth below, which further provisions shall
for all purposes have the same effect as if set forth at
this place.
Unless the certificate of authentication hereon has
been executed by the Trustee or its duly appointed
co-authenticating agent by manual signature, this Note shall
not be entitled to any benefit under the Indenture or be
valid or obligatory for any purpose.
<PAGE>
IN WITNESS WHEREOF, Public Service Enterprise Group
Incorporated has caused this Instrument to be signed by the
signature or facsimile signature of its Chairman of the
Board, its President, a Vice President, its Treasurer or an
Assistant Treasurer and attested by its Secretary or an
Assistant Secretary by his signature or a facsimile thereof,
and its corporate seal or a facsimile of its corporate seal
to be affixed hereunto or imprinted hereon.
(SEAL) PUBLIC SERVICE ENTERPRISE
GROUP INCORPORATED
By: MORTON A. PLAWNER
--- ---------------------------
Title: Vice President
Attest:
EDWARD J. BIGGINS, JR.
- -------------------------------
Title: Secretary
Dated: June 15, 1999
TRUSTEE'S CERTIFICATE OF AUTHENTICATION
This is one of the Securities of the series
designated therein referred to in the within-mentioned
Indenture.
FIRST UNION NATIONAL BANK, as Trustee
By: FRANK GALLAGHER
-----------------------
Authorized Signatory
<PAGE>
This Note is one of a duly authorized issue of
securities (the "Securities") of the Company (which term
includes any successor corporation under the Indenture
hereinafter referred to) issued and to be issued pursuant to
such Indenture. This Security is one of a Series designated
by the Company as its Extendible Notes due June 15, 2001,
Series C (the "Notes"). The Indenture does not limit the
aggregate principal amount of the Notes or the Securities.
The Company issued this Note pursuant to an
Indenture, dated as of November 1, 1998 (the "Indenture"
which term, for the purpose of this Note, shall include the
Officers' Certificate dated June 15, 1999, delivered
pursuant to Section 301 of the Indenture), between the
Company and First Union National Bank, as trustee (the
"Trustee," which term includes any successor trustee under
the Indenture), to which Indenture and all indentures
supplemental thereto reference is hereby made for a
statement of the respective rights, limitations of rights,
duties and immunities thereunder of the Company, the Trustee
and Holders of the Notes and of the terms upon which the
Notes are, and are to be, authenticated and delivered.
The Notes are issuable as Registered Securities,
without coupons, in denominations of $1,000 and any amount
in excess thereof which is an integral multiple of $1,000.
As provided in the Indenture and subject to certain
limitations therein set forth, Notes are exchangeable for a
like aggregate principal amount of Notes of like tenor of
any authorized denomination, as requested by the Holder
surrendering the same, upon surrender of the Note or Notes
to be exchanged at any office or agency described below
where Notes may be presented for registration of transfer.
Certain provisions relating to the remarketing of
the Notes set forth below are contained in a Remarketing
Agreement dated as of June 15, 1999 (the "Remarketing
Agreement") between the Company and Merrill Lynch, Pierce,
Fenner & Smith Incorporated, as Remarketing Agent (the
"Remarketing Agent").
During the period from and including June 15, 1999
to but excluding March 15, 2000 (the "Initial Spread
Period"), interest on this Note shall be payable in arrears,
on September 15, 1999, December 15, 1999 and March 15, 2000,
except as described below. During the Initial Spread Period
the interest rate on the Notes shall be reset quarterly, on
June 15, 1999, September 15, 1999 and December 15, 1999 (the
"Interest Reset Date" in respect of the Initial Spread
Period), and the Notes shall bear interest at a per annum
rate (computed on the basis of the actual number of days
elapsed over a 360-day year) equal to LIBOR (as defined
below) for the applicable Interest Reset Period (as defined
below), plus the Initial Spread (as defined below). Interest
on this Note shall accrue from and including the most recent
Interest Payment Date to which interest has been paid or
duly provided for to but excluding the applicable Interest
Payment Date, Stated Maturity or date of earlier redemption,
as the case may be. The "Initial Interest Reset Period"
shall be the period from and including the date of original
issuance of the Notes to but excluding September 15, 1999.
Thereafter, each "Interest Reset Period" during the Initial
Spread Period shall be the quarterly period from and
including the most recent Interest Reset Date to but
excluding the next succeeding Interest Reset Date or
Remarketing Reset Date (as defined below), as the case
maybe.
The Spread applicable to the Notes during the
Initial Spread Period shall be 0.40% (the "Initial Spread"),
and the interest rate mode used for the Initial Spread
Period shall be the "Floating Rate Mode". Thus, the interest
rate per annum for the Notes during the Initial Interest
Reset Period shall be equal to LIBOR, determined as of June
11, 1999, plus the Initial Spread. The interest rate per
annum for each succeeding Interest Reset Period during the
Initial Spread Period shall equal LIBOR for such Interest
Reset Period plus the Initial Spread, calculated as
described below. Thereafter, the Spread shall be determined
in the manner described herein for each period from and
including each Remarketing Reset Date (as defined below) to
but excluding each next succeeding Remarketing Reset Date
or, as the case maybe, Stated Maturity (a "Subsequent Spread
Period"), which will be one or more periods of at least
three months and not more than the period remaining to the
Stated Maturity of this Note (or any integral multiple of
three months therein), designated by the Company, commencing
on the 15th day of September, December, March or June (or as
otherwise specified by the Company and the Remarketing Agent
on the applicable Duration/Mode Determination Date (as
defined below) in connection with the establishment of each
Subsequent Spread Period), as applicable (each such date, a
"Remarketing Reset Date"), provided, however, that no
Subsequent Spread Period may end on or after the Stated
Maturity. The initial Remarketing Reset Date shall be March
15, 2000.
If this Note is to be reset to the Floating Rate
Mode, as agreed to by the Remarketing Agent and the Company
on a Duration/Mode Determination Date, then during the
corresponding Subsequent Spread Period, (i) the interest
rate on the Notes will be reset monthly, quarterly or
semiannually (each, an "Interest Reset Period") and interest
on the Notes will be payable either monthly, quarterly or
semiannually on such dates (each such date, an "Interest
Payment Date" in respect of such Subsequent Spread Period),
in each case as specified by the Remarketing Agent and
Enterprise on the applicable Duration/Mode Determination
Date and (ii) the Notes will bear interest at a per annum
rate (computed on the basis of the actual number of days
elapsed over a 360-day year) equal to LIBOR for the
applicable Interest Reset Period, plus the applicable
Spread, as determined on the relevant Spread Determination
Date. Unless otherwise specified on the applicable
Duration/Mode Determination Date for Notes in the Floating
Rate Mode, interest on this Note shall be payable, in the
case of Notes which reset (i) monthly, on the 15th day of
each month; (ii) quarterly, on the 15th day of each
September, December, March or June; and (iii) semiannually
on the 15th day of each March and September. The first day
of an Interest Reset Period is referred to herein as an
"Interest Reset Date" in respect of the Subsequent Spread
Period and, unless otherwise specified on the applicable
15th day of each month; (ii) quarterly, on the 15th day of
September, December, March or June; and (iii) semiannually
on the 15th day of each March and September.
The interest rate in effect on each day shall be
(i) if such day is an Interest Reset Date, the interest rate
determined as of the Floating Rate Determination Date (as
defined below) immediately preceding such Interest Reset
Date or (ii) if such day is not an Interest Reset Date, the
interest rate determined as of the Floating Rate
Determination Date immediately preceding the most recent
Interest Reset Date.
If any Interest Payment Date (other than at Stated
Maturity), redemption date, repayment date, Interest Reset
Date or Remarketing Reset Date in the Floating Rate Mode
would otherwise be a day that is not a Business Day (as
defined below), such Interest Payment Date, redemption date,
repayment date, Interest Reset Date or Remarketing Reset
Date shall be postponed to the next succeeding day that is a
Business Day, except that if such Business Day is in the
next succeeding calendar month, such Interest Payment Date,
redemption date, repayment date, Interest Reset Date or
Remarketing Reset Date shall be the next preceding Business
Day.
The interest rate applicable to each Interest Reset
Period commencing on the related Interest Reset Date shall
be the rate determined as of the applicable Floating Rate
Determination Date. The "Floating Rate Determination Date"
shall be the second London Business Day (as defined below)
immediately preceding the applicable Interest Reset Date.
For the Initial Spread Period and if the Notes are
reset to the Floating Rate Mode for a Subsequent Spread
Period, LIBOR shall be determined by the Rate Agent (as
defined below) as of the applicable Floating Rate
Determination Date in accordance with the following
provisions:
(i) LIBOR shall be determined on the basis of the
offered rates for deposits in U.S. dollars of not
less than U.S.$1,000,000 of the applicable Index
Maturity (as defined below), commencing on the
second London Business Day immediately following
such Floating Rate Determination Date, which
appears on Telerate page 3750 (as defined below)
as of approximately 11:00 a.m., London time, on
such Floating Rate Determination Date. "Telerate
page 3750" means the display designated on page
"3750" on Bridge Telerate, Inc. (or such other
page as may replace the 3750 page on that service,
any successor service or such other service or
services as may be nominated by the British
Bankers' Association for the purpose of displaying
London interbank offered rates for U.S. dollar
deposits). If no rate appears on Telerate page
3750, LIBOR for such Floating Rate Determination
Date shall be determined in accordance with the
provisions of paragraph (ii) below.
(ii) With respect to a Floating Rate Determination Date
on which no rate appears on Telerate page 3750 as
of approximately 11:00 a.m., London time, on such
Floating Rate Determination Date, the Rate Agent
shall request the principal London offices of each
of four major reference banks in the London
interbank market selected by the Rate Agent to
provide the Rate Agent with a quotation of the
rate at which deposits of the applicable Index
Maturity in U.S. dollars, commencing on the second
London Business Day immediately following such
Floating Rate Determination Date, are offered by
it to prime banks in the London interbank markets
as of approximately 11:00 a.m., London time, on
such Floating Rate Determination Date in a
principal amount equal to an amount of not less
than U.S.$1,000,000 that is representative for a
single transaction in such market at such time. If
at least two such quotations are provided, LIBOR
for such Floating Rate Determination Date shall be
the arithmetic mean of such quotations as
calculated by the Rate Agent. If fewer than two
quotations are provided, LIBOR for such Floating
Rate Determination Date shall be the arithmetic
mean of the rates quoted as of approximately 11:00
a.m., New York City time, on such Floating Rate
Determination Date by three major banks in The
City of New York selected by the Rate Agent (after
consultation with the Company) for loans in U.S.
dollars to leading European banks of the
applicable Index Maturity commencing on the second
London Business Day immediately following such
Floating Rate Determination Date and in a
principal amount equal to an amount of not less
than U.S.$1,000,000 that is representative for a
single transaction in such market at such time;
provided, however, that if the banks selected as
aforesaid by the Rate Agent are not quoting as
mentioned in this sentence, LIBOR for such
Floating Rate Determination Date shall be LIBOR
determined with respect to the immediately
preceding Floating Rate Determination Date, or in
the case of the first Floating Rate Determination
Date, LIBOR for the Initial Interest Reset Period.
The "Index Maturity" applicable to Notes
in the Floating Rate Mode shall be, in the case of Notes
resetting (i) monthly, one month; (ii) quarterly, three
months; and (iii) semiannually, six months.
If this Note is to be reset to the Fixed
Rate Mode, as agreed to by the Company and the
Remarketing Agent on a Duration/Mode Determination Date,
then the applicable Fixed Rate for the corresponding
Subsequent Spread Period shall be determined by 4:00
p.m., New York City time, on the third Business Day prior
to the Remarketing Reset Date for such Subsequent Spread
Period (the "Fixed Rate Determination Date"), in
accordance with the following provisions: the Fixed Rate
shall be determined by adding (i) the applicable Spread
(as determined by the Remarketing Agent and agreed to by
the Company on the immediately preceding Spread
Determination Date) to (ii) the yield to maturity
determined by 4:00 p.m., New York City time, on the Fixed
Rate Determination Date (expressed as a bond equivalent,
on the basis of a year of 365 or 366 days, as applicable,
and applied on a daily basis) of the applicable United
States Treasury security, selected by the Rate Agent
after consultation with the Remarketing Agent, as having
a maturity comparable to the duration selected for the
following Subsequent Spread Period, which would be used
in accordance with customary financial practice in
pricing new issues of corporate debt securities of
comparable maturity to the duration selected for the
following Subsequent Spread Period.
Interest in the Fixed Rate Mode shall be
computed on the basis of a 360-day year of twelve 30-day
months. Such interest shall be payable semiannually in
arrears on the Interest Payment Dates (i.e., March 15th
and September 15th, unless otherwise specified by the
Company and the Remarketing Agent on the applicable
Duration/Mode Determination Date) at the applicable Fixed
Rate, as determined on the Fixed Rate Determination Date,
beginning on the applicable Remarketing Reset Date and
continuing for the duration of the relevant Subsequent
Spread Period.
If any Interest Payment Date, redemption
date or repayment date in the Fixed Rate Mode would
otherwise be a day that is not a Business Day (in either
case, other than any Interest Payment Date, redemption
date or repayment date that falls on a Remarketing Reset
Date, in which case each such date shall be postponed to
the next day that is a Business Day), the related payment
of principal and interest shall be made on the next
succeeding Business Day as if it were made on the date
such payment was due, and no interest shall accrue on the
amounts so payable for the period from and after such
date to the next succeeding Business Day.
Unless notice of redemption of the Notes
as a whole has been given, after the Initial Spread
Period, the duration, redemption dates, redemption type
(i.e., par, premium or make-whole, as described below),
redemption prices (if applicable), repayment dates,
Remarketing Reset Date, Interest Reset Dates, Interest
Payment Dates, interest rate mode (i.e., Fixed Rate Mode
or Floating Rate Mode, as described below), optional
repayment terms, if any, and any other relevant terms for
each Subsequent Spread Period shall be agreed to by the
Company and the Remarketing Agent by 3:00 p.m., New York
City time, on the eighth Business Day prior to the
Remarketing Reset Date which commences such Subsequent
Spread Period (the "Duration/Mode Determination Date").
In addition, the Spread for each Subsequent Spread Period
shall be established by 3:00 p.m., New York City time, on
the fourth Business Day prior to the Remarketing Reset
Date which commences such Subsequent Spread Period (the
"Spread Determination Date"). Interest on this Note
during each Subsequent Spread Period shall accrue, as
applicable, either (i) at a floating interest rate (such
Note being in the "Floating Rate Mode" and such interest
rate being a "Floating Rate") or (ii) at a fixed interest
rate (such Note being in the "Fixed Rate Mode" and such
interest being a "Fixed Rate"), in each case as
determined by the Remarketing Agent and the Company in
accordance with the Remarketing Agreement and the
applicable Remarketing Agency Agreement (as defined
below).
The term "Business Day" means any day
other than a Saturday or Sunday or a day on which banking
institutions in The City of New York are required or
authorized to close and, if this Note is in the Floating
Rate Mode (as defined below), that is also a London
Business Day. The term "London Business Day" means any
day on which dealings in deposits in U.S. dollars are
transacted in the London interbank market.
IN THE EVENT THAT THE COMPANY AND
REMARKETING AGENT DO NOT AGREE ON THE SPREAD FOR ANY
SUBSEQUENT SPREAD PERIOD, THEN THE COMPANY IS REQUIRED
UNCONDITIONALLY TO REPURCHASE AND RETIRE ALL OF THE NOTES
ON THE REMARKETING RESET DATE AT A PRICE EQUAL TO 100% OF
THE PRINCIPAL AMOUNT OF THE NOTES, TOGETHER WITH ACCRUED
AND UNPAID INTEREST, IF ANY, THEREON TO BUT EXCLUDING THE
REMARKETING RESET DATE.
All percentages resulting from any
calculation of any interest rate for this Note shall be
rounded, if necessary, to the nearest one hundred
thousandth of a percentage point, with five one
millionths of a percentage point rounded upward and all
dollar amounts shall be rounded to the nearest cent, with
one-half cent being rounded upward.
In the event the Company and the
Remarketing Agent agree on the Spread on the Spread
Determination Date with respect to any Subsequent Spread
Period and the Company and the Remarketing Agent enter
into a Remarketing Agency Agreement (the "Remarketing
Agency Agreement") on such Spread Determination Date, on
the Remarketing Reset Date which commences such
Subsequent Spread Period, this Note shall be
automatically tendered, or deemed tendered, to the
Remarketing Agent for remarketing by the Remarketing
Agent on the Remarketing Reset Date at 100% of the
principal amount hereof (the "Purchase Price") unless the
beneficial owner of this Note, at such owner's option,
upon giving notice as provided below (the "Hold Notice"),
elects not to tender this Note. Subject to the second
succeeding paragraph, the Purchase Price shall be paid by
the Remarketing Agent in accordance with the standard
procedures of DTC, which currently provide for payments
in same-day funds. Interest accrued on such Notes with
respect to the preceding interest period shall be paid by
the Company in the manner described above.
The Hold Notice must be received by the
Remarketing Agent through DTC during the period
commencing at 3:00 p.m., New York City time, on the
Duration/Mode Determination Date and ending at 12:00
noon, New York City time, on the third Business Day prior
to the Remarketing Reset Date for such Subsequent Spread
Period (the "Notice Date"); provided, however, that if
the Remarketing Agent and Enterprise are unable to agree
on the Spread for such Subsequent Spread Period, any Hold
Notices received will be null and void. Except as
otherwise provided below, a Hold Notice shall be
irrevocable. If a Hold Notice is not received for any
reason by the Remarketing Agent with respect to this Note
by 12:00 noon, New York City time, on the Notice Date,
the beneficial owner of this Note shall be deemed to have
elected to tender this Note for purchase by the
Remarketing Agent.
In the event that the Remarketing Agent is
unable to remarket some or all of the tendered Notes and,
in its sole discretion, chooses not to purchase such
tendered Notes, the Company is obligated unconditionally
to purchase and retire on the Remarketing Reset Date the
remaining unsold tendered Notes at a price equal to 100%
of the principal amount thereof, plus accrued and unpaid
interest, if any, thereon to the applicable Remarketing
Reset Date.
Notwithstanding anything to the contrary
contained herein, the Remarketing Agent shall have the
option, but not the obligation, to purchase any Notes
tendered to it that it is not able to remarket. If the
Remarketing Agent is unable to remarket the entire
principal amount of all Notes tendered on any Remarketing
Reset Date and, in its sole discretion, the Remarketing
Agent chooses not to purchase such tendered Notes, it
shall promptly notify the Company and the Trustee. No
beneficial owner of any Note shall have any rights or
claims against the Remarketing Agent as a result of the
Remarketing Agent not purchasing such Notes.
The term "Remarketing Agent" means the
nationally recognized broker-dealer selected by the
Company to act as Remarketing Agent. Pursuant to the
Remarketing Agreement, Merrill Lynch, Pierce, Fenner &
Smith Incorporated has agreed to act as Remarketing
Agent. The term "Rate Agent" means the entity selected by
the Company as its agent to determine (i) LIBOR and the
interest rate on the Notes for any Interest Reset Period
and/or (ii) the yield to maturity on the applicable
United States Treasury security that is used in
connection with the determination of the applicable Fixed
Rate, and the ensuing applicable Fixed Rate. Pursuant to
the Remarketing Agreement, Merrill Lynch, Pierce, Fenner
& Smith Incorporated has agreed to act as Rate Agent in
respect of any Fixed Rate Mode, and pursuant to a
Calculation Agency Agreement, First Union National Bank
has agreed to act as the Rate Agent in respect of any
Floating Rate Mode. The Company, in its sole discretion,
may change the Remarketing Agent and the Rate Agent for
any Subsequent Spread Period at any time on or prior to
3:00 p.m., New York City time, on the Duration/Mode
Determination Date relating thereto.
This Note may not be redeemed by the
Company prior to March 15, 2000. On that date, on each
subsequent Remarketing Reset Date and on those Interest
Payment Dates or other dates specified as redemption
dates by the Company on the Duration/Mode Determination
Date in connection with any Subsequent Spread Period, the
Notes may be redeemed, at the option of the Company, in
whole or in part, upon notice thereof (as described
below) given at any time during the 30 calendar day
period ending on the eighth Business Day prior to the
redemption date (or fifteen Business Days, prior to the
redemption date in the case of a partial redemption), in
accordance with the redemption type selected on the
Duration/Mode Determination Date. This Note is also
subject to redemption in accordance with other provisions
specified above. In the event that less than all of the
outstanding Notes are to be redeemed, the Notes to be
redeemed shall be selected by such method as the Company
shall deem fair and appropriate.
The redemption type to be chosen by the
Company and the Remarketing Agent on the Duration/Mode
Determination Date with respect to any Subsequent Spread
Period may be one of the following as defined herein: (i)
Par Redemption; (ii) Premium Redemption; or (iii)
Make-Whole Redemption. "Par Redemption" means redemption
at a redemption price equal to 100% of the principal
amount thereof, plus unpaid interest thereon, if any,
accrued to the redemption date. "Premium Redemption"
means redemption at a redemption price or prices greater
than 100% of the principal amount thereof, plus unpaid
interest thereon, if any, accrued to the redemption date,
as determined on the Duration/Mode Determination Date.
"Make-Whole Redemption" means redemption at a redemption
price equal to the Make-Whole Amount (as defined below)
with respect to such Notes. Unless otherwise specified by
the Company and the Remarketing Agent on any
Duration/Mode Determination Date, the redemption type
shall be Par Redemption. The redemption in part of any
Notes must be in increments of $1,000 or integral
multiples thereof.
"Make-Whole Amount" means, in connection
with any optional redemption of any Note, an amount equal
to the greater of (i) 100% of its principal amount plus
accrued interest, if any, thereon to the date of
redemption and (ii) the sum of the present values of the
remaining scheduled payments of principal and interest
thereon discounted to the date of redemption on a
semiannual basis (assuming a 360-day year consisting of
twelve 30-day months) at the applicable Treasury Yield
plus the Reinvestment Spread.
"Treasury Yield" means, with respect to
any redemption date applicable to any of the Notes, the
rate per annum equal to the semiannual equivalent yield
to maturity of the Comparable Treasury Issue, assuming a
price for the Comparable Treasury Issue (expressed as a
percentage of its principal amount) equal to the
applicable Comparable Treasury Price for such redemption
date.
"Comparable Treasury Issue" means, with
respect to the Notes subject to redemption, the United
States Treasury security selected by the Remarketing
Agent as having a maturity comparable to the remaining
term of the Notes that would be utilized, at the time of
selection and in accordance with customary financial
practice, in pricing new issues of corporate debt
securities of comparable maturity to the remaining term
of the Notes. "Comparable Treasury Price" means, with
respect to any redemption date applicable to the Notes
subject to redemption, (i) the average of the applicable
Reference Treasury Dealer Quotations for such redemption
date, after excluding the highest and lowest of such
applicable Reference Treasury Dealer Quotations, or (ii)
if the Trustee obtains fewer than four such Reference
Treasury Dealer Quotations, the average of all such
Quotations, or (iii) if only one Reference Treasury
Dealer Quotation is received, such Quotation. "Reference
Treasury Dealer Quotations" means, with respect to each
Reference Treasury Dealer and any redemption date for the
Notes subject to redemption, the average, as determined
by the Trustee, of the bid and asked prices for the
Comparable Treasury Issue for the Notes (expressed in
each case as a percentage of its principal amount) quoted
in writing to the Trustee by such Reference Treasury
Dealer at 3:30 p.m. on the third business day preceding
such redemption date.
"Reference Treasury Dealer" means, with
respect to the Notes subject to redemption, at least four
primary U.S. Government securities dealers in New York
City as the Company shall select, which may include the
Remarketing Agent or an affiliate thereof.
"Reinvestment Spread" means, with respect
to the Notes subject to redemption, a number, expressed
as a number of basis points or as a percentage, selected
by the Company and agreed to by the Remarketing Agent on
the Duration/Mode Determination Date.
All notices of redemption shall state the
redemption date, the redemption price, if fewer than all
the Outstanding Notes are to be redeemed, the
identification (and, in the case of partial redemption,
the principal amounts) of the particular Notes to be
redeemed, that on the redemption date the redemption
price shall become due and payable upon each Note, or
portion thereof, to be redeemed, that interest on each
Note, or portion thereof, called for redemption shall
cease to accrue on the redemption date and the place or
places where Notes may be surrendered for redemption.
In the event of redemption of this Note in
part only, a new Note or Notes of like tenor for the
unredeemed portion hereof shall be issued in authorized
denominations in the name of the Holder hereof upon the
cancellation hereof.
For all purposes of this Note and the
Indenture, unless the context otherwise requires, all
provisions relating to the redemption by the Company of
this Note shall relate, in the case that this Note is
redeemed or to be redeemed by the Company only in part to
that portion of the principal amount of this Note that
has been or is to be redeemed.
The Notes will not be subject to repayment
at the option of the Holders thereof prior to the initial
Remarketing Reset Date. Thereafter, if the Company so
elects on the Duration/Mode Determination Date preceding
a Subsequent Spread Period, the Notes will be subject to
repayment at the option of the holders thereof, during
such Subsequent Spread Period, on such date(s) as the
Company may select, in whole or in part in increments of
$1,000 or integral multiples thereof, at a repayment
price equal to 100% of the unpaid principal amount to be
repaid, together with unpaid interest accrued thereon to
but excluding the date of repayment or within such other
notice period as may be specified on the applicable
Duration/Mode Determination Date.
If an Event of Default (as set forth in
the Indenture) with respect to Notes shall occur and be
continuing, the principal of the Notes may be declared
due and payable in the manner and with the effect
provided in the Indenture.
The Indenture permits, in certain
circumstances therein specified, the amendment thereof
without the consent of the Holders of the Securities. The
Indenture also permits, with certain exceptions as
therein provided, the amendment thereof and the
modification of the rights and obligations under the
Indenture of the Company and the rights of Holders of the
Securities of each series to be affected under the
Indenture at any time by the Company and the Trustee with
the consent of the Holders of a majority in aggregate
principal amount of the Securities at the time
Outstanding of each series to be affected. The Indenture
also contains provisions permitting the Holders of a
majority in aggregate principal amount of the Securities
of each series at the time Outstanding, on behalf of the
Holders of all the Securities of such series, to waive
compliance by the Company with certain provisions of the
Indenture and certain past defaults under the Indenture
and their consequences. Any such consent or waiver by the
Holder of this Note shall be conclusive and binding upon
such Holder and upon all future Holders of this Note and
of any Note issued upon the registration of transfer
hereof or in exchange herefor or in lieu hereof, whether
or not notation of such consent or waiver is made upon
this Note.
No reference herein to the Indenture and
no provision of this Note, subject to the provisions for
satisfaction and discharge in Article Four of the
Indenture, shall alter or impair the obligation of the
Company, which is absolute and unconditional, to pay the
principal of and interest on this Note at the times,
place and rate, and in the coin or currency, herein
prescribed.
The Indenture permits the Company, by
irrevocably depositing, in amounts and maturities
sufficient to pay and discharge at the Stated Maturity or
redemption date, as the case may be, the entire
indebtedness on all Outstanding Notes, cash or U.S.
Government Obligations with the Trustee in trust solely
for the benefit of the Holders of all Outstanding Notes,
to defease the Indenture with respect to such Notes, and
upon such deposit the Company shall be deemed to have
paid and discharged its entire indebtedness on such
Notes. Thereafter, Holders would be able to look only to
such trust fund for payment of principal and interest at
the Stated Maturity or redemption date, as the case may
be.
As provided in the Indenture and subject
to certain limitations therein set forth, the transfer of
Notes is registrable in the Security Register, upon
surrender of a Note for registration of transfer at the
Corporate Trust Office of the Trustee or at the office or
agency of the Trustee in the Borough of Manhattan, The
City of New York, or at such other offices or agencies as
the Company may designate, duly endorsed by, or
accompanied by a written instrument of transfer in form
satisfactory to the Company and the Security Registrar
duly executed by, the Holder hereof or his attorney duly
authorized in writing, and thereupon one or more new
Notes of like tenor, of authorized denominations and for
the same aggregate principal amount, shall be issued to
the designated transferee or transferees.
No service charge shall be made by the
Company, the Trustee or the Security Registrar for any
such registration of transfer or exchange, but the
Company may require payment of a sum sufficient to cover
any tax or other governmental charge payable in
connection therewith (other than exchanges pursuant to
Sections 304, 906 or 1107 of the Indenture, not involving
any transfer).
Prior to due presentment of this Note for
registration of transfer, the Company, the Trustee and
any agent of the Company or the Trustee may treat the
Person in whose name this Note is registered as the owner
hereof for all purposes, whether or not this Note be
overdue, and neither the Company, the Trustee nor any
such agent shall be affected by notice to the contrary.
This Note shall be governed by and
construed in accordance with the law of the State of New
Jersey without regard to principles of conflicts of laws.
All undefined terms used in this Note
which are defined in the Indenture shall have the
meanings assigned to them in the Indenture.
<PAGE>
ABBREVIATIONS
The following abbreviations, when used in the
inscription on the face of this instrument, shall be
construed as though they were written out in full according
to applicable laws or regulations:
TEN COM - as tenants in common UNIF GIFT MIN ACT _____Custodian _____
(Cust.) (Minor)
TEN ENT - as tenants by the Under Uniform Gifts to Minor Act
(State)
JT TEN - as joint tenants with right
of survivorship and not as
tenants in common
Additional abbreviations may also be used though
not in the above list.
--------------------
FOR VALUE RECEIVED, the undersigned hereby sells(s), assign(s)
and transfer(s) unto
Please Insert Social Security or Employer
Identification number of assignee
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- ------------------------------------------------------------
Please Print or Typewrite Name and Address
Including Postal Zip Code of Assignee
- ------------------------------------------------------------
The within Security and all rights thereunder, hereby
irrevocably constituting and appointing
__________________________ attorney to transfer said
Security on the books of the Company, with full power of
substitution in the premises.
Dated: __________ _______________________
Signature
NOTICE: The signature to this assignment must
correspond with the name as it appears upon the
face of the within Note in every particular,
without alteration or enlargement or any change
whatever.
<TABLE>
EXHIBIT 12
- --------------------------------------------------------------------------------------------------------------------------
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
- --------------------------------------------------------------------------------------------------------------------------
<CAPTION>
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
12 Months
Ended
YEARS ENDED DECEMBER 31, June 30,
------------- ------------ ------------- ------------ ------------ -----------
1994 1995 1996 1997 1998 1999
------------- ------------ ------------- ------------ ------------ -----------
<S> <C> <C> <C> <C> <C> <C>
Earnings as Defined in Regulation S-K (A):
Income from Continuing Operations (B) $667 $627 $588 $560 $644 $700
Income Taxes (C) 320 348 297 313 428 463
Fixed Charges 535 549 527 543 577 590
------------- ------------ ------------- ------------ ---------- -----------
Earnings $1,522 $1,524 $1,412 $1,416 $1,649 $1,753
============= ============ ============= ============ =========== ===========
Fixed Charges as Defined in Regulation S-K (D):
Total Interest Expense (E) $462 $464 $453 $470 $481 $477
Interest Factor in Rentals 12 12 12 11 11 11
Subsidiaries' Preferred Securities
Dividend Requirements 2 16 28 44 71 88
Preferred Stock Dividends 41 34 22 12 9 9
Adjustment to Preferred Stock
Dividends to state on a
pre-income
tax basis 18 23 12 6 5 5
------------ ------------ ------------- ------------ ----------- -----------
Total Fixed Charges $535 $549 $527 $543 $577 $590
============= ============ ============= ============ =========== ===========
Ratio of Earnings to Fixed Charges 2.84 2.78 2.68 2.61 2.86 2.97
============= ============ ============= ============ =========== ===========
<FN>
(A) The term "earnings" shall be defined as pretax income from continuing
operations. Add to pretax income the amount of fixed charges adjusted to
exclude (a) the amount of any interest capitalized during the period and
(b) the actual amount of any preferred stock dividend requirements of
majority-owned subsidiaries which were included in such fixed charges
amount but not deducted in the determination of pretax income.
(B) Excludes income from discontinued operations and extraordinary item.
(C) Includes State income taxes and Federal income taxes for other income and
excludes taxes applicable to extraordinary item.
(D) Fixed Charges represent (a) interest, whether expensed or capitalized, (b)
amortization of debt discount, premium and expense, (c) an estimate of
interest implicit in rentals, and (d) preferred securities dividend
requirements of subsidiaries and preferred stock dividends, increased to
reflect the pretax earnings requirement for Public Service Enterprise
Group Incorporated.
(E) Excludes interest expense from discontinued operations.
</FN>
</TABLE>
<TABLE>
EXHIBIT 12 (A)
- ----------------------------------------------------------------------------------------------------------------------------
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
- ----------------------------------------------------------------------------------------------------------------------------
<CAPTION>
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
12 Months
Ended
YEARS ENDED DECEMBER 31, June 30,
----------- ------------ ------------- ------------ ------------ ----------
1994 1995 1996 1997 1998 1999
----------- ------------ ------------- ------------ ------------ ----------
<S> <C> <C> <C> <C> <C> <C>
Earnings as Defined in Regulation S-K (A):
Net Income (B) $659 $617 $535 $528 $604 $663
Income Taxes (C) 302 326 268 286 406 447
Fixed Charges 408 419 438 450 446 449
----------- ------------ ------------- ------------ ----------- -----------
Earnings $1,369 $1,362 $1,241 $1,264 $1,456 $1,559
=========== ============ ============= ============ ============ ===========
Fixed Charges as Defined in Regulation S-K (D):
Total Interest Expense $396 $407 $399 $395 $390 $391
Interest Factor in Rentals 12 12 11 11 11 11
Subsidiaries' Preferred Securities
Dividend Requirements -- -- 28 44 45 47
----------- ------------ ------------- ------------ ------------ -----------
Total Fixed Charges $408 $419 $438 $450 $446 $449
=========== ============ ============= ============ ============ ===========
Ratio of Earnings to Fixed Charges 3.35 3.25 2.83 2.81 3.27 3.47
=========== ============ ============= ============ ============ ===========
<FN>
(A) The term "earnings" shall be defined as pretax income from continuing
operations. Add to pretax income the amount of fixed charges adjusted to
exclude (a) the amount of any interest capitalized during the period and
(b) the actual amount of any preferred stock dividend requirements of
majority-owned subsidiaries which were included in such fixed charges
amount but not deducted in the determination of pretax income.
(B) Excludes extraordinary item.
(C) Includes State income taxes and Federal income taxes for other income and
excludes taxes applicable to extraordinary item.
(D) Fixed Charges represent (a) interest, whether expensed or capitalized, (b)
amortization of debt discount, premium and expense, (c) an estimate of
interest implicit in rentals, and (d) Preferred Securities Dividend
Requirements of subsidiaries.
</FN>
</TABLE>
<TABLE>
EXHIBIT 12 (B)
- -----------------------------------------------------------------------------------------------------------------------------
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
- -----------------------------------------------------------------------------------------------------------------------------
<CAPTION>
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS
12 Months
Ended
YEARS ENDED DECEMBER 31, June 30,
------------ ------------- ------------ ------------ ------------- ------------
1994 1995 1996 1997 1998 1999
------------ ------------- ------------ ------------ ------------- ------------
<S> <C> <C> <C> <C> <C> <C>
Earnings as Defined in Regulation S-K (A):
Net Income (B) $659 $617 $535 $528 $604 $663
Income Taxes (C) 302 326 268 286 406 447
Fixed Charges 408 419 438 450 446 449
------------ ------------- ------------ ------------ ------------- ------------
Earnings $1,369 $1,362 $1,241 $1,264 $1,456 $1,559
============ ============= ============ ============ ============= ============
Fixed Charges as Defined in Regulation S-K (D):
Total Interest Expense $396 $407 $399 $395 $390 $391
Interest Factor in Rentals 12 12 11 11 11 11
Subsidiaries' Preferred Securities
Dividend Requirements -- -- 28 44 45 47
Preferred Stock Dividends 42 49 23 12 9 9
Adjustment to Preferred Stock
Dividends to state on a pre-income
tax basis 19 24 12 6 6 7
------------ ------------- ------------ ------------ ------------- ------------
Total Fixed Charges $469 $492 $473 $468 $461 $465
============ ============= ============ ============ ============= ============
Ratio of Earnings to Fixed Charges 2.92 2.77 2.62 2.70 3.15 3.35
============ ============= ============ ============ ============= ============
<FN>
(A) The term "earnings" shall be defined as pretax income from continuing
operations. Add to pretax income the amount of fixed charges adjusted to
exclude (a) the amount of any interest capitalized during the period and
(b) the actual amount of any preferred stock dividend requirements of
majority-owned subsidiaries which were included in such fixed charges
amount but not deducted in the determination of pretax income.
(B) Excludes extraordinary item.
(C) Includes State income taxes and Federal income taxes for other income and
excludes taxes applicable to extraordinary item.
(D) Fixed Charges represent (a) interest, whether expensed or capitalized, (b)
amortization of debt discount, premium and expense, (c) an estimate of
interest implicit in rentals, and (d) preferred securities dividend
requirements of subsidiaries and preferred stock dividends, increased to
reflect the pretax earnings requirement for Public Service Electric and
Gas Company.
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from SEC Form
10-Q and is qualified in its entirety by reference to such financial statements.
</LEGEND>
<CIK> 0000788784
<NAME> PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
<MULTIPLIER>1000000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1999
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 6,839
<OTHER-PROPERTY-AND-INVEST> 4,365
<TOTAL-CURRENT-ASSETS> 2,012
<TOTAL-DEFERRED-CHARGES> 5,251
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 18,467
<COMMON> 3,096 <F1>
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 1,089
<TOTAL-COMMON-STOCKHOLDERS-EQ> 4,012 <F2>
1,113
95
<LONG-TERM-DEBT-NET> 4,840
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 1,288
<LONG-TERM-DEBT-CURRENT-PORT> 851
0
<CAPITAL-LEASE-OBLIGATIONS> 50
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 6,218
<TOT-CAPITALIZATION-AND-LIAB> 18,467
<GROSS-OPERATING-REVENUE> 3,231
<INCOME-TAX-EXPENSE> 266 <F3>
<OTHER-OPERATING-EXPENSES> 2,333
<TOTAL-OPERATING-EXPENSES> 2,597
<OPERATING-INCOME-LOSS> 634
<OTHER-INCOME-NET> 16
<INCOME-BEFORE-INTEREST-EXPEN> 650
<TOTAL-INTEREST-EXPENSE> 281 <F4>
<NET-INCOME> (421) <F5>
52
<EARNINGS-AVAILABLE-FOR-COMM> (421)
<COMMON-STOCK-DIVIDENDS> 238
<TOTAL-INTEREST-ON-BONDS> 201
<CASH-FLOW-OPERATIONS> 603
<EPS-BASIC> (1.90)
<EPS-DILUTED> (1.90)
<FN>
<F1>Includes Treasury Stock of ($507) million.
<F2>Includes Foreign Currency Translation Adjustment of ($170) million.
<F3>Federal and State Income Taxes for Other Income of $2 million were
incorporated into this line for FDS purposes. In the referenced financial
statements, Total Other Income and Deductions are net of the above applicable
Federal and State income taxes.
<F4>Total interest expense includes Preferred Securities Dividends Requirements.
<F5> Net Loss includes an extraordinary charge of $790 million, net of tax of
$345 million. The extraordinary charge impacted EPS (basic and diluted) by
$(3.57).
</FN>
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<LEGEND>
This schedule contains summary financial information extracted from SEC Form
10-Q and is qualified in its entirety by reference to such financial statements.
</LEGEND>
<CIK> 0000081033
<NAME> PUBLIC SERVICE ELECTRIC AND GAS COMPANY
<MULTIPLIER>1000000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1999
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 6,839
<OTHER-PROPERTY-AND-INVEST> 834
<TOTAL-CURRENT-ASSETS> 1,758
<TOTAL-DEFERRED-CHARGES> 5,207
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 14,638
<COMMON> 2,563
<CAPITAL-SURPLUS-PAID-IN> 594
<RETAINED-EARNINGS> 529
<TOTAL-COMMON-STOCKHOLDERS-EQ> 3,683
588
95
<LONG-TERM-DEBT-NET> 3,393
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 940
<LONG-TERM-DEBT-CURRENT-PORT> 735
0
<CAPITAL-LEASE-OBLIGATIONS> 50
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 5,154
<TOT-CAPITALIZATION-AND-LIAB> 14,638
<GROSS-OPERATING-REVENUE> 2,963
<INCOME-TAX-EXPENSE> 242 <F1>
<OTHER-OPERATING-EXPENSES> 2,188
<TOTAL-OPERATING-EXPENSES> 2,428
<OPERATING-INCOME-LOSS> 535
<OTHER-INCOME-NET> 3
<INCOME-BEFORE-INTEREST-EXPEN> 538
<TOTAL-INTEREST-EXPENSE> 209 <F2>
<NET-INCOME> (461) <F3>
5
<EARNINGS-AVAILABLE-FOR-COMM> (466)
<COMMON-STOCK-DIVIDENDS> 392
<TOTAL-INTEREST-ON-BONDS> 160
<CASH-FLOW-OPERATIONS> 538
<EPS-BASIC> 0
<EPS-DILUTED> 0
<FN>
<F1>State and Federal Income Taxes for Other Income of $2 million were
incorporated into this line item for FDS purposes. In the referenced financial
statements, Total Other Income and Deductions are net of the above applicable
Federal and State income taxes.
<F2>Total interest expense includes Preferred Securities Dividend Requirements.
<F3>Net Loss includes an extraordinary charge of $790 million, net of tax of
$345 million.
</FN>
</TABLE>
