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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 March 31, 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 April 30, 1999: 219,563,008
As of April 30, 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.
<PAGE>
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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
Months Ended March 31, 1999 and 1998............................ 1
Consolidated Balance Sheets as of March 31, 1999
and December 31, 1998........................................... 2
Consolidated Statements of Cash Flows for the Three
Months Ended March 31, 1999 and 1998............................ 4
Public Service Electric and Gas Company (PSE&G):
Consolidated Statements of Income for the Three
Months Ended March 31, 1999 and 1998............................ 5
Consolidated Balance Sheets as of March 31, 1999
and December 31, 1998........................................... 6
Consolidated Statements of Cash Flows for the Three
Months Ended March 31, 1999 and 1998............................ 8
Notes to Consolidated Financial Statements-- PSEG................. 9
Notes to Consolidated Financial Statements-- PSE&G................ 23
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations
PSEG ........................................................... 24
PSE&G........................................................... 36
Item 3. Qualitative and Quantitative Disclosures About Market Risk.. 37
PART II. OTHER INFORMATION
Item 1. Legal Proceedings........................................... 38
Item 4. Submission of Matters to a Vote of Security Holders......... 39
Item 5. Other Information........................................... 39
Item 6. Exhibits and Reports on Form 8-K............................ 41
Signatures -- PSEG.................................................. 42
Signatures -- PSE&G................................................. 42
<PAGE>
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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)
<CAPTION>
For the Quarters Ended
March 31,
-------------------------------
1999 1998
------------ -----------
<S> <C> <C>
OPERATING REVENUES
Electric $ 966 $ 902
Gas 700 612
Nonutility Activities 129 145
----------- -----------
Total Operating Revenues 1,795 1,659
----------- -----------
OPERATING EXPENSES
Net Interchanged Power and Fuel for Electric Generation 225 219
Gas Purchased 449 416
Operation and Maintenance 438 357
Depreciation and Amortization 166 157
Taxes (Note 6)
Income Taxes 143 132
Other 56 61
----------- -----------
Total Operating Expenses 1,477 1,342
----------- -----------
OPERATING INCOME 318 317
----------- -----------
OTHER INCOME AND DEDUCTIONS 6 7
----------- -----------
INCOME BEFORE INTEREST CHARGES AND
DIVIDENDS ON PREFERRED SECURITIES 324 324
----------- -----------
INTEREST CHARGES AND PREFERRED SECURITIES DIVIDENDS
Interest Expense 114 121
Allowance for Funds Used During Construction - Debt and
Capitalized Interest (2) (4)
Preferred Securities Dividend Requirements of Subsidiaries 24 16
----------- -----------
Total Interest Charges and Preferred Securities Dividends 136 133
----------- -----------
NET INCOME $ 188 $ 191
=========== ===========
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (000's) 222,703 231,958
EARNINGS PER SHARE (Basic and Diluted) $ 0.85 $ 0.82
=========== ===========
DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 0.54 $ 0.54
=========== ===========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions of Dollars)
<CAPTION>
March 31, December 31,
1999 1998
-------------- -----------------
<S> <C> <C>
UTILITY PLANT - Original cost
Electric $ 14,234 $ 14,164
Gas 2,895 2,878
Common 435 433
-------------- -----------------
Total 17,564 17,475
Less: Accumulated depreciation and amortization 7,222 7,048
-------------- -----------------
Net 10,342 10,427
Nuclear Fuel in Service, net of accumulated amortization -
1999, $325; 1998, $312 175 187
-------------- -----------------
Net Utility Plant in Service 10,517 10,614
Construction Work in Progress, including Nuclear Fuel in
Process - 1999, $77; 1998, $72 214 219
Plant Held for Future Use 21 24
-------------- -----------------
Net Utility Plant 10,752 10,857
-------------- -----------------
INVESTMENTS AND OTHER NONCURRENT ASSETS
Long-Term Investments, net of amortization - 1999, $30; 1998,
$28, and net of valuation allowances - 1999, $14; 1998, $18 2,946 3,034
Nuclear Decommissioning and Other Special Funds 667 649
Other Noncurrent Assets, net of amortization - 1999, $29; 1998,
$29, and net of valuation allowances - 1999, $10; 1998, $10 157 150
-------------- -----------------
Total Investments and Other Noncurrent Assets 3,770 3,833
-------------- -----------------
CURRENT ASSETS
Cash and Cash Equivalents 69 140
Accounts Receivable:
Customer Accounts Receivable 669 506
Other Accounts Receivable 209 219
Less: Allowance for Doubtful Accounts 54 38
Unbilled Revenues 192 255
Fuel, at average cost 204 331
Materials and Supplies, at average cost, net of
valuation reserves - 1999, $12; 1998, $12 176 167
Miscellaneous Current Assets 78 93
-------------- -----------------
Total Current Assets 1,543 1,673
-------------- -----------------
DEFERRED DEBITS (Note 3)
SFAS 109 Income Taxes 690 704
OPEB Costs 265 270
Demand Side Management Costs 143 150
Environmental Costs 126 139
Unamortized Loss on Reacquired Debt and Debt Expense 131 135
Other 230 236
-------------- -----------------
Total Deferred Debits 1,585 1,634
-------------- -----------------
TOTAL $ 17,650 $ 17,997
============== =================
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
(Millions of Dollars)
<CAPTION>
March 31, 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 - 11,326,200 shares,
1998 - 5,314,100 shares (442) (207)
Retained Earnings 1,816 1,748
Accumulated Other Comprehensive Income (171) (46)
------------ ---------------
Total Common Stockholders' Equity 4,806 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 (Note 5) 1,038 1,038
Long-Term Debt 4,912 4,763
------------ ---------------
Total Capitalization 10,926 11,069
------------ ---------------
OTHER LONG-TERM LIABILITIES
Accrued OPEB 357 344
Environmental Costs (Note 4) 83 84
Capital Lease Obligations 50 50
Other 76 65
------------ ---------------
Total Other Long-Term Liabilities 566 543
------------ ---------------
CURRENT LIABILITIES
Long-Term Debt due within one year 372 418
Commercial Paper and Loans 724 1,056
Accounts Payable 504 655
Accrued Taxes 262 41
Other 413 288
------------ ---------------
Total Current Liabilities 2,275 2,458
------------ ---------------
DEFERRED CREDITS
Income Taxes 3,310 3,384
Investment Tax Credits 319 322
Other 254 221
------------ ---------------
Total Deferred Credits 3,883 3,927
------------ ---------------
COMMITMENTS AND CONTINGENT LIABILITIES (Note 4) - -
------------ ---------------
TOTAL $ 17,650 $ 17,997
============ ===============
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
<CAPTION>
For the Quarters Ended
March 31,
-----------------------
1999 1998
--------- ----------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 188 $ 191
Adjustments to reconcile net income to net cash flows from
operating activities:
Depreciation and Amortization 166 157
Recovery of Electric Energy and Gas Costs - net 89 28
Provision for Deferred Income Taxes - net (70) (1)
Unrealized Gains on Investments (24) (35)
Proceeds from Leasing Activities (14) (59)
Changes in certain current assets and liabilities:
Net change in Accounts Receivable and Unbilled Revenues (74) 48
Net change in Inventory - Fuel and Materials and Supplies 118 136
Net change in Accounts Payable (151) (73)
Net change in Accrued Taxes 221 184
Net change in Other Current Assets and Liabilities 140 (13)
Other 25 23
--------- ----------
Net Cash Provided By Operating Activities 614 586
--------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Utility Plant, excluding AFDC (79) (81)
Net change in Long-Term Investments (3) 45
Contribution to Decommissioning Funds and Other Special Funds (12) (29)
Other (7) (17)
--------- ----------
Net Cash Used In Investing Activities (101) (82)
--------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Net change in Short-Term Debt (332) (478)
Issuance of Long-Term Debt 252 -
Redemption of Long-Term Debt (149) (122)
Issuance of Preferred Securities - 225
Purchase of Treasury Stock (235) -
Cash Dividends Paid on Common Stock (120) (125)
Other - (10)
--------- ----------
Net Cash Used In Financing Activities (584) (510)
--------- ----------
Net Change In Cash And Cash Equivalents (71) (6)
Cash And Cash Equivalents At Beginning Of Period 140 83
--------- ----------
Cash And Cash Equivalents At End Of Period $ 69 $ 77
========= ==========
Income Taxes Paid $ 1 $ 50
Interest Paid $ 107 $ 109
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars)
<CAPTION>
For the Quarters Ended
March 31,
----------------------------
1999 1998
---------- ----------
<S> <C> <C>
OPERATING REVENUES
Electric $ 966 $ 902
Gas 700 612
---------- ----------
Total Operating Revenues 1,666 1,514
---------- ----------
OPERATING EXPENSES
Net Interchanged Power and Fuel for Electric Generation 221 216
Gas Purchased 424 391
Operation and Maintenance 394 323
Depreciation and Amortization 165 152
Taxes (Note 6)
Income Taxes 133 115
Other 56 58
---------- ----------
Total Operating Expenses 1,393 1,255
---------- ----------
OPERATING INCOME 273 259
---------- ----------
OTHER INCOME AND DEDUCTIONS 3 2
---------- ----------
INCOME BEFORE INTEREST CHARGES AND
DIVIDENDS ON PREFERRED SECURITIES 276 261
---------- ----------
INTEREST CHARGES AND PREFERRED SECURITIES DIVIDENDS
Interest Expense 95 96
Allowance for Funds Used During Construction - Debt (2) (3)
Preferred Securities Dividend Requirements of Subsidiaries 11 11
---------- ----------
Total Interest Charges and Preferred Securities Dividends 104 104
---------- ----------
NET INCOME 172 157
---------- ----------
Preferred Stock Dividend Requirements 3 2
---------- ----------
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE
GROUP INCORPORATED $ 169 $ 155
========== ==========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions of Dollars)
<CAPTION>
March 31, December 31,
1999 1998
---------------- -----------------
<S> <C> <C>
UTILITY PLANT - Original cost
Electric $ 14,234 $ 14,164
Gas 2,895 2,878
Common 435 433
---------------- -----------------
Total 17,564 17,475
Less: Accumulated depreciation and amortization 7,222 7,048
---------------- -----------------
Net 10,342 10,427
Nuclear Fuel in Service, net of accumulated amortization -
1999, $325; 1998, $312 175 187
---------------- -----------------
Net Utility Plant in Service 10,517 10,614
Construction Work in Progress, including Nuclear Fuel in
Process - 1999, $77; 1998, $72 214 219
Plant Held for Future Use 21 24
---------------- -----------------
Net Utility Plant 10,752 10,857
---------------- -----------------
INVESTMENTS AND OTHER NONCURRENT ASSETS
Long-Term Investments 69 65
Nuclear Decommissioning and Other Special Funds 667 649
Other Noncurrent Assets 32 46
---------------- -----------------
Total Investments and Other Noncurrent Assets 768 760
---------------- -----------------
CURRENT ASSETS
Cash and Cash Equivalents 15 42
Accounts Receivable:
Customer Accounts Receivable 608 451
Other Accounts Receivable 152 178
Less: Allowance for Doubtful Accounts 40 34
Unbilled Revenues 192 255
Fuel, at average cost 204 331
Materials and Supplies, at average cost, net of
valuation reserves - 1999, $12; 1998, $12 176 165
Miscellaneous Current Assets 61 84
---------------- -----------------
Total Current Assets 1,368 1,472
---------------- -----------------
DEFERRED DEBITS (Note 3)
SFAS 109 Income Taxes 690 704
OPEB Costs 265 270
Demand Side Management Costs 143 150
Environmental Costs 126 139
Unamortized Loss on Reacquired Debt and Debt Expense 131 135
Other 194 182
---------------- -----------------
Total Deferred Debits 1,549 1,580
---------------- -----------------
TOTAL $ 14,437 $ 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>
March 31, 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 1,278 1,386
Accumulated Other Comprehensive Income (3) (3)
------------- ----------------
Total Common Stockholder's Equity 4,432 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 (Note 5) 513 513
Long-Term Debt 3,946 4,045
------------- ----------------
Total Capitalization 9,061 9,268
------------- ----------------
OTHER LONG-TERM LIABILITIES
Accrued OPEB 357 344
Environmental Costs (Note 4) 83 84
Capital Lease Obligations 50 50
Other 76 65
------------- ----------------
Total Other Long-Term Liabilities 566 543
------------- ----------------
CURRENT LIABILITIES
Long-Term Debt due within one year 200 100
Commercial Paper and Loans 571 850
Accounts Payable 382 565
Accounts Payable - Associated Companies 170 46
Accrued Taxes 108 30
Other 365 223
------------- ----------------
Total Current Liabilities 1,796 1,814
------------- ----------------
DEFERRED CREDITS
Income Taxes 2,474 2,533
Investment Tax Credits 310 313
Other 230 198
------------- ----------------
Total Deferred Credits 3,014 3,044
------------- ----------------
COMMITMENTS AND CONTINGENT LIABILITIES (Note 4) - -
------------- ----------------
TOTAL $ 14,437 $ 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)
<CAPTION>
For the Quarters Ended
March 31,
-----------------------
1999 1998
--------- ----------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 172 $ 157
Adjustments to reconcile net income to net cash flows from
operating activities:
Depreciation and Amortization 165 152
Recovery of Electric Energy and Gas Costs - net 89 28
Provision for Deferred Income Taxes - net (59) (1)
Changes in certain current assets and liabilities:
Net change in Accounts Receivable and Unbilled Revenues (62) 38
Net change in Inventory - Fuel and Materials and Supplies 116 136
Net change in Accounts Payable (59) (13)
Net change in Accrued Taxes 78 82
Net change in Other Current Assets and Liabilities 165 28
Other 7 26
--------- ----------
Net Cash Provided By Operating Activities 612 633
--------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Utility Plant, excluding AFDC (79) (81)
Contribution to Decommissioning Funds and Other Special Funds (12) (29)
Other 10 (7)
--------- ----------
Net Cash Used In Investing Activities (81) (117)
--------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Net change in Short-Term Debt (279) (284)
Redemption of Long-Term Debt - (104)
Cash Dividends Paid (277) (127)
Other (2) -
--------- ----------
Net Cash Used In Financing Activities (558) (515)
--------- ----------
Net Change In Cash And Cash Equivalents (27) 1
Cash And Cash Equivalents At Beginning Of Period 42 17
--------- ----------
Cash And Cash Equivalents At End of Period $ 15 $ 18
========= ==========
Income Taxes Paid $ 1 $ 28
Interest Paid $ 98 $ 105
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
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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 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. These Notes
update and supplement matters discussed in the 1998 Annual Report on Form 10-K.
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 January 1, 1999, Public Service Enterprise Group Incorporated
(PSEG) and Public Service Electric and Gas Company (PSE&G) adopted Emerging
Issues Task Force (EITF) Issue No. 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 and 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 and 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 and net cash flows of
PSEG or PSE&G.
Note 2. Regulatory Issues
New Jersey Energy Master Plan Proceedings and Summary Order
In 1998 and continuing into 1999, energy industry restructuring continued
to advance in New Jersey. In 1998, evidentiary hearings related to PSE&G's
proposal in connection with the New Jersey Board of Public Utilities' (BPU) New
Jersey Energy Master Plan (Energy Master Plan) were completed and the Office of
Administrative Law filed its decision providing recommendations on such proposal
to the BPU. In January 1999, the State Legislature passed the New Jersey
Electric Discount and Competition Act (Energy Competition Act) which was signed
into law by the Governor on February 9, 1999. Among other things, the Energy
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Competition Act provides 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 suppliers commencing December 31,
1999, thus fully opening the New Jersey energy markets to customer choice and
competition.
The Energy Competition Act provides the BPU requisite authority to
implement certain aspects of retail electric and gas competition in New Jersey.
The BPU is currently engaged in proceedings to implement the Energy Competition
Act, the result of which will fundamentally change the electric and gas
industries in New Jersey by, among other things, introducing retail competition
to replace the monopoly structure of regulated public utilities, potentially
requiring or resulting in the separation or sale of utilities' electric
generation-related assets and establishing a number of generic rules related to
deregulation, including governing regulated utilities' relationships with their
affiliates.
Under the Energy Competition Act, the distribution business will remain
regulated by the BPU. The transmission business will remain regulated by the
Federal Energy Regulatory Commission (FERC). With deregulation, electric
generation will become a competitive business. Succeeding as a competitive
generator will depend on many factors such as fuel cost, production costs
including labor cost, environmental constraints and related expenses,
transmission availability and rates, marketing ability and quality of service,
among others. The final outcome of these proceedings will have a profound effect
on PSEG and PSE&G.
A proposed amendment to the Energy Competition Act was introduced on March
22, 1999 under which the BPU would be required to establish power emission
standards that every seller of energy in New Jersey would have to meet.
Investment in energy efficiency projects and renewable energy would also be
mandated if this bill were to be passed into law. PSEG and PSE&G cannot predict
the outcome of this matter or its potential impacts.
On February 11, 1999, the BPU adopted a schedule for the resolution of each
New Jersey electric utility's filings for rate unbundling, stranded cost and
restructuring proceedings pursuant to the Energy Competition Act. With respect
to PSE&G, the BPU encouraged the parties to the case to undertake discussions in
an attempt to reach consensus on the litigated issues in the rate unbundling,
stranded cost and, on limited issues, the restructuring proceedings. On March
17, 1999, PSE&G, together with seven other parties, filed a proposed stipulation
(PSE&G Stipulation) with regard to these proceedings with the BPU. On March 29,
1999, the Office of the Ratepayer Advocate, together with certain other parties,
filed their proposal with regard to these proceedings. On April 7, 1999, PSE&G
filed its response to the Ratepayer Advocate's proposal. On April 21, 1999, the
BPU rendered its oral and written summary decision regarding Energy Master Plan
matters (Summary Order), but indicated that it would issue a more detailed
Decision and Order (Decision and Order) in these matters in the near future
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 the related BPU proceedings are hereinafter referred to as the Energy Master
Plan Proceedings.
The Summary Order adopted the PSE&G Stipulation with the specific
modifications and clarifications as set forth below:
Transition Period
PSE&G's Proposed Stipulation as Adopted:
o A four-year transition period will begin August 1, 1999 and end July
31, 2003. During this transition period, rates will be capped for all
customers who remain with PSE&G.
<PAGE>
Rate Reductions
PSE&G's Proposed Stipulation:
o Customers would receive the following reductions from current rates
through July 2003 according to this schedule:
August 1, 1999: 5%
January 1, 2000: increasing to 7%, depending on timing of
securitization
August 1, 2001: increasing to 8.25%
August 1, 2002: increasing to 13.9% average (10% off rates in
effect in April 1997)
All rate reductions after the initial 5% reduction would be contingent
on PSE&G's implementing a BPU order providing for securitization of
$2.475 billion of generation-related stranded costs, plus transaction
costs, and establishing a securitization bond charge under the Energy
Competition Act.
BPU Modifications:
o Customers are to receive rate reductions of:
August 1, 1999: 5%
January 1, 2000: 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 rejected PSE&G's request that all further rate reductions
beyond the initial 5% be conditioned upon securitization. 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, but found however, that the final aggregate rate
reduction in 2002 of 13.9% is required by the legislation and is not
contingent on the implementation of securitization.
Shopping Credits
PSE&G's Proposed Stipulation as Adopted:
o Shopping credits will be established for four years and will include
cost of energy, capacity, transmission, ancillary services, losses,
taxes and a retail adder. The average overall annual 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
PSE&G's Proposed Stipulation:
o Generation-related stranded costs would be established at $3.3
billion, net of tax, of which $2.475 billion plus transaction costs of
up to $125 million would be securitized. As a result of negotiation,
PSE&G would reduce the unsecuritized portion by $225 million. PSE&G
would then have the opportunity to recover the remaining $600 million,
net of tax, over the four-year transition period. The $600 million
would be recovered by various means, including an explicit market
transition charge (MTC). There would be a reconciliation mechanism to
insure that PSE&G does not recover more than $600 million, net of tax.
BPU Modifications:
o The BPU concluded that PSE&G should be provided the opportunity to
recover up to $2.94 billion net of tax stranded costs, through
securitization of $2.4 billion and an opportunity to recover up to
$540 million of its unsecuritized generation-related stranded costs on
present value basis net of tax. The stranded costs recovery is subject
to a true up on the collection of the unsecuritized generation-related
stranded costs.
Additionally, PSE&G cannot use the overrecovery in the Electric
Levelized Energy Adjustment Clause (LEAC) as of July 31, 1999, expected
to be approximately $60 million, net of tax, as a mitigation tool.
Instead, PSE&G must return the overrecovery amount to ratepayers by
applying the overrecovery as a credit to the starting deferred balance
of the non-utility generation market transition clause (NTC) to offset
stranded costs otherwise recoverable from ratepayers.
Securitization
PSE&G's Proposed Stipulation:
o PSE&G would be allowed to issue a total of up to $2.6 billion of
transition bonds to be amortized over a 15-year period. A transition
bond charge would be collected from customers via a per kWh or wires
charge. This would be trued-up at least annually. Net proceeds from
this securitization of stranded costs would be used to refinance or
retire debt and/or equity. The resulting savings from this bond
financing must be returned to customers.
BPU Modifications:
o The BPU will issue a financing order, consistent with the provisions
of the Energy Competition Act, to authorize PSE&G to issue up to
$2.525 billion of transition bonds representing $2.4 billion of net of
tax generation-related stranded costs and an estimated $125 million of
transaction costs. 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 legitimate
recoverable stranded costs, however they should not be collected
through the transition bond charge; rather, such taxes shall be
collected via a separate MTC. The duration of this separate MTC shall
be 15 years, identical to the duration of the transition bond charge.
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.
Transfer of Generation-Related Assets
PSE&G's Proposed Stipulation:
o PSE&G would be required to separate its transmission and distribution
assets from its generation-related assets. Its generation-related
assets would be transferred to a separate generation company (Genco)
to be owned by PSE&G's parent holding company, PSEG. Given the
resolution of stranded costs, the proposed transfer price of $2.368
billion was intended to ensure that PSE&G receives full and fair
recompense for these assets. Genco would become an exempt wholesale
generator (EWG) upon receipt of FERC approval. If the
generation-related assets are sold to a third party during the
four-year transition period, any gains would be shared equally between
customers and shareholders, subject to BPU approval.
BPU Modifications:
o The BPU directed the establishment of a separate company (i.e., Genco)
by PSEG to sell generation output in the wholesale marketplace and
also ordered PSE&G to transfer its generation-related assets to such
separate unregulated subsidiary at a price of $2.443 billion. Any
gains resulting from the sale of the transferred generation-related
assets to a third party which occurs within five years of August 1,
1999, rather than within the four years proposed in the PSE&G
stipulation, will be shared 50 - 50 between ratepayers and
shareholders.
Basic Generation Service
PSE&G's Proposed Stipulation:
o Through a contract with Genco, PSE&G would provide basic generation
service (BGS) for the first three years and would not promote it as a
competitive alternative. BGS would be competitively bid for the fourth
year and annually thereafter.
BPU Modifications:
o The BPU approved PSE&G's proposal on basic generation, but clarified
that any payments to PSE&G resulting from BGS being bid out for year 4
of the transition period shall be credited to the deferred societal
benefit costs (SBC) balance for purposes of establishing the SBC rate
in year 5, and shall in no event be retained by PSE&G or remitted to
Genco or otherwise utilized to recover unsecuritized
generation-related stranded costs.
Electric Distribution Depreciation
PSE&G's Proposed Stipulation as Adopted:
o PSE&G is required to reduce its depreciation reserve for its
distribution assets by $568.7 million which will be achieved by
amortizing its excess electric distribution depreciation reserve over
the period of January 1, 2000 to July 31, 2003.
Societal Benefit and Other Costs
PSE&G's Proposed Stipulation as Adopted:
o SBC and above market stranded costs associated with non-utility
generation will be collected through clause mechanisms; SBC level will
remain constant through the transition period; deferred accounting,
including interest on any over/underrecoveries, will be used; and the
clauses will be reset annually thereafter. The clause mechanism for
the above market 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 non- utility generator (NUG) contract
buyouts will also be charged to the NTC clause and be subject to
deferred accounting. The clause mechanism for societal benefits will
include costs related to: 1) social programs which include the
universal service fund; 2) nuclear plant decommissioning; 3) demand
side management (DSM) program; 4) manufactured gas plant remediation
and 5) consumer education.
Upon the issuance of the Decision and Order, PSE&G will no longer meet 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. Pending the BPU's final written
order, PSE&G anticipates that it will be required to record a net extraordinary
charge to earnings, in the range of $500 million to $700 million, in the second
quarter of 1999 to reflect its unrecoverable costs.
Pending issuance of the Decision and Order, PSEG and PSE&G cannot determine
the applicability and impact of other regulatory and/or legal requirements which
may also be triggered by the implementation of the Decision and Order. These may
include actions in the areas of corporate finance, tax, environmental and
nuclear. PSEG and PSE&G cannot predict whether any appeals will be filed with
respect to the Decision and Order, once issued, within the applicable time
period.
Additionally, the BPU is expected to issue a series of orders that will
decide generic issues related to deregulation of the electric and gas industry
in the State. 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 these proposed standards were held during April
1999 and an order is expected in the second quarter of 1999.
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 public 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 pursuant to the Energy
Competition Act.
o A proposed regulatory asset charge, if applicable.
o A proposed transportation rate.
On April 30, 1999, PSE&G filed its gas unbundling compliance filing with
the BPU as required by the BPU's March 17, 1999 Order. As required, this filing
continues and 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. PSE&G cannot
predict the outcome of this proceeding.
Hearings are expected in September 1999 with the BPU expected to render a
decision by the end of November 1999. The Energy Competition Act also applies
similar rules to the gas industry as to the electric industry addressing
affiliate relations, consumer protections, among others.
Unbundled Gas Transportation Tariffs
On December 22, 1998, PSE&G, the BPU and the Office of the Ratepayer
Advocate executed an Interim Stipulation for Phase I of PSE&G's Residential Gas
Transportation Program (Program). In accordance with the Interim Stipulation,
residential customers would not be eligible to register (sign up) for the
Program until 60 days after the BPU's Decision and Order. The Interim
Stipulation mandates that residential customers who return to PSE&G's bundled
sales service after a designated period would be served gas which is
market-priced under PSE&G's Market Price Gas Service (MPGS) tariff. On April 28,
1999, the BPU made the Interim Stipulation final.
<PAGE>
Electric Levelized Energy Adjustment Clause (LEAC)
To the extent fuel revenue and expense flow through the LEAC mechanism,
variances in fuel revenues and expenses offset and thus have no direct effect on
earnings. Once the LEAC mechanism is eliminated when the transition period
commences on August 1, 1999, earnings volatility may increase since the
unregulated generation portion of PSEG's business will bear the full risks and
rewards of changes in nuclear and fossil generating fuel costs and replacement
power costs. For further discussion, see New Jersey Energy Master Plan
Proceedings and Summary Order above and Note 3. Regulatory Assets and
Liabilities.
Other Regulatory Issues
Interim Competitive Transition Charge (ICTC)
In September 1996, PSE&G filed a petition with the BPU to establish an
ICTC, or exit fee, which would be designed to recover stranded costs which would
result from a customer leaving PSE&G's system as a full requirements customer.
The Energy Competition Act does not require that on-site generators pay any fees
equivalent to the SBC or recovery of utility stranded costs (market transition
charge or transition bond charges) provided that the energy load served by the
on-site generators does not reduce the utility's distributed kilowatt hours
below 92.5% of the kilowatt hours distributed by the utility in 1999. If that
trigger is exceeded, then on-site generators will pay such charges. On March 31,
1999, the BPU issued an Order of Dismissal regarding the issue of exit fees
since the language incorporated into the Energy Competition Act established the
procedures necessary to assess an exit fee. This Order dismissed the petition of
PSE&G and related outstanding motions. This Order also closes the BPU's generic
exit fee proceeding and all motions related thereto.
Note 3. 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 will be charged or
credited to income. Once the BPU issues its written Decision and Order in the
Energy Master Plan Proceedings, PSE&G will no longer meet the requirements for
application of SFAS 71 for its then deregulated operations. For discussion of
the Energy Master Plan Proceedings, see Note 2. Regulatory Issues. It is
expected that the existing regulatory assets will continue in the regulated
portion of PSE&G's business and will continue to be subject to SFAS 71, except
as follows:
o the SFAS 109, "Accounting for Income Taxes," deferred tax assets will
be written down to the extent they relate to generation-related
stranded costs;
o unamortized debt expense and loss on reacquired debt may be affected
to the extent the debt related to such amounts is retired; and
o the LEAC will be discontinued as discussed below.
Overrecovered Electric Energy Costs/Under(over)recovered Gas Costs: PSE&G
will continue to follow deferred accounting treatment for the LEAC through July
31, 1999. Per the Summary Order, the overrecovered balance as of that date,
expected to be approximately $100 million ($60 million net of tax), will be
applied as a credit to the starting deferred balance of the NTC to offset
stranded costs otherwise recoverable from ratepayers.
March 31, December 31,
----------------------------------
1999 1998
-------------- --------------
Under(over)recovered Gas Costs $(14) $35
Overrecovered Electric Energy Costs (80) (39)
Note 4. 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 the Salem Nuclear Generating Station Units
1 and 2 (Salem) and the Peach Bottom Atomic Power Station Units 2 and 3 (Peach
Bottom), 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) 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
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 from 1997 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. $5 million was incurred in the
quarter ended March 31, 1999. 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.
The schedule to replace certain systems was accelerated for Year 2000
purposes. Analysis of these systems is continuing and costs identified to date
are approximately $5 million, which are not included in the estimates above.
Additionally, PSE&G is continuing its installation of 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 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.
If PSEG, PSE&G, their domestic and international subsidiaries, other
members of the PJM Interconnection, L.L.C. (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 and net cash flows.
Construction and Fuel Supplies
PSE&G has substantial commitments as part of its ongoing construction
program, which include capital requirements for nuclear fuel. 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. The outcome of the Energy Master
Plan Proceedings and the use of alternative sources of generation may impact
PSE&G's construction program.
PSE&G's construction expenditures are expected to aggregate approximately
$2.8 billion during the years 1999 through 2003. The estimate of construction
requirements is based on expected project completion dates and includes
anticipated escalation due to inflation of approximately 3% annually. Therefore,
construction delays or higher inflation levels could cause significant increases
in these amounts. The Summary Order has directed that PSE&G's generation-related
assets be separated from its transmission and distribution assets. The breakdown
of anticipated construction expenditures between these businesses has yet to be
determined. For discussion of the Energy Master Plan Proceedings and their
potential impacts, see Note 2. Regulatory Issues.
PSE&G does not presently anticipate any difficulties in obtaining sufficient
fuel for electric generation or adequate gas supplies during the years 1999
through 2003.
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, the
extent of the contamination and the nature of required remedial and restoration
actions.
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 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 and 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 extant 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 and net cash flows. The Energy
Competition Act provides for the continuation of RAC programs. The Summary Order
provides for the recovery of costs for RAC is to be 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
utility 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, indicating sufficient allowances through 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. 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. PSE&G's present analysis
leads it to believe that 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 CERCLA
and that, to date, at least thirteen corporations may be potentially liable for
performing required remedial actions to address potential environmental
pollution at the facility. The EPA anticipates identifying other potentially
responsible parties (PRP). 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. The Cooperating Party has reported that it has incurred approximately $35
million to date in connection with the implementation of required remedial
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.
Note 5. 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.
Commodity Instruments--PSE&G
At March 31, 1999 and December 31, 1998, PSE&G held or issued 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
currently has levelized energy adjustment clauses, LEAC and LGAC, in place for
both electricity and natural gas pursuant to BPU orders. For discussion of the
LEAC and the LGAC and their current and proposed status under the Energy Master
Plan Proceedings, see Note 2. Regulatory Issues and Note 3. Regulatory Assets
and Liabilities. These clauses were established to minimize the impact of major
commodity price swings on energy cost to customers. PSE&G uses futures,
forwards, swaps and options to manage and hedge price risk related to these
market exposures.
At March 31, 1999, PSE&G had outstanding commodity financial instruments
with a notional contract quantity of 0.7 million megawatt-hours (MWH) of
electricity and 67.9 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. In 1998 and prior, such
gains and losses were recorded upon settlement of the contracts. PSE&G recorded
$11 million and $5 million of gains in the quarters ended March 31, 1999 and
1998, respectively.
Natural Gas Hedging--PSEG Energy Holdings Inc. (Energy Holdings)
As of March 31, 1999 and December 31, 1998, PSEG Energy Technologies Inc.
(Energy Technologies), a wholly-owned subsidiary of Energy Holdings, had
outstanding futures contracts to buy natural gas related to fixed-price natural
gas sales commitments. Such contracts hedged approximately 91% and 90% of its
fixed price sales commitments at March 31, 1999 and December 31, 1998,
respectively. As of March 31, 1999 and December 31, 1998, Energy Technologies
had a net unrealized hedge loss of approximately $1 million and $5 million,
respectively.
Foreign Currencies--Energy Holdings
PSEG Global Inc. (Global), a wholly-owned subsidiary of Energy Holdings,
had consolidated non-recourse debt of $119 million as of March 31, 1999 which is
denominated in the Brazilian Real that is indexed to a basket of currencies
including U.S. dollars. As a result, it is subject to foreign currency exchange
rate risk due to the effect of exchange rate movements between the indexed
foreign currencies and the Brazilian Real and between the Brazilian Real and the
U.S. Dollar. Exchange rate changes ultimately impact the debt level outstanding
in the denominated currency and result in foreign currency transactions in
accordance with current accounting guidance. Any related transaction gains
(losses) resulting from such exchange rate changes are included in determining
net income for the period and amounted to a $4 million gain in each of the
quarters ended March 31, 1999 and 1998.
In January 1999, Brazil abandoned its managed devaluation strategy and
allowed its currency, the Real, to float against other currencies. As of March
31, 1999, the Real has devalued approximately 30% against the U.S. dollar since
December 31, 1998 resulting in a charge of $164 million to cumulative foreign
currency translation adjustment (a separate component of stockholders' equity).
Net foreign currency devaluations, caused primarily by the Brazilian Real, have
reduced Global's total assets by $168 million as of March 31, 1999 with an
offsetting charge to cumulative foreign currency translation adjustment. PSEG
cannot predict to what extent, if any, further devaluation may occur, and,
therefore, cannot predict the impact of potential devaluation of currencies on
PSEG's results of operations, financial condition and net cash flows. However,
assuming no further significant devaluation, PSEG does not expect this to have a
material adverse effect on its 1999 results of operations, financial condition
or net cash flows. For additional information, see Note 7. Financial Information
by Business Segments of Notes.
As PSEG increases its international investments, the financial statements
of PSEG will be increasingly affected by changes in the global economy.
Nuclear Decommissioning Trust Funds
Contributions made to the Nuclear Decommissioning Trust Funds are invested
in debt and equity securities. The carrying value of these funds of $539 million
and $524 million approximates the fair market value as of March 31, 1999 and
December 31, 1998, respectively.
Equity Securities--Energy Holdings
PSEG Resources Inc. (Resources), a wholly-owned subsidiary of Energy
Holdings, has investments in equity securities and partnerships, in which
Resources is a limited partner, which invest 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 market prices of the underlying securities. Fair
value is determined by adjusting the market value of the securities for
liquidation and market volatility factors, where appropriate. The aggregate
amount of such investments which have available market prices at March 31, 1999
and December 31, 1998 was $223 million and $204 million, respectively. The
portfolio has exposure to market price risk. As such, 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
$18 million at March 31, 1999 and $17 million at December 31, 1998.
Note 6. Income Taxes
PSEG's effective income tax rate is as follows:
Quarter Ended
March 31,
-----------------------
1999 1998
---------- ---------
Federal tax provision at statutory rate 35.0% 35.0%
New Jersey Corporate Business Tax, net of Federal 5.9% 5.9%
benefit
Other-- net 2.1% 0.2%
---------- ---------
Effective Income Tax Rate 43.0% 41.1%
========== =========
<PAGE>
Note 7. 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. With the transition into a deregulated environment, it is
likely that this basis of segment reporting will change.
Information related to the segments of PSEG's business is detailed below:
<TABLE>
<CAPTION>
Other
Non-utility Consolidated
(Millions of Dollars) Electric Gas Resources Activities (A) Total
-----------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
For the Quarter Ended March 31, 1999:
Total Operating Revenues.................. $966 $700 $46 $83 $1,795
Segment Net Income (Loss)................. $105 $67 $19 $(3) $188
=========== ========== =========== ============ ==========
For the Quarter Ended March 31, 1998:
Total Operating Revenues.................. $902 $612 $70 $75 $1,659
Segment Net Income (Loss)................. $109 $48 $36 $(2) $191
=========== ========== =========== ============ ==========
As of March 31, 1999:
Total Assets.............................. $11,997 $2,440 $1,833 $1,380 $17,650
As of December 31, 1998:
Total Assets.............................. $12,200 $2,469 $1,809 $1,519 $17,997
<FN>
(A) Other Non-utility Activities include amounts applicable to PSEG, the
parent corporation, and Energy Holdings, excluding Resources.
</FN>
</TABLE>
Geographic information for PSEG is disclosed below. PSE&G does not have foreign
investments or operations.
<TABLE>
<CAPTION>
Revenues (1) Identifiable Assets
Quarter ended March 31, March 31, December 31,
------------------------------- ---------------------------------
1999 1998 1999 1998
------------- -------------- -------------- --------------
<S> <C> <C> <C> <C>
United States $1,768 $1,635 $16,169 $16,387
Foreign Countries (2) 27 24 1,481 1,610
--------- --------- ---------- -------
Total $1,795 $1,659 $17,650 $17,997
========= ========= ========== =======
Identifiable investments in Foreign Countries include amounts from:
Argentina $309 $307
Brazil (3) $338 $482
Netherlands $404 $400
- ---------------------------------------------------------------------------------------------------------------
<FN>
(1) Revenues are attributed to countries based on the locations of the
investments.
(2) Total assets are net of foreign currency translation adjustment of
$(168) million as of March 31, 1999 and $(43) million as of December
31, 1998.
(3) Amount is net of foreign currency translation adjustment of $(164)
million as of March 31, 1999 and $(39) million as of December 31,
1998.
</FN>
</TABLE>
<PAGE>
Note 8. Accounting Matters
In June 1998, the FASB issued SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities" (SFAS 133), which is effective for financial
statements for all fiscal quarters of fiscal years beginning after June 15,
1999. SFAS 133 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 9. Comprehensive Income
<TABLE>
<CAPTION>
Comprehensive Income, Net of Tax:
Three Months Ended
March 31,
-----------------------------
1999 1998
----------- ------------
(Millions of Dollars)
<S> <C> <C>
Net income.......................................... $188 $191
Foreign currency translation, net of tax of $(14) and
$(1) for 1999 and 1998, respectively ............... (125) (6)
----------- ------------
Comprehensive income................................ $63 $185
=========== ============
</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. Regulatory Assets and Liabilities
Note 4. Commitments and Contingent Liabilities
Note 5. Financial Instruments and Risk Management
Note 7. Financial Information by Business Segments
Note 8. Accounting Matters
Note 6. Income Taxes
PSE&G's effective income tax rate is as follows:
<TABLE>
<CAPTION>
Quarter Ended
March 31,
-----------------------
1999 1998
--------- ---------
<S> <C> <C>
Federal tax provision at statutory rate......................... 35.0% 35.0%
New Jersey Corporate Business Tax, net of Federal benefit....... 5.9% 5.9%
Other-- net..................................................... 2.9% 1.8%
--------- ---------
Effective Income Tax Rate................................... 43.8% 42.7%
========= =========
</TABLE>
Note 9. Comprehensive Income
Effective January 1, 1998, PSE&G adopted SFAS 130, "Reporting Comprehensive
Income," which requires companies to report all changes in equity during a
period, except those resulting from investment by and distribution to owners, in
a financial statement for the period in which the changes are recognized. For
the quarters ended March 31, 1999 and 1998, PSE&G's comprehensive income equaled
the consolidated net income 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 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
On February 9, 1999, the New Jersey Electric Discount and Energy
Competition Act (Energy Competition Act) was enacted. It provides 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 fully opening the New Jersey energy
markets to competition.
The New Jersey Board of Public Utilities (BPU) has been conducting related
proceedings pursuant to the New Jersey Energy Master Plan (Energy Master Plan).
On April 21, 1999 the BPU issued a Summary Order (Summary Order) which adopted
PSE&G's previously filed proposed stipulation (PSE&G Stipulation) with certain
modifications and clarifications (see Note 2. Regulatory Issues of Notes).
In its Summary Order, the BPU indicated that it would issue a more detailed
Decision and Order (Decision and Order) in these matters in the near future.
Once such order is provided, PSE&G will discontinue application 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 and will record the appropriate accounting entries at that time.
Pending the BPU's final written order, PSE&G anticipates that it will be
required to record a net extraordinary charge to earnings in the range of $500
million to $700 million, in the second quarter of 1999 to reflect its
unrecoverable costs. It is also anticipated that the BPU will issue additional
rulings on generic issues for the industry (e.g., affiliate standards) as well
as matters specific to PSE&G (e.g., a financing order to implement
securitization). For further discussion of the aforementioned BPU activities,
the Energy Competition Act and the Summary Order (the Energy Master Plan
Proceedings) as well as the gas unbundling proceedings, see Note 2. Regulatory
Issues of Notes.
These decisions will fundamentally change the energy industry in New Jersey
and will result in competitive markets for electric and gas supply and for
customer services while the transmission and distribution businesses will remain
regulated. As set forth in the Summary Order, PSE&G will transfer its
generation-related assets to a separate generation company (i.e., Genco) which
will be owned by PSEG. In addition to the approval received from the BPU, Genco
will need approvals from a number of other regulators, including the Federal
Energy Regulatory Commission (FERC) (to be recognized as an exempt wholesale
generator (EWG)) and the Nuclear Regulatory Commission (NRC) (to transfer its
licenses) and will have to resolve a number of other issues related to taxes,
environmental restrictions and PSE&G's Mortgage Indenture (see Liquidity and
Capital Resources and Note 2. Regulatory Issues of Notes). PSEG and PSE&G cannot
determine the applicability and impact of other regulatory and/or legal
requirements, which may also be triggered by the implementation of the Decision
and Order.
As set forth in the Summary Order, Genco will provide PSE&G with the energy
required to meet its basic generation service (BGS) obligation. Genco will
provide BGS at the contracted rate for the first three years of the transition
period. BGS will be competitively bid for the fourth year and annually
thereafter. To the extent Genco produces less energy than required under the BGS
contract with PSE&G, Genco's earnings will be exposed to the risks of the
competitive market for the difference between the market rate for energy and the
BGS contract rate (see PJM Interconnection, L.L.C. (PJM)).
PSEG has been engaged in the competitive energy business for a number of
years through certain of its non-utility subsidiaries. Due to the regulatory
changes outlined above, in the future, competitive businesses will constitute a
larger portion of PSEG's activities. 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 will
increase. The pending regulatory decisions and the business experience PSEG has
acquired in operating non-regulated energy business will be significant
components in determining future success.
PSEG and PSE&G believe that the final outcome of the Energy Master Plan
Proceedings will involve a fundamental change in the way their businesses are
conducted. These changes may impact financial operating trends and could result
in earnings volatility, write down of asset values, reduction in dividend
payments and adverse impacts on revenues due to the mandated electric rate cut,
electric and gas retail choice and fuel and energy price risks. However, based
on its analysis of the Summary Order, PSEG believes that its dividend payments
can be maintained at their current level. Additionally, PSE&G is actively
seeking regulatory and operational changes that will allow it to provide energy
services in a safe and reliable manner at competitive prices while achieving
strong financial performance.
Many forces are reshaping how the utility industry meets the needs and
expectations of its customers and shareholders. Profound changes in the way the
industry is regulated are affecting how PSEG conducts business and its financial
prospects in the future. Competitive changes in the utility industry continued
to occur in 1998 and will continue to occur in 1999.
Going forward, PSEG will continue to pursue its strategies to grow its
family of businesses. As previously reported, more emphasis will be placed on
finding opportunities for expansion outside of its traditional utility services
and markets. PSEG's unregulated generation business strategy is to size its
fleet to take advantage of market opportunities, while seeking to increase its
value and manage commodity price risk through its wholesale trading activity.
PSEG will also consider opportunities for expansion through business
combinations. PSE&G's transmission and distribution strategy, both gas and
electric, is to provide cost-effective, high quality service. PSEG Global Inc.'s
(Global) strategy is to invest in both generation and distribution facilities
worldwide with the goal of creating long-term value. PSEG Resources Inc.'s
(Resources) strategy is to continue focusing on passive investments in the
energy sector worldwide seeking to provide earnings and economic value. PSEG
Energy Technologies Inc.'s (Energy Technologies) strategy is to expand upon the
current energy related services it provides to industrial and commercial
customers to create long-term value and to participate in the retail energy
marketplace.
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 1999 and beyond and that past
results are not necessarily an indication of future business prospects or
financial results.
Results of Operations
Basic and diluted earnings per share of PSEG common stock (Common Stock)
were $0.85 for the quarter ended March 31, 1999, representing an increase of
$0.03 or 4% per share from the comparable 1998 period.
PSE&G's contribution to earnings per share of Common Stock for the quarter
ended March 31, 1999 increased $0.06 from the comparable 1998 period. The
increase for the quarter ended March 31, 1999 was primarily due to increased
sales of gas and electricity resulting from considerably colder weather in the
first 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 first quarter of 1998.
PSEG Energy Holdings Inc.'s (Energy Holdings) contribution to earnings per
share of Common Stock for the quarter ended March 31, 1999 decreased $0.07 from
the comparable 1998 period, primarily due to lower income from Resources'
financial investment portfolio in the first quarter of 1999.
As a result of PSEG's stock repurchase program which began in September
1998, earnings per share of Common Stock for the quarter ended March 31, 1999
increased $0.04 from the comparable 1998 period. A total of 11.3 million shares
were repurchased at a cost of $442 million under this program as of March 31,
1999.
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 have no direct effect on earnings. These
include base fuel revenues, demand side management (DSM) revenue and Remediation
Adjustment Charge (RAC) revenue. In 1999, the LEAC mechanism will be eliminated
as a result of the Energy Master Plan Proceedings. This may 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 3. Regulatory Assets and Liabilities of Notes for a
discussion of LEAC, LGAC, RAC and DSM and their current and proposed status
under the Energy Master Plan Proceedings.
Electric
Revenues increased $64 million or 7% for the quarter ended March 31, 1999
from the comparable period in 1998 primarily due to higher sales resulting from
colder weather in the first quarter of 1999 augmented by positive economic
factors in New Jersey as well as profits realized from wholesale energy
activities. Additionally, DSM revenues were higher in the quarter ended March
31, 1999 than in the comparable 1998 period.
Gas
Revenues increased $88 million or 14% for the quarter ended March 31, 1999
from the comparable period in 1998. The increase was primarily due to colder
weather in the first quarter of 1999. Additionally, DSM revenues were higher in
the quarter ended March 31, 1999 than in the comparable 1998 period.
PSE&G -- Expenses
Net Interchanged Power and Fuel for Electric Generation
Net Interchanged Power and Fuel for Electric Generation increased $5
million or 2% for the quarter ended March 31, 1999 from the comparable 1998
period primarily due to increased sales of electricity resulting in increased
purchases of fuel for electric generation and purchases of power from the PJM
Interconnection, L.L.C. (PJM) pool.
As previously reported, during the summer of 1998, the eastern electricity
commodity markets experienced severe volatility resulting from extremely hot
weather and electric capacity and energy shortages in the Midwest. PSE&G cannot
predict whether similar events leading to extreme price movements will occur
again. Given the impending 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 megawatt hour (see Competitive Environment), the absence of a PJM
price cap in situations involving emergency purchases and the potential for
plant outages, extreme price movements could occur which could have a material
impact on PSEG's financial condition, results of operations and net cash flows.
For a discussion of market risks, see Item 3. Qualitative and Quantitative
Disclosures About Market Risk.
<PAGE>
Gas Purchased
Gas Purchased increased $33 million or 8% for the quarter ended March 31,
1999 from the comparable 1998 period primarily due to increased sales of gas
resulting from colder weather in the first quarter of 1999.
Operation and Maintenance
Operation and Maintenance expense increased $71 million or 22% for the
quarter ended March 31, 1999 from the comparable 1998 period. 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 Employment Benefits (OPEB) costs were incurred in the quarter ended
March 31, 1999 than in the comparable 1998 period. Also, in the quarter ended
March 31, 1999, there was higher DSM recovery resulting in a greater recognition
of previously deferred expenses. These increases were partially offset by lower
nuclear operation and maintenance costs in 1999 due to restart expenses in 1998
for Salem.
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.
Income Taxes
Income Taxes increased $18 million or 16% for the quarter ended March 31,
1999 from the comparable 1998 period. This increase is primarily due to higher
pre-tax operating income.
Year 2000 Expenses -- PSEG and PSE&G
For a discussion of Year 2000 expenses, see Note 4. Commitments and
Contingent Liabilities of Notes and Year 2000 Readiness Disclosure, below.
Energy Holdings -- Earnings/(Losses)
Increase (Decrease)
----------------------
Quarter Ended
March 31,
1999 vs. 1998
----------------------
(Millions of Dollars)
PSEG Resources Inc. (Resources) $ (18)
PSEG Global Inc. (Global) --
PSEG Energy Technologies Inc. (Energy Technologies) 1
Enterprise Group Development Corporation --
------------
Total $ (17)
============
Energy Holdings had net earnings of $19 million for the quarter ended March
31, 1999 compared to net earnings of $36 million for the same period in 1998,
representing a decrease of $17 million. Energy Holdings' earnings were primarily
those of Resources. The decrease in Energy Holdings' earnings was primarily due
to Resources' lower income in the quarter ended March 31, 1999 as compared to
the quarter ended March 31, 1998 due to less income from investments in
leveraged buyout funds and limited partnerships in 1999, primarily due to the
sale of securities in the prior year, and lower realized gains in the first
quarter of 1999 resulting from the exercise of an early buyout option by the
lessee in a leveraged lease in the first quarter of 1998. The decrease was
partially offset by income in the quarter ended March 31, 1999 from several
leveraged leases entered into subsequent to March 31, 1998.
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 the related corporate structure reorganizations, the capital
structure of PSEG and PSE&G will likely change. The BPU, in its Summary Order,
stated 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 tax and transaction costs). The right of PSE&G to receive the
bondable transition charge pursuant to the securitization transaction is
property subject to the lien of PSE&G's Mortgage Indenture. The proceeds of
securitization will be deposited with the Mortgage Trustee to comply with the
property release provisions of the Mortgage. PSE&G can utilize one or more of
the following, at its option, with respect to these proceeds:
o Withdraw funds for corporate use by utilizing additions and
improvements. These funds could be used to purchase Common Stock, or
purchase, tender or redeem outstanding Mortgage Bonds under existing
applicable optional redemption provisions.
o Direct the Trustee to invest the proceeds in U.S. Government
Securities.
o Direct the Trustee to purchase Mortgage Bonds at the lowest prices
obtainable, not exceeding the lowest amount at which any such Mortgage
Bond then outstanding may then be by its terms redeemable (e.g., at
par or below). If the Trustee is unable so to purchase sufficient
Mortgage Bonds to exhaust such proceeds deposited with it, the balance
may be applied towards the redemption of eligible series of Mortgage
Bonds pro rata at par.
Unless PSE&G affirmatively chooses an option within two years of deposit of
the funds, the Trustee is required to undertake par redemptions. All outstanding
Mortgage Bonds, except for each of the series of Pollution Control Bonds and two
series of coupon Bonds are eligible for such redemption at their par special
redemption price, as provided in the Mortgage Indenture and each respective
Supplemental Indenture.
Generation assets which have been directed by the BPU to be transferred to
a separate unregulated subsidiary of PSEG are also subject to the lien of the
Mortgage Indenture. Proceeds of that sale will likewise be deposited with the
Trustee. PSE&G has the same options with regard to those proceeds as discussed
above in connection with securitization. Transfer of generation assets requires
PSE&G to obtain various additional Federal and State regulatory approvals.
PSE&G has not yet made a decision as to the extent to which it will elect
to redeem such eligible Mortgage Bonds at par. Such decision will be based upon
the final Decision and Order, financial conditions at the time of the decision
and other factors. At March 31, 1999, PSE&G had a total of $4.149 billion of
Mortgage Bonds outstanding, of which $3.354 billion are eligible for special
redemption at par. $780 million of Pollution Control Bonds and $15 million of
coupon Bonds are not eligible for this special redemption.
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.
Genco's capital needs will be dictated by its strategy to size its generation
fleet, but will likely require cash generated from operations and external
financings. Energy Holdings' growth will be funded through external financings
and cash generated from operations. Financing activity at the parent company
level is currently limited to funding PSEG's stock repurchase program on an
interim basis primarily from external financings. However, PSEG periodically
reassesses its financial needs and could make additional equity infusions in its
subsidiaries if investment opportunities are presented.
As previously reported, on September 15, 1998, in anticipation of
securitization of PSE&G's stranded costs afforded by the then proposed Energy
Competition Act, the Board of Directors of PSEG authorized the repurchase of up
to 10 million shares of Common Stock. Under the authorization, repurchases were
made in the open market at the discretion of PSEG. The repurchased shares have
been held as treasury stock. On February 16, 1999, the Board of Directors of
PSEG authorized the expansion of the repurchase program up to an aggregate of 20
million shares under substantially the same terms and conditions as the program
which began in September 1998. At March 31, 1999, PSEG had repurchased
approximately 11.3 million shares of Common Stock at a cost of $442 million,
under these authorizations. As of April 30, 1999, PSEG had repurchased a total
of approximately 12.4 million shares at a cost of approximately $484 million
under this program.
Dividend payments on Common Stock were $0.54 per share and totaled
approximately $120 million and $125 million for the three months ended March 31,
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 outcome of the Energy
Master Plan Proceedings (see Note 2. Regulatory Issues of Notes), 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 $274 million and $125 million to PSEG
during the quarters ended March 31, 1999 and 1998, respectively. These amounts
were used to fund PSEG's Common Stock dividends, and in 1999, to support a
portion of its stock repurchase program. Changes in PSE&G's financial condition
that could result from the Energy Master Plan Proceedings could have a material
adverse effect on PSEG's ability to maintain the dividend at PSEG's current
level. However, based on its analysis of the Summary Order, PSEG believes that
its dividend payments can be maintained at their current level. For discussion
of the Energy Master Plan Proceedings, see Note 2. Regulatory Issues of Notes.
Due to the growth in Energy Holdings investment activities, no dividends on
Energy Holdings' common stock were paid in the quarters ended March 31, 1999 and
1998.
PSEG and PSE&G, respectively, have 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 of March 31, 1999, PSEG's capital structure consisted of 44.0% common
equity, 44.9% long-term debt and 11.1% preferred stock and other preferred
securities.
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 March 31, 1999 were approximately 18% 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 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.
As a result of the final outcome of the Energy Master Plan Proceedings and
accounting impacts resulting from the deregulation of the generation of
electricity and the unbundling of the utility business referenced above,
modifications will be required to certain of the restrictions agreed to by PSEG
with the BPU in response to the Focused Audit. PSEG believes that these issues
will be satisfactorily resolved. For discussion of the Energy Master Plan
Proceedings and potential impacts see Note 2. Regulatory Issues of Notes.
Energy Holdings
As noted above, Global, Resources and Energy Technologies are expected to
provide long-term growth for Energy Holdings and PSEG. Resources' investments
are designed to produce immediate earnings and cash flows, which enable Global
and Energy Technologies to focus on longer-term growth. During the next five
years, Energy Holdings' capital requirements are expected to be provided from
additional debt financing, equity from PSEG and operating cash flows. 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
current energy related services being provided to industrial and commercial
customers.
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 and net cash flows.
As of March 31, 1999 and 1998, Energy Holdings' embedded cost of debt of its
finance subsidiaries was approximately 6.64% and 7.91%, respectively.
Capital Requirements
Capital resources and capital requirements will be affected by the final
outcome of the Energy Master Plan Proceedings. For a discussion of the potential
impact of the Energy Master Plan Proceedings on PSE&G's future prospects,
including financial condition, results of operations and net cash flows, see
Note 2. Regulatory Issues of Notes.
PSEG
Beginning in December 1998, PSEG has entered into contracts to purchase
combustion turbines. PSEG's commitment under these contracts is approximately
$392 million to be expended between December 1998 and December 2001. Through
April 30, 1999, payments of approximately $25 million were made under these
contracts.
PSE&G
For the quarter ended March 31, 1999, PSE&G had utility plant additions,
including Allowance for Funds Used During Construction, of $81 million, a $3
million decrease from the corresponding 1998 period.
Dependent upon the final outcome of the Energy Master Plan Proceedings and
the Decision and Order, 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., Genco) may incur capital requirements based on its
growth strategy. For discussion of the Energy Master Plan Proceedings and their
potential impacts, see Note 2. Regulatory Issues and Note 4. Commitments and
Contingent Liabilities of Notes.
<PAGE>
Energy Holdings
Global
In April 1999, Global, with a partner, entered into an agreement to jointly
acquire 90% of the outstanding shares of Chilquinta S.A. (Chilquinta Energia), a
power generation and distribution company based in Santiago, Chile under a 50/50
partnership. Global will pay $255 million for an approximately 45% interest in
the company which includes holdings of distribution assets in Chile and Peru and
2,100 megawatts of generating capacity in Argentina. Additional acquisition
financing will be provided by $320 million of non-recourse debt. The acquisition
increases PSEG's worldwide customer base by over 1 million customers. Upon final
acquisition, Global and its partner will make a tender offer to acquire the
remaining 10% of Chilquinta Energia shares from other shareholders. The
transaction requires the approval of Chilquinta Energia's shareholders and
regulatory notifications in Chile. Closing is expected to occur in June 1999.
In April 1999, Global and Panda Energy International Inc. entered into a
joint venture agreement to develop a 1,000 megawatt combined-cycle gas plant in
Guadalupe County in Texas. Global's equity investment is expected to be
approximately $48 million, with the total investment by Global not to exceed
$125 million, including loans and guarantees.
Global is currently funding its equity investment in a 200 megawatt
gas-fired generation project in Venezuela. Funding of approximately $70 million
for the construction of the project commenced in December 1998 and will continue
through mid-2000. Upon completion, the project will distribute energy to
approximately forty industrial customers in the northern part of Venezuela.
Resources
As a result of the sale of a security in April 1999, Resources, through its
beneficial interest in the KKR Leveraged Buyout Fund (KKR LBO Fund), realized
proceeds of approximately $59 million and an after tax book gain of
approximately $12 million.
Resources has been advised by KKR that it plans to sell a portion of one of
its security investments through a secondary market offering expected to take
place in the second quarter of 1999. Contingent on the sale, based on the
current market value of the security, Resources anticipates to receive cash
proceeds of approximately $25 million.
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.
For discussion of the use of proceeds of securitization, see Liquidity and
Capital Resources.
PSEG and PSE&G are analyzing their future capital and financing needs in
light of securitization, the transfer of generation-related assets to a separate
generation company and their business strategies. However, it is expected that
following completion of securitization and the generation-related asset
transfer, PSE&G and Genco will likely issue debt through the capital markets.
<PAGE>
PSEG
At March 31, 1999, PSEG had a committed $150 million revolving credit
facility which expires in December 2002. At March 31, 1999, PSEG had $30 million
outstanding under this revolving credit facility. At March 31, 1999 and 1998,
PSEG had a $25 million uncommitted line of credit with a bank. At March 31,
1999, PSEG had no debt outstanding under this line of credit.
PSE&G
PSE&G has filed with the BPU for approval to opportunistically refinance
essentially all of its long-term debt through January 4, 2000. In addition,
PSE&G will need to file a petition with the BPU in connection with
securitization and 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 March 31, 1999, the Mortgage would
permit up to $3.6 billion aggregate principal amount of new Mortgage Bonds to be
issued against previous additions and improvements. At March 31, 1999, PSE&G's
Mortgage coverage ratio was 4.036:1. 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.
To provide liquidity for its commercial paper program, PSE&G has a $650
million revolving credit agreement expiring in June 1999, which PSE&G expects to
renew, 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
March 31, 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 March 31, 1999, PSE&G had $499 million of short-term debt
outstanding, including $130 million borrowed against its uncommitted bank lines
of credit which lines of credit totaled $150 million as of March 31, 1999.
PSE&G Fuel Corporation (Fuelco) has a $125 million commercial paper program
to finance a 42.49% share of 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 March 31, 1999, Fuelco had commercial paper of $72
million outstanding.
Energy Holdings
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. At March 31,
1999, PSEG Capital had total debt outstanding of $650 million, all of which was
comprised of MTNs.
On February 16, 1999, PSEG Capital issued $252 million of 6.25% MTNs due
May 2003. The proceeds were used to repay $100 million of PSEG Capital MTNs
which matured February 16, 1999 and to reduce Energy Holdings' short-term debt.
As of March 31, 1999, Funding had $300 million and $150 million revolving
credit facilities with two groups of banks which expire in July and November
1999, respectively. Funding makes short-term investments only if the funds
cannot be employed in intercompany loans. Intercompany borrowing rates are
established based upon Funding's cost of funds. Funding is providing both long
and short-term capital for Resources and Global and their subsidiaries on the
basis of an unconditional guaranty from Energy Holdings, but without direct
support from PSEG. As of March 31, 1999, Funding had $123 million of total debt
outstanding under its revolving credit facility. Energy Holdings is in the
process of refinancing and renegotiating these credit facilities. Closing is
expected in the second quarter of 1999.
Compliance with applicable financial covenants will depend upon future
financial position and level 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 and Energy
Holdings' ability to obtain additional financing beyond current levels. Based on
current expectations of contemplated investments in 1999, it is anticipated that
equity from PSEG will be required by Energy Holdings in 1999 in addition to
Energy Holdings' debt financing. In order for investment activity to exceed
current expectations due to attractive opportunities in the marketplace, Energy
Holdings would need to access additional sources of debt, which may include
capital markets, to fund new development activity.
Global has certain project debt that is non-recourse to Energy Holdings and
Global which is maturing or for which principal and interest payments are due in
May 1999. While efforts are underway to refinance this debt in a similar
non-recourse capacity, additional capital may be required by the lenders from
the respective partners. The aggregate amount of such additional capital
required is not expected to exceed $40 million.
Foreign Operations
In accordance with their growth strategies, Global and Resources have made
approximately $946 million and $696 million, respectively, of international
investments. As of March 31, 1999, foreign investments represented 8% of PSEG's
consolidated assets and contributed 2% of first quarter 1999 consolidated
revenues. Resources' international investments are primarily in leveraged leases
in the Netherlands, Australia and the United Kingdom with associated revenues
denominated in U.S. dollars, and, therefore bear no foreign currency risk.
Global's international investments are primarily in projects that generate or
distribute electricity in Brazil, Argentina and China. As a primary vehicle for
PSEG's growth, Global is expected to continue to invest in competitive power
markets. Where possible, Global structures its investments to manage the risk
associated with project development, including foreign currency devaluation and
fluctuations. Global has evaluated the current economic conditions in these
regions and has determined that its investments have not been impaired. In
evaluating its investment decisions, Global considers the economic, political
and currency risks associated with each potential project. Where warranted,
Global assumes a certain level of currency devaluation when making its
investment decision. For discussion of the devaluation of the Brazilian Real,
see Note 5. Financial Instruments and Risk Management of Notes.
Competitive Environment
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. The
Decision and Order resulting from these proceedings could have a material
adverse impact on PSEG's and PSE&G's financial condition, results of operations
and net cash flows.
<PAGE>
PJM Interconnection, L.L.C. (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 reliability
of the bulk electric supply systems in the Mid-Atlantic area.
As of April 1, 1999, FERC lifted the requirements that bids for electric
energy offered for sale in the PJM interchange energy market from generation
located within the PJM control area shall 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 capped at $1,000 per megawatt hour. 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. When the LEAC is discontinued, to the extent PSEG's
generation business (Genco) produces less energy than required under the basic
generation service (BGS) contract with PSE&G, the lifting of such caps could
present additional risks to Genco with respect to the difference between the LMP
and the BGS rate. For further discussion of price volatility of electricity, see
Qualitative and Quantitative Disclosures About Market Risk of MD&A.
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 purchased right that can hedge against congestion charges incurred
on a specified transmission path. An FTR financially binds the owner to the
congestion activity on that path. The path is defined as the point where power
is synchronized onto the PJM grid to the point where it is withdrawn. The PJM
ISO administers this system. PSE&G cannot predict the impacts of PJM
implementing these market enhancements.
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 by 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) identifies systems having potential
Year 2000 issues and sets priorities for assessing and remediating those
systems. The second phase (Assessment) determines 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.
PSEG and PSE&G have completed required Year 2000 readiness work for more
than 85% of their critical systems as of March 31, 1999. The work required by
the remaining critical systems is expected to be completed by July 1999, except
for certain systems at PSE&G's nuclear facilities. The majority of these systems
are scheduled beyond July 1999 in order to coincide with planned refueling
outages at these facilities. 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. 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
such systems.
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. As of March 31, 1999, PSE&G's Year
2000 effort at its nuclear facilities is on schedule to meet the NRC's response
date of July 1, 1999 and to have all mission critical systems ready by January
1, 2000. Additionally, at meetings held in March 1999, PECO again confirmed to
PSE&G that Peach Bottom's Year 2000 effort is on schedule to meet the required
July 1999 NRC response schedule.
PSEG and PSE&G 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 80% of
their critical vendors that they are making or have made preparations for the
Year 2000. To date, all critical vendors responding indicate that their business
operations will be ready. 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 and net cash flows.
Year 2000 Costs
For a discussion of Year 2000 Costs, see Note 4. Commitments and Contingent
Liabilities of Notes.
Year 2000 Risks
PSEG and PSE&G have identified some and will continue working to determine
the most reasonably likely, worst case scenarios arising from Year 2000
readiness issues. Such scenarios may include, among others, significant
reductions in key customers' power needs due to their own Year 2000 readiness
issues or temporary disruption of service from the effect of disruptions caused
by other entities whose electrical systems are connected to PSE&G's through PJM.
The results of such 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 is in the process of performing an assessment of PSE&G's Year
2000 program.
o On a general level, the BPU has required PSEG and PSE&G to participate
in periodic status meetings with other utilities.
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 will be 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 project 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, 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 and
net cash flows.
Accounting Issues
For a discussion of significant accounting matters including Emerging
Issues Task Force (EITF) Issues 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," and SOP 98-5, "Reporting on the Costs of Start-Up Activities,"
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), see Note 8. Accounting Matters of Notes.
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; Accounting Issues and
Impact of New Accounting Pronouncements.
Forward Looking Statements
The Private Securities Litigation Reform Act of 1995 (the Act) provides a
"safe harbor" for forward-looking statements to encourage such disclosures
without the threat of litigation providing those statements are identified as
forward-looking and are accompanied by meaningful, cautionary statements
identifying important factors that could cause the actual results to differ
materially from those projected in the statement. Forward-looking statements
have been made in this report. 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", "estimate",
"expect", "objective", "hypothetical", "potential" and similar expressions are
intended to identify forward-looking statements. 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; managing rapidly changing energy trading operations in conjunction
with electricity and gas production, transmission and distribution systems;
managing foreign investments and electric generation and distribution operation
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 service territory and a need to
reduce operating and capital costs; ability to obtain adequate and timely rate
relief, cost recovery, including stranded costs, and other necessary regulatory
approvals; Federal and state regulatory actions; costs of construction; 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 credit market concerns. 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
pursuant to the Act 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 Act.
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 nonperformance or nonpayment by a major
counterparty, there may be a material adverse impact on PSEG's and PSE&G's
financial condition, results of operations and net cash flows.
Commodities--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.
PSE&G currently has 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 reduce the risk to PSE&G by permitting PSE&G to
defer price increases and decreases until regulatory treatment can be
determined. In accordance with the BPU's April 21, 1999 Summary Order, PSE&G,
effective August 1, 1999, will no longer account for the cost of electric energy
through a levelized adjustment clause. For discussion of the levelized energy
adjustment clauses and the potential impacts from the Energy Master Plan
Proceedings, see Note 2. Regulatory Issues and Note 3. 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, L.L.C. (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. The
measured value-at-risk using a variance/co-variance model with a 97.5%
confidence level and assuming a one week horizon at March 31, 1999 was
approximately $5 million, compared to the December 31, 1998 level of $4 million.
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.
Foreign Currencies--Energy Holdings
For discussion of foreign currency risks, see Note 5. 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 is updated below.
(1) New Matter. On April 19, 1999, 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 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. Similar
allegations by the plaintiff regarding the 1996, 1997 and 1998 proxy
statements were dismissed by the Court in the applicable proceedings. G. E.
Stricklin v. E. James Ferland, et. al., United States District Court for
the Eastern District of Pennsylvania.
In addition, see the following at the pages hereof indicated:
(1) Pages 9 through 14 and 24 through 25. 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. Proceeding before the BPU Establishing Procedures for gas
unbundling, Docket No. GX99030121.
(3) Page 15. Proceedings before the BPU relating to PSE&G's proposed CTC
filed September 19, 1996, Docket Nos. ET96090669 and 97040274.
(4) Page 18. Investigation by the U.S. Environmental Protection Agency
(EPA) regarding the Passaic River site.
(5) Page 18. Additional investigation by the U.S. Environmental Protection
Agency (EPA) regarding the Passaic River site.
(6) Page 41. Administrative proceedings before the NJDEP under Section 316
of the FWPCA for certain electric generating stations.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
PSEG's Annual Meeting of Stockholders was held on April 20, 1999. Proxies
for the meeting were solicited pursuant to Regulation 14A under the Securities
Act of 1934. There was no solicitation of proxies in opposition to management's
nominees as listed in the proxy statement and all of management's nominees were
elected to the Board of Directors. Details of the voting are provided below:
<TABLE>
<CAPTION>
Votes Votes
For Withheld
------------------ ------------------
<S> <C> <C>
Proposal 1 - Election of Directors
Class III - Term expiring 2002
T. J. Dermot Dunphy 181,790,995 2,462,843
Raymond V. Gilmartin 181,934,810 2,319,028
Conrad K. Harper 181,749,133 2,500,205
Votes Votes
For Against Abstentions
------------------ ------------------ -----------------
Proposal 2 - Ratification of the Appointment of
Deloitte & Touche LLP as Independent
Auditors for 1999 181,946,886 777,509 1,400,350
</TABLE>
With respect to Proposal 2, abstentions are not counted in the vote totals and,
therefore, have no effect on the vote.
ITEM 5. OTHER INFORMATION
Certain information reported under PSEG's and PSE&G's 1998 Annual Report to
the SEC is updated below. References are to the related pages of the Form 10-K
as printed and distributed.
PJM Interconnection, L.L.C.
Form 10-K, page 10. On March 19, 1999, the New York Mercantile Exchange
(NYMEX) began offering an electric energy futures trading contract based upon
the previously established PJM Western trading hub. The PJM Western hub is a
financial location specifically designed for facilitating such trading. The
Western hub is a composite of 111 locations for which PJM publishes a composite
price. The composite price is made up of the fixed load-weighted average of the
locational prices at each of the nodes that comprise the hub. PJM studies have
determined that a composite of many nodes provides a more stable hub price than
selecting a single node for the hub. The stability of the hub prices contributes
to the liquidity of the markets trading to and from the hub.
<PAGE>
Nuclear Operations
Form 10-K, page 11. As previously reported, on September 16, 1998, the NRC
indefinitely suspended its Systematic Assessment of Licensee Performance (SALP)
program until the NRC staff completed a review of its nuclear power plant
performance assessment process. The NRC has now developed a new program which
takes into account improvements in the performance of the nuclear industry over
the past twenty years and the desire of the NRC to apply more objective, timely,
safety-significant criteria in assessing performance. The NRC will monitor
performance in three broad areas - reactor safety, radiation safety and plant
security. Nuclear plant performance will be measured by a combination of
objective performance indicators and by the NRC inspection program, which will
be refocused on those plant activities which have the greatest impact on safety
and overall risk. Each performance indicator and inspection assessment will be
categorized to determine the appropriate regulatory response. For performance
indicators and inspection area results which do not meet the NRC's highest level
of acceptable performance, the NRC will increase its inspection and oversight
activities. Each year, a performance report will be issued as well as the
inspection plan for the following six-month period. Additionally, plants with
declining performance will be identified which may require further NRC action.
The new program will begin in June 1999 on a pilot basis at eight nuclear
power plants, including Salem and Hope Creek. It is expected that this new
process will be used at all domestic nuclear plants beginning in January 2000.
On April 16, 1999, as part of the transition to a new performance assessment
program, the NRC announced formal elimination of the "watch list" of troubled
plants and that recognition will no longer be given to "superior" performers.
On April 12, 1999, the NRC issued its six-month Plant Performance Review of
Salem and Hope Creek, which is being used as an interim process since the
suspension of the SALP program until the new assessment program is in place.
Salem and Hope Creek's overall performance was rated "acceptable" for the period
April 1998 through January 1999. Areas for improvement included human
performance, corrective maintenance backlog, work control process,
communications and procedural deficiencies.
PECO Energy has advised PSE&G that the NRC issued its six-month Plant
Performance Review of Peach Bottom on April 9, 1999. Overall performance was
rated "acceptable" for the period April 1998 through January 15, 1999. Areas for
improvement included engineering analysis of degraded conditions and some human
performance issues concerning maintenance activities and equipment status
control.
Other Nuclear Matters
Form 10-K, page 13. As previously reported, as a result of several BWRs
experiencing clogging of some emergency core cooling system suction strainers
which supply water from the suppression pool for emergency cooling of the core
and related structures, the NRC issued a Bulletin in 1996 to operators of BWRs
requesting that measures be taken to minimize the potential for clogging. The
NRC has proposed three resolution options and required that actions be completed
by the end of the unit's first refueling outage after January 1, 1997.
Alternative resolution options will be subject to NRC approval. PSE&G installed
a portion of the required large capacity passive strainers at Hope Creek during
Hope Creek's refueling outage in December 1997. The remaining strainers were
installed in March 1999. PECO Energy has advised PSE&G that large capacity
passive strainers were installed at Peach Bottom 3 during its refueling outage
in October 1997 and at Peach Bottom 2 during its refueling outage in October
1998. PSE&G cannot predict what other actions, if any, the NRC may take in this
matter.
Air Pollution Control
Form 10-K, page 20. For discussion of NOx allowances, see Note 4.
Commitments and Contingent Liabilities of Notes.
<PAGE>
Water Pollution Control
Form 10-K, page 22. As previously reported, PSE&G is implementing the 1994
NJPDES permit issued for Salem which requires, among other things, water intake
screen modifications and wetlands restoration. Under the 1994 permit, which
remains in effect until such time as a renewal permit is issued, PSE&G is
continuing to restore wetlands and to conduct the requisite management and
monitoring associated with the implementation of the special conditions of that
permit. The existing permit remains in full force and effect indefinitely given
the submission of a timely renewal filing. On March 4, 1999, PSE&G timely filed
a comprehensive application for the renewal of Salem's NJDEP permit which
included updated Section 316(a) and 316(b) demonstrations as well as a
demonstration of the implementation of the Special Conditions of the 1994 NJPDES
permit and their biological efficacy. PSE&G has also made a preliminary
submission to the Delaware River Basin Commission (DRBC) to initiate the
regulatory review necessary to renew the Docket for Salem, which Docket expires
in September 2000 unless renewed by the DRBC. While it is impossible to predict
the timing and/or outcome of the review of these applications presently, an
unfavorable determination could have a material adverse effect on PSEG's and
PSE&G's financial position, results of operations and net cash flows.
Certain Beneficial Owners
New Matter. As previously reported, according to the Schedule 13G filed by
Barclays Bank, PLC dated February 12, 1999, Barclays Bank, PLC was a beneficial
owner of 7.2% of Common Stock. According to the revised Schedule 13G of Barclays
Bank, PLC dated March 10, 1999, Barclays Bank, PLC was the owner of 3.5% of
Common Stock.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
<TABLE>
<CAPTION>
(A) A listing of exhibits being filed with this document is as follows:
PSEG PSE&G
---------------------------------------------------- ----------------------------------------------------------
Exhibit Document Exhibit Document
Number Number
------------- -------------------------------------- ------------ ---------------------------------------------
<S> <C> <C>
12 Computation of Ratios of Earnings 12(A) Computation of Ratios of Earnings to Fixed
to Fixed Charges (PSEG) Charges (PSE&G)
27(A) Financial Data Schedule (PSEG) 12(B) Computation of Ratios of Earnings to Fixed
Charges plus Preferred Stock Dividend
Requirements (PSE&G)
27(B) Financial Data Schedule (PSE&G)
</TABLE>
(B) Reports on Form 8-K:
Registrant Date of Report Items Reported
- -------------- -------------- --------------
PSEG and PSE&G March 18, 1999 Items 5 and 7
PSEG and PSE&G April 26, 1999 Item 5
<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: May 6, 1999
<TABLE>
EXHIBIT 12
- --------------------------------------------------------------------------------------------------------------------------
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
- --------------------------------------------------------------------------------------------------------------------------
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
12 Months
<CAPTION>
Ended
YEARS ENDED DECEMBER 31, March 31,
------------- ------------ ------------- ------------ ------------ -----------
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 $642
Income Taxes (C) 320 348 297 313 428 438
Fixed Charges 535 549 527 543 577 577
------------- ------------ ------------- ------------ ----------- -----------
Earnings $1,522 $1,524 $1,412 $1,416 $1,649 $1,657
============= ============ ============= ============ =========== ===========
Fixed Charges as Defined in
Regulation S-K (D):
Total Interest Expense (E) $462 $464 $453 $470 $481 $474
Interest Factor in Rentals 12 12 12 11 11 11
Subsidiaries' Preferred Securities
Dividend Requirements 2 16 28 44 71 78
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 $577
============= ============ ============= ============ =========== ===========
Ratio of Earnings to Fixed Charges 2.84 2.78 2.68 2.61 2.86 2.87
============= ============ ============= ============ =========== ===========
<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.
(C) Includes State income taxes and Federal income taxes for other income.
(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 pre-tax 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
- ----------------------------------------------------------------------------------------------------------------------------
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
<CAPTION>
12 Months
Ended
YEARS ENDED DECEMBER 31, March 31,
----------- ------------ ------------- ------------ ------------ ----------
1994 1995 1996 1997 1998 1999
----------- ------------ ------------- ------------ ------------ ----------
<S> <C> <C> <C> <C> <C> <C>
Earnings as Defined in Regulation S-K (A):
Net Income $659 $617 $535 $528 $604 $616
Income Taxes (B) 302 326 268 286 406 421
Fixed Charges 408 419 438 450 446 443
----------- ------------ ------------- ------------ ------------ -----------
Earnings $1,369 $1,362 $1,241 $1,264 $1,456 $1,480
=========== ============ ============= ============ ============ ===========
Fixed Charges as Defined in Regulation
S-K (C):
Total Interest Expense $396 $407 $399 $395 $390 $387
Interest Factor in Rentals 12 12 11 11 11 11
Subsidiaries' Preferred Securities
Dividend Requirements -- -- 28 44 45 45
----------- ------------ ------------- ------------ ------------ ----------
Total Fixed Charges $408 $419 $438 $450 $446 $443
=========== ============ ============= ============ ============ ===========
Ratio of Earnings to Fixed Charges 3.35 3.25 2.83 2.81 3.27 3.34
=========== ============ ============= ============ ============ ===========
<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) Includes State income taxes and Federal income taxes for other income.
(C) 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
- -----------------------------------------------------------------------------------------------------------------------------
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
PLUS PREFERRED STOCK DIVIDEND REQUIREMENTS
<CAPTION>
12 Months
Ended
YEARS ENDED DECEMBER 31, March 31,
------------ ------------- ------------ ------------ ------------- ------------
1994 1995 1996 1997 1998 1999
------------ ------------- ------------ ------------ ------------- ------------
<S> <C> <C> <C> <C> <C> <C>
Earnings as Defined in Regulation
S-K (A):
Net Income $659 $617 $535 $528 $604 $616
Income Taxes (B) 302 326 268 286 406 421
Fixed Charges 408 419 438 450 446 443
------------ ------------- ------------ ------------ ------------ ------------
Earnings $1,369 $1,362 $1,241 $1,264 $1,456 $1,480
============ ============= ============ ============ ============= ============
Fixed Charges as Defined in
Regulation S-K (C):
Total Interest Expense $396 $407 $399 $395 $390 $387
Interest Factor in Rentals 12 12 11 11 11 11
Subsidiaries' Preferred Securities
Dividend Requirements -- -- 28 44 45 45
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 $459
============ ============= ============ ============ ============= ============
Ratio of Earnings to Fixed Charges 2.92 2.77 2.62 2.70 3.15 3.22
============ ============= ============ ============ ============= ============
<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) Includes State income taxes and Federal income taxes for other income.
(C) 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 pre-tax 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> 3-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1999
<PERIOD-END> MAR-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 10,752
<OTHER-PROPERTY-AND-INVEST> 3,770
<TOTAL-CURRENT-ASSETS> 1,543
<TOTAL-DEFERRED-CHARGES> 1,585
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 17,650
<COMMON> 3,161 <F1>
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 1,816
<TOTAL-COMMON-STOCKHOLDERS-EQ> 4,806 <F2>
1,113
95
<LONG-TERM-DEBT-NET> 4,912
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 724
<LONG-TERM-DEBT-CURRENT-PORT> 372
0
<CAPITAL-LEASE-OBLIGATIONS> 50
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 5,578
<TOT-CAPITALIZATION-AND-LIAB> 17,650
<GROSS-OPERATING-REVENUE> 1,795
<INCOME-TAX-EXPENSE> 144 <F3>
<OTHER-OPERATING-EXPENSES> 1,334
<TOTAL-OPERATING-EXPENSES> 1,477
<OPERATING-INCOME-LOSS> 318
<OTHER-INCOME-NET> 6
<INCOME-BEFORE-INTEREST-EXPEN> 324
<TOTAL-INTEREST-EXPENSE> 136 <F4>
<NET-INCOME> 188
24
<EARNINGS-AVAILABLE-FOR-COMM> 188
<COMMON-STOCK-DIVIDENDS> 120
<TOTAL-INTEREST-ON-BONDS> 97
<CASH-FLOW-OPERATIONS> 614
<EPS-PRIMARY> .85
<EPS-DILUTED> .85
<FN>
<F1>Includes Treasury Stock of ($442).
<F2>Includes Foreign Currency Translation Adjustment of ($168).
<F3>Federal and State Income Taxes for Other Income of $1 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.
</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> 3-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1999
<PERIOD-END> MAR-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 10,752
<OTHER-PROPERTY-AND-INVEST> 768
<TOTAL-CURRENT-ASSETS> 1,368
<TOTAL-DEFERRED-CHARGES> 1,549
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 14,437
<COMMON> 2,563
<CAPITAL-SURPLUS-PAID-IN> 594
<RETAINED-EARNINGS> 1,278
<TOTAL-COMMON-STOCKHOLDERS-EQ> 4,432
588
95
<LONG-TERM-DEBT-NET> 3,946
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 571
<LONG-TERM-DEBT-CURRENT-PORT> 200
0
<CAPITAL-LEASE-OBLIGATIONS> 50
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 4,555
<TOT-CAPITALIZATION-AND-LIAB> 14,437
<GROSS-OPERATING-REVENUE> 1,666
<INCOME-TAX-EXPENSE> 134 <F1>
<OTHER-OPERATING-EXPENSES> 1,260
<TOTAL-OPERATING-EXPENSES> 1,393
<OPERATING-INCOME-LOSS> 273
<OTHER-INCOME-NET> 3
<INCOME-BEFORE-INTEREST-EXPEN> 276
<TOTAL-INTEREST-EXPENSE> 104 <F2>
<NET-INCOME> 172
3
<EARNINGS-AVAILABLE-FOR-COMM> 169
<COMMON-STOCK-DIVIDENDS> 274
<TOTAL-INTEREST-ON-BONDS> 79
<CASH-FLOW-OPERATIONS> 612
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
<FN>
<F1>State and Federal Income Taxes for Other Income of $1 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.
</FN>
</TABLE>
