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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 September 30, 1998
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 October 31, 1998: 228,227,508
As of October 31, 1998 Public Service Electric and Gas Company had issued
and outstanding 132,450,344 shares of common stock, without nominal or par
value, all of which were privately held, beneficially and of record by Public
Service Enterprise Group Incorporated.
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<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 and Nine
Months Ended September 30, 1998 and 1997........................... 1
Consolidated Balance Sheets as of September 30, 1998
and December 31, 1997.............................................. 2
Consolidated Statements of Cash Flows for the Nine
Months Ended September 30, 1998 and 1997........................... 4
Public Service Electric and Gas Company (PSE&G):
Consolidated Statements of Income for the Three and Nine
Months Ended September 30, 1998 and 1997........................... 5
Consolidated Balance Sheets as of September 30, 1998
and December 31, 1997.............................................. 6
Consolidated Statements of Cash Flows for the Nine
Months Ended September 30, 1998 and 1997........................... 8
Notes to Consolidated Financial Statements-- PSEG.................... 9
Notes to Consolidated Financial Statements-- PSE&G................... 22
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations
PSEG .............................................................. 23
PSE&G.............................................................. 34
Item 3. Qualitative and Quantitative Disclosures About Market Risk..... 35
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.............................................. 36
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 per share data)
(Unaudited)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
--------- --------- --------- ---------
<S> <C> <C> <C> <C>
OPERATING REVENUES
Electric ..................................................... $ 1,219 $ 1,107 $ 3,112 $ 2,966
Gas .......................................................... 197 270 1,081 1,328
Nonutility Activities ........................................ 9 71 212 162
--------- --------- --------- ---------
Total Operating Revenues ................................ 1,425 1,448 4,405 4,456
--------- --------- --------- ---------
OPERATING EXPENSES
Operation
Interchanged Power and Fuel for Electric Generation .......... 275 252 730 696
Gas Purchased ................................................ 128 144 687 745
Other ........................................................ 297 281 918 798
Maintenance .................................................... 52 69 153 197
Depreciation and Amortization .................................. 165 156 493 462
Taxes (Note 6)
Income Taxes ................................................. 134 93 356 245
Transitional Energy Facility Assessment/New Jersey
Gross Receipts Taxes ....................................... 41 132 128 421
Other ........................................................ 21 20 60 63
--------- --------- --------- ---------
Total Operating Expenses ................................ 1,113 1,147 3,525 3,627
--------- --------- --------- ---------
OPERATING INCOME ............................................... 312 301 880 829
--------- --------- --------- ---------
OTHER INCOME AND DEDUCTIONS
Settlement of Salem Litigation - Net of Applicable
Taxes of $29 .............................................. -- -- -- (53)
Other - net .................................................. 3 2 12 6
--------- --------- --------- ---------
Total Other Income and Deductions ....................... 3 2 12 (47)
--------- --------- --------- ---------
INCOME BEFORE INTEREST CHARGES AND
DIVIDENDS ON PREFERRED SECURITIES .............................. 315 303 892 782
--------- --------- --------- ---------
INTEREST CHARGES AND PREFERRED SECURITIES
DIVIDENDS
Interest Expense ............................................. 115 119 352 345
Allowance for Funds Used During Construction - Debt and
Capitalized Interest ....................................... (3) (6) (10) (15)
Preferred Securities Dividend Requirements of Subsidiaries ... 23 14 57 42
Net Loss on Preferred Stock Redemptions ...................... -- -- -- 3
--------- --------- --------- ---------
Total Interest Charges and Preferred Securities Dividends 135 127 399 375
--------- --------- --------- ---------
NET INCOME .............................................. $ 180 $ 176 $ 493 $ 407
========= ========= ========= =========
WEIGHTED AVERAGE COMMON SHARES AND
POTENTIAL DILUTIVE EFFECT OF STOCK OPTIONS
OUTSTANDING (000's) ....................................... 231,727 231,958 231,901 231,995
EARNINGS PER SHARE (Basic and Diluted) ......................... $ 0.78 $ 0.76 $ 2.13 $ 1.75
========= ========= ========= =========
DIVIDENDS PAID PER SHARE OF COMMON STOCK ....................... $ 0.54 $ 0.54 $ 1.62 $ 1.62
========= ========= ========= =========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions of Dollars)
<CAPTION>
(Unaudited)
September 30, December 31,
1998 1997
------------- -----------
<S> <C> <C>
UTILITY PLANT - Original cost
Electric ........................................................... $ 13,908 $ 13,692
Gas ................................................................ 2,782 2,697
Common ............................................................. 586 558
---------- ----------
Total ......................................................... 17,276 16,947
Less: Accumulated depreciation and amortization .................... 6,921 6,463
---------- ----------
Net ........................................................... 10,355 10,484
Nuclear Fuel in Service, net of accumulated amortization -
1998, $321; 1997, $302 .......................................... 181 216
---------- ----------
Net Utility Plant in Service .................................. 10,536 10,700
Construction Work in Progress, including Nuclear Fuel in
Process - 1998, $74; 1997, $60 ................................... 313 326
Plant Held for Future Use .......................................... 24 24
---------- ----------
Net Utility Plant ............................................. 10,873 11,050
---------- ----------
INVESTMENTS AND OTHER NONCURRENT ASSETS
Long-Term Investments, net of amortization - 1998, $27; 1997,
$21, and net of valuation allowances - 1998, $24; 1997, $10 ...... 2,886 2,873
Nuclear Decommissioning and Other Special Funds ..................... 570 492
Other Noncurrent Assets, net of amortization - 1998, $18; 1997, $16,
and net of valuation allowances - 1998, $5; 1997, $0 ............. 193 167
---------- ----------
Total Investments and Other Noncurrent Assets ................. 3,649 3,532
---------- ----------
CURRENT ASSETS
Cash and Cash Equivalents .......................................... 78 83
Accounts Receivable:
Customer Accounts Receivable ..................................... 539 520
Other Accounts Receivable ........................................ 361 293
Less: Allowance for Doubtful Accounts ............................ 39 41
Unbilled Revenues .................................................. 186 270
Fuel, at average cost .............................................. 326 310
Materials and Supplies, at average cost, net of inventory valuation
reserves - 1998, $12; 1997, $12 .................................. 144 142
Prepayments ........................................................ 234 48
Miscellaneous Current Assets ....................................... 32 38
---------- ----------
Total Current Assets .......................................... 1,861 1,663
---------- ----------
DEFERRED DEBITS (Note 3)
Unamortized Loss on Reacquired Debt and Debt Expense ............... 140 136
OPEB Costs ......................................................... 275 289
Environmental Costs ................................................ 121 122
Electric Energy and Gas Costs ...................................... 69 167
SFAS 109 Income Taxes .............................................. 698 725
Demand Side Management Costs ....................................... 141 116
Other .............................................................. 130 143
---------- ----------
Total Deferred Debits ......................................... 1,574 1,698
---------- ----------
TOTAL ................................................................ $ 17,957 $ 17,943
========== ==========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
(Millions of Dollars, except share data)
<CAPTION>
(Unaudited)
September 30, December 31,
1998 1997
------------ -------------
<S> <C> <C>
CAPITALIZATION
Common Stockholders' Equity:
Common Stock, issued; 231,957,608 shares .......................... $ 3,603 $ 3,603
Treasury Stock, at cost; 2,351,100 shares ......................... (91) --
Retained Earnings ................................................. 1,720 1,623
Foreign Currency Translation Adjustment ........................... (37) (15)
---------- ---------
Total Common Stockholders' Equity .............................. 5,195 5,211
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 8) ............................................ 1,038 513
Long-Term Debt ...................................................... 4,517 4,873
---------- ---------
Total Capitalization ........................................... 10,920 10,767
---------- ---------
OTHER LONG-TERM LIABILITIES
Accrued OPEB ........................................................ 332 289
Decontamination and Decommissioning Costs ........................... 39 43
Environmental Costs (Note 4) ....................................... 69 73
Capital Lease Obligations ........................................... 50 52
---------- ---------
Total Other Long-Term Liabilities .............................. 490 457
---------- ---------
CURRENT LIABILITIES
Long-Term Debt due within one year .................................. 419 340
Commercial Paper and Loans .......................................... 1,206 1,448
Accounts Payable .................................................... 725 686
Other ............................................................... 345 353
---------- ---------
Total Current Liabilities ...................................... 2,695 2,827
---------- ---------
DEFERRED CREDITS
Income Taxes ........................................................ 3,380 3,394
Investment Tax Credits .............................................. 328 343
Other ............................................................... 144 155
---------- ---------
Total Deferred Credits ......................................... 3,852 3,892
---------- ---------
COMMITMENTS AND CONTINGENT LIABILITIES (Note 4) ...................... -- --
---------- ---------
TOTAL ................................................................. $ 17,957 $ 17,943
========== =========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
(Unaudited)
<CAPTION>
Nine Months Ended September 30,
-------------------------------
1998 1997
--------- ---------
<S>
CASH FLOWS FROM OPERATING ACTIVITIES <C> <C>
Net income ..................................................... $ 493 $ 407
Adjustments to reconcile net income to net cash flows from
operating activities:
Depreciation and Amortization ................................ 493 462
Amortization of Nuclear Fuel ................................. 70 47
Recovery of Electric Energy and Gas Costs - net .............. 98 23
Unrealized (Gains)/Losses on Investments - net ............... (29) (37)
Proceeds from Leasing Activities ............................. (39) 76
Changes in certain current assets and liabilities:
Net change in Accounts Receivable and Unbilled Revenues ..... (5) 167
Net increase in Inventory - Fuel and Materials and Supplies . (18) (11)
Net change in Accounts Payable .............................. 39 (32)
Net increase in Prepayments ................................. (186) (175)
Net decrease in Other Current Assets and Liabilities ........ (2) (102)
Other ........................................................ 27 (47)
----- -----
Net Cash Provided By Operating Activities ................. 941 778
----- -----
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Utility Plant, excluding AFDC ..................... (359) (383)
Net decrease (increase) in Long-Term Investments and Real Estate 46 (438)
Contribution to Decommissioning Funds and Other Special Funds .. (91) (43)
Other .......................................................... (39) (65)
----- -----
Net Cash Used In Investing Activities ..................... (443) (929)
----- -----
CASH FLOWS FROM FINANCING ACTIVITIES
Net (decrease) increase in Short-Term Debt ..................... (242) 422
Issuance of Long-Term Debt ..................................... 250 454
Redemption of Long-Term Debt ................................... (527) (488)
Redemption of Preferred Stock .................................. -- (94)
Issuance of Preferred Securities ............................... 525 95
Purchase of Treasury Stock ..................................... (91) --
Retirement of Common Stock ..................................... -- (43)
Cash Dividends Paid on Common Stock ............................ (376) (376)
Other .......................................................... (42) (10)
----- -----
Net Cash Used In Financing Activities ..................... (503) (40)
----- -----
Net Decrease In Cash And Cash Equivalents ........................ (5) (191)
Cash And Cash Equivalents At Beginning Of Period ................. 83 279
----- -----
Cash And Cash Equivalents At End Of Period ....................... $ 78 $ 88
===== =====
Income Taxes Paid ................................................ $ 347 $ 118
Interest Paid .................................................... $ 339 $ 302
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(Millions of Dollars)
(Unaudited)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -------------------
1998 1997 1998 1997
------- ------- ------- --------
<S> <C> <C> <C> <C>
OPERATING REVENUES
Electric ..................................................... $ 1,219 $ 1,107 $ 3,112 $ 2,966
Gas .......................................................... 197 270 1,081 1,328
------- ------- ------- -------
Total Operating Revenues ................................ 1,416 1,377 4,193 4,294
------- ------- ------- -------
OPERATING EXPENSES
Operation
Interchanged Power and Fuel for Electric Generation .......... 275 252 730 696
Gas Purchased ................................................ 128 144 687 745
Other ........................................................ 265 259 814 736
Maintenance .................................................... 51 69 153 197
Depreciation and Amortization .................................. 162 155 484 459
Taxes (Note 6)
Income Taxes ................................................. 155 84 351 231
Transitional Energy Facility Assessment/New Jersey
Gross Receipts Taxes ...................................... 41 132 128 421
Other ........................................................ 18 18 56 58
------- ------- ------- -------
Total Operating Expenses ................................ 1,095 1,113 3,403 3,543
------- ------- ------- -------
OPERATING INCOME ............................................... 321 264 790 751
------- ------- ------- -------
OTHER INCOME AND DEDUCTIONS
Settlement of Salem Litigation - Net of Applicable
Taxes of $29 ............................................. -- -- -- (53)
Other - net .................................................. 1 2 6 6
------- ------- ------- -------
Total Other Income and Deductions ....................... 1 2 6 (47)
------- ------- ------- -------
INCOME BEFORE INTEREST CHARGES AND
DIVIDENDS ON PREFERRED SECURITIES .............................. 322 266 796 704
------- ------- ------- -------
INTEREST CHARGES AND PREFERRED SECURITIES
DIVIDENDS
Interest Expense ............................................. 97 100 285 296
Allowance for Funds Used During Construction - Debt .......... (3) (4) (9) (12)
Preferred Securities Dividend Requirements
of Subsidiaries ......................................... 11 11 33 33
------- ------- ------- -------
Total Interest Charges and Preferred Securities Dividends 105 107 309 317
------- ------- ------- -------
NET INCOME .............................................. 217 159 487 387
------- ------- ------- -------
Preferred Stock Dividend Requirements ........................ 2 2 7 10
Net Loss on Preferred Stock Redemptions ...................... -- -- -- 3
------- ------- ------- -------
EARNINGS AVAILABLE TO PUBLIC SERVICE
ENTERPRISE GROUP INCORPORATED .................................. $ 215 $ 157 $ 480 $ 374
======= ======= ======= =======
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions of Dollars)
<CAPTION>
(Unaudited)
September 30, December 31,
1998 1997
------------- -------------
<S> <C> <C>
UTILITY PLANT - Original cost
Electric ......................................................... $ 13,908 $ 13,692
Gas .............................................................. 2,782 2,697
Common ........................................................... 586 558
---------- ----------
Total ....................................................... 17,276 16,947
Less: Accumulated depreciation and amortization .................. 6,921 6,463
---------- ----------
Net ......................................................... 10,355 10,484
Nuclear Fuel in Service, net of accumulated amortization -
1998, $321; 1997, $302 ........................................ 181 216
---------- ----------
Net Utility Plant in Service ................................ 10,536 10,700
Construction Work in Progress, including Nuclear Fuel in
Process - 1998, $74; 1997, $60 ................................. 313 326
Plant Held for Future Use ........................................ 24 24
---------- ----------
Net Utility Plant ........................................... 10,873 11,050
---------- ----------
INVESTMENTS AND OTHER NONCURRENT ASSETS
Long-Term Investments, net of amortization - 1998, $27; 1997, $21,
and net of valuation allowances - 1998, $14; 1997, $10 ......... 136 137
Nuclear Decommissioning and Other Special Funds .................. 570 492
Other Noncurrent Assets ........................................... 43 45
---------- ----------
Total Investments and Other Noncurrent Assets ............... 749 674
---------- ----------
CURRENT ASSETS
Cash and Cash Equivalents ........................................ 17 17
Accounts Receivable:
Customer Accounts Receivable ................................... 498 488
Other Accounts Receivable ...................................... 336 232
Less: Allowance for Doubtful Accounts .......................... 37 41
Unbilled Revenues ................................................ 186 270
Fuel, at average cost ............................................ 326 310
Materials and Supplies, at average cost, net of inventory
valuation reserves - 1998, $12; 1997, $12 ...................... 144 142
Prepayments ...................................................... 229 44
Miscellaneous Current Assets ..................................... 28 37
---------- ----------
Total Current Assets ........................................ 1,727 1,499
---------- ----------
DEFERRED DEBITS (Note 3)
Unamortized Loss on Reacquired Debt and Debt Expense ............. 140 135
OPEB Costs ....................................................... 275 289
Environmental Costs .............................................. 121 122
Electric Energy and Gas Costs .................................... 69 167
SFAS 109 Income Taxes ............................................ 698 725
Demand Side Management Costs ..................................... 141 116
Other ............................................................ 130 143
---------- ----------
Total Deferred Debits ....................................... 1,574 1,697
---------- ----------
TOTAL .............................................................. $ 14,923 $ 14,920
========== ==========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
(Millions of Dollars)
<CAPTION>
(Unaudited)
September 30, December 31,
1998 1997
-------------- --------------
<S> <C> <C>
CAPITALIZATION
Common Stockholder's Equity:
Common Stock ........................................... $ 2,563 $ 2,563
Contributed Capital .................................... 594 594
Retained Earnings ...................................... 1,455 1,352
------- -------
Total Common Stockholder's Equity ................... 4,612 4,509
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 8) .................................. 513 513
Long-Term Debt ........................................... 4,044 4,126
------- -------
Total Capitalization ................................ 9,339 9,318
------- -------
OTHER LONG-TERM LIABILITIES
Accrued OPEB ............................................. 332 289
Decontamination and Decommissioning Costs ................ 39 43
Environmental Costs (Note 4) ............................ 69 73
Capital Lease Obligations ................................ 50 52
------- -------
Total Other Long-Term Liabilities ................... 490 457
------- -------
CURRENT LIABILITIES
Long-Term Debt due within one year ....................... 100 118
Commercial Paper and Loans ............................... 1,082 1,106
Accounts Payable ......................................... 637 608
Other .................................................... 257 268
------- -------
Total Current Liabilities ........................... 2,076 2,100
------- -------
DEFERRED CREDITS
Income Taxes ............................................. 2,567 2,569
Investment Tax Credits ................................... 319 333
Other .................................................... 132 143
------- -------
Total Deferred Credits .............................. 3,018 3,045
------- -------
COMMITMENTS AND CONTINGENT LIABILITIES (Note 4) ............ -- --
------- -------
TOTAL ...................................................... $14,923 $14,920
======= =======
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions of Dollars)
(Unaudited)
<CAPTION>
Nine Months Ended September 30,
-------------------------------
1998 1997
---------- -----------
<S> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income ................................................... $ 487 $ 387
Adjustments to reconcile net income to net cash flows from
operating activities:
Depreciation and Amortization .............................. 484 459
Amortization of Nuclear Fuel ............................... 70 47
Recovery of Electric Energy and Gas Costs - net ............ 98 23
Changes in certain current assets and liabilities:
Net change in Accounts Receivable and Unbilled Revenues ... (34) 160
Net increase in Inventory - Fuel and Materials and Supplies (18) (11)
Net change in Accounts Payable ............................ 29 (12)
Net increase in Prepayments ............................... (185) (169)
Net decrease in Other Current Assets and Liabilities ...... (2) (107)
Other ...................................................... 39 (81)
----- -----
Net Cash Provided By Operating Activities ............... 968 696
----- -----
CASH FLOWS FROM INVESTING ACTIVITIES
Additions to Utility Plant, excluding AFDC ................... (359) (383)
Contribution to Decommissioning Funds and Other Special Funds (91) (43)
Other ........................................................ (10) (33)
----- -----
Net Cash Used In Investing Activities ................... (460) (459)
----- -----
CASH FLOWS FROM FINANCING ACTIVITIES
Net (decrease) increase in Short-Term Debt ................... (24) 290
Issuance of Long-Term Debt ................................... 250 279
Redemption of Long-Term Debt ................................. (350) (416)
Redemption of Preferred Stock ................................ -- (94)
Issuance of Preferred Securities ............................. -- 95
Cash Dividends Paid .......................................... (383) (401)
Other ........................................................ (1) (13)
----- -----
Net Cash Used In Financing Activities ................... (508) (260)
----- -----
Net Change In Cash And Cash Equivalents ........................ -- (23)
Cash And Cash Equivalents At Beginning Of Period ............... 17 48
----- -----
Cash And Cash Equivalents At End Of Period ..................... $ 17 $ 25
===== =====
Income Taxes Paid .............................................. $ 333 $ 205
Interest Paid .................................................. $ 295 $ 271
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
- --------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Basis of Presentation/Organization
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 1997 Annual Report on Form 10-K and the
Quarterly Reports on Form 10-Q for the quarters ended March 31, 1998 and June
30, 1998. These Notes update and supplement matters discussed in the 1997 Annual
Report on Form 10-K and the Quarterly Reports on Form 10-Q for the quarters
ended March 31, 1998 and June 30, 1998.
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 1997
Annual Report on Form 10-K. Certain reclassifications of prior period data have
been made to conform with the current presentation.
These reclassifications include netting the cost of interchanged power for
energy trading against energy trading revenue in Operating Revenues - Electric.
Public Service Enterprise Group Incorporated (PSEG) and Public Service Electric
& Gas Company (PSE&G) enter into contracts for the purchase and sale of energy
commodities (primarily electricity) to manage exposure to price volatility and
to generate market gains. The gross amounts of revenue and expense generated
from these contracts have previously been reported in Electric Revenue and
Interchanged Power and Fuel for Electric Generation, respectively, within the
statements of income. Effective in the third quarter of 1998, these contracts
are reported on a net basis. Reclassifications of prior period information have
been made to conform with the current presentation.
Organization
As previously reported, on June 12, 1998, PSEG renamed certain of its
principal non-utility subsidiaries. Enterprise Diversified Holdings Incorporated
was renamed PSEG Energy Holdings Inc. (Energy Holdings); Community Energy
Alternatives Incorporated was renamed PSEG Global Inc. (Global); Energis
Resources Incorporated was renamed PSEG Energy Technologies Inc. (Energy
Technologies) and Public Service Resources Corporation was renamed PSEG
Resources Inc. (Resources).
Note 2. Rate Matters
New Jersey Energy Master Plan Proceedings and Related Legislation
As previously reported, the New Jersey Board of Public Utilities (BPU) is
engaged in proceedings to implement the New Jersey Energy Master Plan (Energy
Master Plan) which, when completed, are expected to fundamentally change the
electric industry in the State by, among other things, introducing retail
competition to replace the monopoly position of regulated public utilities,
potentially requiring or resulting in the separation or sale of utilities'
generation assets and establishing generic rules governing the regulated
utilities' relationships with their affiliates. If the generation business is
deregulated as proposed, generation will be in 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, marketing ability and quality of service, among others. The
outcome of these proceedings and the proposed legislation to authorize the BPU
to permit competition in the electric and gas marketplace will have a profound
effect on PSEG and PSEG's principal subsidiary, PSE&G.
In connection with its Energy Master Plan proceedings, the BPU requested
the Office of Administrative Law (OAL) to hold evidentiary hearings regarding
stranded costs and unbundling issues. On August 17, 1998, the OAL filed its
decision providing its recommendations to the BPU. The BPU can adopt, reject or
modify the Administrative Law Judge's (ALJ) recommendations in its decision on
PSE&G's proposal which was filed as part of these proceedings. PSE&G cannot
predict the extent to which the BPU will rely on the ALJ's decision in
evaluating PSE&G's proposal. The ALJ's decision on PSE&G's competition and rate
proposal:
Recommended the adoption of PSE&G's request to securitize up to $2.5
billion of its after-tax stranded costs through the issuance of
revenue bonds, which would mature over a 15 year period.
Recommended the recovery of $1.6 billion of PSE&G's above-market price
contracts to purchase power from non-utility generators (NUGs).
Recommended a rate cut of between 10% and 12%, exclusive of the impact
of energy tax reform.
Supported PSE&G's request for a seven year transition period. PSE&G
had proposed a transition period of seven years, starting on the
effective date of the BPU's final decision in these proceedings, with
basic tariff rates capped during that seven year period. During the
transition period, PSE&G would maintain responsibility for system
reliability of energy and capacity supply.
Accepted PSE&G's approach/methodology of quantifying stranded costs
without quantifying the amount of such costs.
Recommended a review of PSE&G's actual electric fuel costs, which
would apply any potential savings from the elimination of the Electric
Levelized Energy Adjustment Clause (LEAC) to mitigate stranded costs
(see Note 3. Regulatory Assets and Liabilities).
Supported PSE&G's Societal Benefits Clause proposal, but proposed to
exclude non-utility generators (NUG) costs from the Societal Benefits
Clause. A separate NUG charge would be created.
Recommended adding an amount, known as a "retail adder," to the
proposed market-based energy credit on customers' bills to give
customers who choose another energy supplier credits for more than the
market price for power.
On October 2, 1998, PSE&G filed exceptions to the ALJ's decision. These
exceptions addressed issues identified in the ALJ's decision including the
validity of capital additions made by PSE&G after the conclusion of its 1992
base rate case, the relevance of PSE&G's methodology regarding stranded costs,
mitigation strategies, the adoption of securitization and the unbundling of
costs and rates. Other parties to the proceeding have also filed exceptions to
the ALJ's decision. PSE&G filed its reply exceptions to the other parties'
exceptions to the ALJ's decision on October 30, 1998.
Hearings at the BPU addressing other restructuring issues such as market
power, functional separation and consumer protection concluded on May 28, 1998.
Briefs have been filed by the parties in these hearings and a decision is
pending.
As discussed above, proposed legislation, the Electric Discount and Energy
Competition Act (Energy Competition Act), concerning competition in the electric
and gas industries, was introduced, into the New Jersey State Assembly on
September 14, 1998 as House Bill A-10 and into the New Jersey Senate on
September 28, 1998 as Senate Bill S-5. These bills will be debated in both
houses of the New Jersey legislature prior to any final approval. Legislative
hearings commenced on October 19, 1998. This legislation would provide the BPU
requisite authority to implement certain aspects of wholesale and retail
electric competition in New Jersey. Key features of the proposed Energy
Competition Act, as introduced, but subject to revision, include:
Competitive choice for electric service would begin on June 1, 1999
with an optional phase-in period of four months. Competitive choice
for gas service must be fully implemented by December 31, 1999. For
further discussion of gas competition, see Gas Unbundling Pilot
Program.
Initial electric rate reductions of between 5% and 10%, phased in over
a period of up to twenty-four months, would be provided to consumers.
When coupled with reductions expected from recent changes in New
Jersey energy taxes (see Note 6. Taxes), the total rate reductions for
consumers could total between 11% and 16%.
Utilities would have an opportunity to recover stranded costs
associated with generation assets through a market transition charge
(MTC) that could last up to eight years. Costs associated with
above-market power purchase contracts with other utilities and with
non-utility generators (NUGs) would be recovered over the remaining
life of those contracts. Mitigation by the utility of its stranded
costs, to the extent possible, would be required.
Securitization is limited to 75% of generation-related stranded costs.
Generation-related transition bonds with a maximum maturity of 15
years could be issued if the proceeds are used to reduce stranded
costs associated with generation-related assets. Power purchase
contracts could also be securitized in an effort to buy out or buy
down contracts. Overall rate reductions and stranded cost levels would
determine the amount of debt a company would be allowed to securitize.
On or after the starting date of implementation of retail choice, the
BPU may require functional separation of a utility's non-competitive
business functions from its competitive electric generation service
and require that those functions be provided by a related competitive
business segment or a public utility holding company. The related
competitive business segment would not be subject to regulation under
New Jersey utility law.
While the proposed Energy Competition Act does not mandate divestiture
of generation assets, it would give the BPU the right to examine
market conditions and require divestiture if it finds market power
would impede development of competition.
Competitive services may be offered by an electric public utility only
with the written approval of the BPU. Tariffs for competitive services
would be required and subject to review and approval by the BPU. The
competitive business segment must not adversely impact the ability of
the utility to offer non-competitive services to customers in a safe,
adequate and proper manner. The price for services must not be less
than the fully allocated cost of providing such services.
Cross-subsidization would be prohibited and standards for affiliate
relationships would be established. The BPU would be required to apply
50% of the net revenues earned from competitive services offered by an
electric public utility as an offset to stranded costs or a reduction
of rates.
Utility holding companies would be permitted to offer competitive
electric generation service to existing utility retail customers
subject to affiliate relations standards to be established by the BPU.
A utility holding company's competitive business entity utilizing
utility assets, including personnel and equipment other than the
delivery network, to provide competitive services may be subject to a
50% sharing of net revenues from such services. Unless the utility
ratepayers receive full market value for the use of such utility
assets pursuant to a contract between the parties filed with the BPU,
those revenues would be used to offset transition charges and/or
distribution rates for a period of time.
The BPU would be required to initiate a proceeding and adopt interim
technical standards to ensure the safety, reliability and accuracy of
metering equipment provided to electric and gas customers. The BPU
would be required to issue an order providing customers the
opportunity to choose a supplier for some or all customer services
(such as metering and billing) not later than one year from the start
of retail competition.
The BPU would be required to adopt interim consumer protection
standards for electric and gas suppliers to prevent slamming, protect
customer privacy and provide customers necessary information to make
informed decisions.
Simultaneously with the implementation of retail choice, the BPU may
permit recovery of certain costs through a Societal Benefits Clause
which would be a component of rates for all customers. These costs
would include societal programs for which rate recovery was approved
prior to April 30, 1997; nuclear decommissioning costs; demand side
management program costs and manufactured gas plant clean up costs.
The BPU should commence a proceeding within nine months of the
implementation of retail choice to determine whether a universal
service fund should be created.
Utilities would serve customers for at least three years as the energy
provider of last resort, providing basic generation and gas services.
The BPU would be required to decide, no later than three years after
the start of retail choice, whether to allow other, non-utility,
suppliers to offer basic generation service on a competitive basis.
Businesses, cities, towns and counties would be able to aggregate
their own power demands and other energy needs for which marketers may
bid to serve. Aggregation by municipalities to serve residents and
businesses within those municipalities could commence in three years
from the effective date of the legislation.
Electric suppliers must disclose information about fuels used to
generate the electricity that they sell and emissions from their
portfolio of electricity suppliers on customers' bills and in
marketing materials. The BPU and New Jersey Department of
Environmental Protection (NJDEP) may adopt an emission control
portfolio standard for all retail suppliers if the BPU finds that a
standard is necessary to meet Clean Air Act rules and that regional
and Federal actions would not achieve compliance with those rules.
Final legislative and executive action on the proposed legislation is
currently expected during the fourth quarter of 1998. If this legislation is not
enacted this year, it is possible that any legislation and any related
regulatory action required for industry restructuring could be delayed until
2000.
To the extent that any portion of its stranded costs are not probable of
recovery upon the conclusion of the Energy Master Plan proceedings and the
related legislative process, and thus ineligible for deferral as a regulatory
asset under Statement of Financial Accounting Standards (SFAS) 71, "Accounting
for the Effects of Certain Types of Regulation" (SFAS 71), PSE&G would incur an
extraordinary, non-cash charge to operations that could be material to the
financial position and results of operations of PSEG and PSE&G. For additional
discussion related to the Energy Master Plan and the related legislation, see
Note 3. Regulatory Assets and Liabilities. PSEG and PSE&G cannot predict the
outcome of these administrative and legislative proceedings. However, such
proceedings could have a material adverse effect on PSEG's and PSE&G's financial
condition, results of operations and net cash flows and could adversely affect
the carrying values of PSEG's and PSE&G's assets and the ability to declare
dividends on PSEG's common stock.
On September 15, 1998, in anticipation of securitization of PSE&G's
stranded costs afforded by the proposed Energy Competition Act and the ALJ's
decision, the Board of Directors of PSEG authorized the repurchase of up to 10
million shares of its common stock (Common Stock). Under the authorization,
repurchases will be made in the open market at the discretion of PSEG. Until the
expected securitization process in connection with the Energy Master Plan
occurs, the Common Stock repurchase will be funded by PSEG debt with the
repurchased shares held as treasury stock. At September 30, 1998, PSEG had
repurchased approximately 2.4 million shares of Common Stock at a cost of $91
million, under this authorization.
Non-utility Generation Buydown
As previously reported, PSE&G is seeking to restructure certain of its BPU
approved contracts with NUGs, which are estimated to be $1.6 billion above
assumed future market prices. Under Federal and State regulations, utilities
have been required to enter into long-term power purchase agreements with NUGs
at prices which have subsequently proven to be above market. In June 1998, PSE&G
and the Union County Utilities Authority (UCUA) announced an agreement to amend
their Power Purchase and Interconnection Agreement and in July 1998, the BPU
approved this amendment. Under this amendment, PSE&G has paid UCUA a lump sum
amount of $7.75 million in exchange for a $15.6 million savings to ratepayers on
a net present value basis. The payment of $7.75 million by PSE&G will be
recovered through the LEAC or successor mechanisms for recovery of NUG costs, to
be determined by the outcome of the Energy Master Plan proceedings.
Levelized Gas Adjustment Clause (LGAC)
On July 10, 1998, PSE&G filed a motion with the BPU requesting a $27
million annual increase in its LGAC for the period October 1, 1998 to September
30, 1999, representing an increase on a typical residential bill of
approximately 2.8%. Also included in the revised LGAC rate is an increase in the
Remediation Adjustment Clause (RAC) component, a decrease in the Demand Side
Adjustment Factor (DSAF) and a request to change, on a monthly basis, the
over/under collection component of the LGAC rate for residential customers. On
October 15, 1998, PSE&G, BPU Staff and the Ratepayer Advocate executed an
Interim Stipulation. The Stipulation allows the filed LGAC rates to become
effective, subject to refund. On November 4, 1998, the BPU approved an Order
adopting the Interim Stipulation. The remaining issues will be either settled or
litigated and incorporated in the BPU's Final Order in this matter. PSE&G cannot
predict the outcome of this proceeding.
Gas Unbundling Pilot Program
In April 1997, the BPU approved PSE&G's proposal for a residential gas
unbundling pilot program (SelectGas), which allowed approximately 65,000
residential natural gas customers, out of a total of 1.4 million residential gas
customers, to participate in the competitive marketplace effective May 1, 1997.
To date, none of these eligible customers have subscribed to the program. On
April 30, 1998, PSE&G filed a report with the BPU on SelectGas and proposed
refinements for a permanent residential gas unbundling program (SelectGas Plus).
Under SelectGas Plus, as proposed, a total of 300,000 residential customers
would be permitted to choose their gas supplier on a first-come, first-served
basis. This expanded program would commence sixty days after a BPU order
authorizing this program. PSE&G's proposal would permit its remaining
residential customers to choose their gas supplier by July 1, 1999 or such
alternate date as may be established by the BPU. For further discussion of
residential gas competition, see New Jersey Energy Master Plan Proceedings and
Related Legislation.
Electric Levelized Energy Adjustment Clause (LEAC)/Demand Side Adjustment
Factor (DSAF)
As previously reported, on April 1, 1998, the BPU approved an annualized
increase of $150.8 million in the DSAF component of the LEAC. This increase was
effective for service rendered on or after April 3, 1998. The Division of the
Ratepayer Advocate has appealed the BPU's order, seeking to overturn the BPU's
decision. Initial Briefs on Appeal were filed on October 14, 1998. PSE&G cannot
predict the outcome of that appeal. If such an appeal is successful, there could
be a material adverse impact on PSEG's and PSE&G's financial condition, results
of operations and net cash flows.
As previously reported, PSE&G's competition and rate proposal in the BPU's
restructuring proceedings provides for a transition period of seven years, with
basic tariff rates being capped and the discontinuation of the LEAC effective
December 31, 1998. That proposal also provides for recovery of mandated societal
costs, including Demand Side Management (DSM), to be adjusted based on changes
in such costs. At September 30, 1998, PSE&G had an underrecovered balance,
including interest, of approximately $146 million related to electric DSM
programs. Such amount is included in Deferred Debits on PSEG's and PSE&G's
Consolidated Balance Sheets. PSE&G estimates that the underrecovered electric
DSM balance at December 31, 1998 will be approximately $130 million. PSEG and
PSE&G cannot predict the final outcome of DSM and other mandated societal costs
recovery under the BPU's proceedings and the related legislation. Inability to
recover such amounts could have a material adverse impact on PSEG's and PSE&G's
financial condition, results of operations and net cash flows. For further
discussion of the potential impact on PSEG and PSE&G of the Energy Master Plan
proceedings, see New Jersey Energy Master Plan Proceedings and Related
Legislation.
Remediation Adjustment Charge (RAC)
On July 10, 1998, PSE&G filed a motion before the BPU requesting a $1.5
million annual increase in its RAC for the period August 1, 1997 to July 31,
1998, representing an increase on a typical residential bill of approximately
0.03%. On November 4, 1998, the BPU approved an Order adopting the Interim
Stipulation. The BPU's Order approves the rates requested on July 10, 1998 on an
interim basis, subject to refund. Any remaining issues will be either settled or
litigated and incorporated in the BPU's Final Order in this matter. PSE&G cannot
predict the outcome of this proceeding.
Other Post-Retirement Benefits (OPEB)
On October 21, 1998, the BPU ordered PSE&G to fund in an external trust its
annual OPEB obligation to the maximum extent allowable under Section 401(h) of
the Internal Revenue Code. For 1998, this amount is expected to be approximately
$12 million. Remaining OPEB costs will not be funded in an external trust, as
mandated by the BPU.
Competitive Services Audit
On August 31, 1998, the BPU mandated the commencement of an audit of
PSE&G's competitive services, including PSE&G's Appliance Service Business, to
determine whether PSE&G's competitive services have impaired or could impair
PSE&G's ability to provide safe, adequate and proper service; if
cross-subsidization exists between the regulated utility and the entity
providing competitive services; if rates for competitive services are unjust,
unreasonable, discriminatory or unduly preferential and if the utility is in
compliance with the BPU's compliance monitoring and reporting requirements. The
BPU's intention is to complete this audit by December 31, 1998, in concert with
the Energy Master Plan.
Storm Damage Investigation
On September 14, 1998, the BPU announced an investigation of the damage
caused by the September 7, 1998 storm that passed through PSE&G's territory. No
docketed proceeding has yet been initiated. The BPU has issued two series of
questions focusing on 1) reductions in workforce over the past few years, 2)
cutbacks in tree trimming over the past few years and 3) communications efforts
to affected municipalities and customers. PSE&G has responded to all of the
BPU's questions to date. PSE&G cannot predict the outcome of this investigation.
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 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 rate-making process, there will be a corresponding
increase or decrease in revenues. Accordingly, PSE&G has deferred certain costs,
which will be 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. PSE&G
continues to meet the requirements for application of SFAS 71.
As discussed in Note 2. Rate Matters, the regulatory changes proposed in
the Energy Master Plan will create a shift from regulated pricing to competitive
market pricing for electric generation. Assuming enactment of the required
enabling legislation (see Note 2. Rate Matters), these proposed changes will
limit PSEG's and PSE&G's ability to continue to meet the applicable criteria of
SFAS 71 for the generation portion of PSE&G's business. If PSE&G were to
discontinue the application of SFAS 71 and full recovery was not probable, there
would be an extraordinary, non-cash charge to operations that could be material
to the financial position and results of operations of PSEG and PSE&G.
The impact to PSEG and PSE&G will be determined based on the outcome of the
Energy Master Plan proceedings and the related legislation. While management
cannot predict the outcome of the Energy Master Plan proceedings and the related
legislative process on PSEG's and PSE&G's future financial condition, results of
operations and net cash flows, the effect could be material (see Note 2. Rate
Matters).
At September 30, 1998 and December 31, 1997, respectively, PSEG and PSE&G
had deferred the following regulatory assets on the Consolidated Balance Sheets:
<TABLE>
<CAPTION>
September 30, December 31,
1998 1997
------------------- ------------------
(Millions of Dollars)
<S> <C> <C>
Unamortized Loss on Reacquired Debt and Debt Expense.............. $140 $135
OPEB Costs........................................................ 275 289
Environmental Costs............................................... 121 122
Electric Energy and Gas Costs..................................... 69 167
SFAS 109 Income Taxes............................................. 698 725
Demand Side Management Costs...................................... 141 116
Decontamination and Decommissioning Costs......................... 39 43
Property Abandonments............................................. 25 37
Plant and Regulatory Study Costs.................................. 33 34
Oil and Gas Property Write-Down................................... 22 26
------ ------
Total Regulatory Assets...................................... $1,563 $1,694
====== ======
</TABLE>
Electric Energy and Gas Costs
Recoveries of electric energy and gas costs are determined by the BPU under
the LEAC and LGAC. PSE&G's deferred fuel balances as of September 30, 1998 and
December 31, 1997, respectively, reflect underrecovered costs as follows:
<TABLE>
<CAPTION>
September 30, December 31,
1998 1997
------------------- ------------------
(Millions of Dollars)
<S> <C> <C>
Underrecovered Electric Energy Costs...................................... $8 $91
Underrecovered Gas Fuel Costs............................................. 61 76
--- -----
Total............................................................... $69 $167
=== ====
</TABLE>
The BPU Order dated December 31, 1996 provides PSE&G the opportunity, but
not a guarantee, during the period January 1, 1997 through December 31, 1998, to
fully recover its December 31, 1996 underrecovered LEAC balance of $151 million
without any change in the current energy component of the LEAC charge.
Management believes that it will recover this amount by December 31, 1998 and
continues to follow deferred accounting treatment for the LEAC.
As previously reported, under the BPU Order dated December 31, 1996, any
underrecovered or overrecovered LEAC balance existing on December 31, 1998 will
not be considered in any LEAC review subsequent to that date. Any overrecovery
at that date is expected to be applied to reduce any potential stranded costs
and any underrecovered balance will be charged to income in the period
identified. Additionally, if PSE&G's Energy Master Plan proposal is approved,
the LEAC would be discontinued. Certain components of the LEAC would become part
of the Societal Benefits Clause under PSE&G's proposal and the proposed Energy
Competition Act. Further, discontinuance of the LEAC may cause increased
earnings volatility since PSE&G will bear the full risks and rewards of changes
in nuclear and fossil generating fuel costs and replacement power costs. No
assurances can be given as to the outcome of the New Jersey Energy Master Plan
proceedings and the related legislation.
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. PSE&G is the operator of Salem and PECO
Energy is the operator of 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 (MDC) (defined below) 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. MDC is the gross electrical output for a station measured at the
output terminals of its turbine generators during the most restrictive seasonal
conditions, less the station's service load. 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 $92 million, to be incurred from 1997 through 2001, of which $8
million was incurred in 1997 and approximately $25 million is expected to be
incurred in 1998. During the nine months ended September 30, 1998, $16 million
of costs related to Year 2000 readiness were incurred. A portion of these costs
is not likely to be incremental to PSEG or PSE&G, but rather, represents a
redeployment of existing personnel/resources.
The schedule to replace certain systems was accelerated for Year 2000
purposes. Analysis is continuing and costs identified to date are approximately
$5 million, which are not included in the estimate above. Additionally, PSE&G is
installing programs from SAP America, Inc. to replace certain major business
systems (SAP). 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 by 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 Pennsylvania--New Jersey--Maryland Interconnection (PJM), PJM
trading partners supplying power through PJM or PSEG's or PSE&G's critical
vendors and/or customers 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.
Hazardous Waste
Certain Federal and state laws authorize the U.S. Environmental Protection
Agency (EPA) and the 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. Except as discussed below
with respect to its Remediation Program, PSEG and PSE&G do not expect its
expenditures for any such site to have a material effect on their 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, among others, to develop procedures for implementing these
regulations. These regulations may substantially increase the costs of remedial
investigations and remediations, where necessary, particularly at sites located
on surface water bodies. PSE&G and predecessor companies owned and/or operated
facilities located 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 and net cash flows.
PSE&G Manufactured Gas Plant Remediation Program (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.
Air Pollution Control
As previously reported, in September 1997, NJDEP proposed 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. In June 1998, NJDEP
adopted final regulations implementing a NOx budget program and establishing the
formulas for NOx allocations. The extent of investment in control technologies
or operational changes required to comply with these regulations will be
directly related to the number of allowances PSE&G receives or is otherwise able
to acquire. PSE&G does not expect to receive its final NOx budget allocation
under the rule until the fall of 1999 and thus cannot fully assess the potential
costs at this time. One component of the potential costs is the cost of new
projects required to comply with the new regulations. The current estimate for
those new projects is $67 million, to be incurred between 2000 and 2003, which
is incremental to the Construction and Capital Requirements Forecast disclosed
in the 1997 Annual Report on Form 10-K.
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 security
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.
PSEG
Interest Rate Swap
PSEG entered into an interest rate swap on June 26, 1998 to hedge
Enterprise Capital Trust II's $150 million of Floating Rate Capital Securities,
Series B, due 2028, which were sold to a group of institutional investors in
June 1998. Enterprise Capital Trust II is a special purpose statutory business
trust controlled by PSEG. The basis for both the interest rate swap and the
Floating Rate Capital Securities is the quarterly London Interbank Offered Rate
(LIBOR). This interest rate swap effectively hedges the underlying debt for 10
years at an effective rate of 7.2%.
Energy Holdings
Equity Securities
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 fair value 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 carrying value of Resources'
portfolio as of September 30, 1998 and December 31, 1997 was $173 million and
$185 million, respectively.
PSE&G
Nuclear Decommissioning Trust Funds
Contributions made into the Nuclear Decommissioning Trust Funds are
invested in debt and equity securities. The carrying value of $469 million and
$459 million of these funds approximates their fair market value as of September
30, 1998 and December 31, 1997, respectively.
Note 6. Taxes
As previously reported, the New Jersey Gross Receipts and Franchise Tax
(NJGRT) was eliminated effective January 1, 1998 and replaced with a combination
of the New Jersey Corporate Business Tax which is a State income tax, the State
sales and use tax and a Transitional Energy Facility Assessment (TEFA), with no
material impact on the financial condition, results of operations and net cash
flows of PSEG and PSE&G. The TEFA will be phased out over five years. While
under NJGRT, PSE&G was subject to an effective state tax on unit sales equal to
approximately 13% of receipts. As a result of such tax reform, after the phase
out of the TEFA, the effective state tax rate applicable to PSE&G will be
substantially reduced. Interim rates were implemented with regard to the new tax
structure effective with service rendered on and after January 1, 1998. The BPU
completed its administrative review of the filings of all New Jersey utilities
and approved permanent rates for 1998 on July 13, 1998 in a final Order.
On September 18, 1998 and October 15, 1998, PSE&G filed with the BPU
additional information necessary to 1) reconcile its NJGRT collections to its
liability through April 1998, 2) reflect the impact of cash working capital and
net negative deferred State income taxes on a separate electric and gas basis
and 3) provide actual and estimated tax collected and tax liability through
December 31, 1998. The BPU has the ability to mandate adjustments beyond those
set forth in its July 13, 1998 Order. PSE&G does not expect these adjustments,
if any, to have a material impact on its financial condition, results of
operations and net cash flows.
Effective January 1, 1998, PSE&G became subject to the New Jersey Corporate
Business Tax, resulting in an effective income tax rate as follows:
<TABLE>
<CAPTION>
Quarter Ended Nine Months Ended
September 30, September 30,
----------------------- ---------------------------
1998 1997 1998 1997
---------- --------- ----------- -----------
<S> <C> <C> <C> <C>
Federal tax provision at statutory rate 35.0 % 35.0 % 35.0 % 35.0 %
New Jersey Corporate Business Tax, net of Federal benefit 5.9 % -- 5.9 % --
Other-- net 2.6 % (0.6)% 1.4 % (0.6)%
--------- ------- -------- ----------
Effective Income Tax Rate 43.5 % 34.4 % 42.3 % 34.4 %
========== ======= ======== ==========
</TABLE>
Note 7. Accounting Matters
In June 1997, the Financial Accounting Standards Board (FASB) issued SFAS
131, "Disclosures about Segments of an Enterprise and Related Information" (SFAS
131), which is effective for financial statements for periods beginning after
December 15, 1997. This Statement need not be applied to interim financial
statements in the initial year of its application. SFAS 131 supersedes SFAS 14,
"Financial Reporting for Segments of a Business Enterprise" and requires that
companies disclose segment data based on how management makes decisions about
allocating resources to segments and measuring their performance. Since SFAS 131
solely revises disclosure requirements, the adoption of SFAS 131 will not have a
material impact on the financial condition, results of operations and net cash
flows of PSEG or PSE&G.
In February 1998, the FASB issued SFAS 132, "Employers' Disclosures about
Pensions and Other Postretirement Benefits" (SFAS 132), which is effective for
financial statements for periods beginning after December 15, 1997. This
statement revises and standardizes disclosure requirements for pension and other
postretirement benefit plans but does not change the measurement or recognition
of those plans. Since SFAS 132 solely revises disclosure requirements, the
adoption of SFAS 132 will not have a material impact on the financial condition,
results of operations and net cash flows of PSEG and PSE&G.
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
derivative's change in fair value will be immediately recognized in earnings.
PSEG and PSE&G are currently evaluating the impact of SFAS 133 in light of the
planned issuance by the Emerging Issues Task Force (EITF) of EITF 98-10,
"Accounting for Energy Trading and Risk Management Activities". EITF 98-10 is
expected to be effective for financial statements issued after December 31,
1998. EITF 98-10 will provide guidance on accounting for energy contracts. PSEG
and PSE&G will evaluate the impact of EITF 98-10 once it is issued in final
form.
In April 1998, the American Institute of Certified Public Accountants
(AICPA) issued Statement of Position 98-5, "Reporting on the Costs of Start-Up
Activities" (SOP 98-5), which is effective for financial statements for fiscal
years beginning after December 15, 1998. 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 is not expected to have a
material impact on the financial condition, results of operations and net cash
flows of PSEG and PSE&G.
Note 8. Guaranteed Preferred Beneficial Interest in Subordinated Debentures
The Guaranteed Preferred Beneficial Interest in Subordinated Debentures
includes the monthly guaranteed preferred beneficial interest in PSE&G's
subordinated debentures and the quarterly guaranteed preferred beneficial
interest in PSEG's and PSE&G's subordinated debentures. The balances as of
September 30, 1998 and December 31, 1997 of these preferred securities are as
follows:
<TABLE>
<CAPTION>
September 30, December 31,
1998 1997
----------------- -----------------
(Millions of Dollars)
<S>
<C> <C>
Monthly Guaranteed Preferred Beneficial Interest in PSE&G's
Subordinated Debentures............................................. $210 $210
Quarterly Guaranteed Preferred Beneficial Interest in PSE&G's
Subordinated Debentures............................................. 303 303
Quarterly Guaranteed Preferred Beneficial Interest in PSEG's
Subordinated Debentures............................................. 525 --
------ ----
Total.............................................................. $1,038 $513
====== ====
</TABLE>
The increase in the Quarterly Guaranteed Preferred Beneficial Interest in
PSEG's Subordinated Debentures since December 31, 1997 is due to the issuance of
$225 million of 7.44% Trust Originated Preferred Securities, Series A by
Enterprise Capital Trust I in January 1998, of $150 million of Floating Rate
Capital Securities, Series B by Enterprise Capital Trust II in June 1998 and of
$150 million of 7.25% Trust Originated Preferred Securities, Series C by
Enterprise Capital Trust III in July 1998.
<PAGE>
- --------------------------------------------------------------------------------
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
- --------------------------------------------------------------------------------
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Concluded)
Note 9. Comprehensive Income
Effective January 1, 1998, PSEG 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. As
allowed for interim periods, PSEG has elected to disclose Comprehensive Income,
which includes net income and the effects of foreign currency translation, in
the Notes as follows:
<TABLE>
<CAPTION>
Comprehensive Income, Net of Tax:
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------------- -----------------------
1998 1997 1998 1997
----------- ------------ --------- ----------
(Millions of Dollars) (Millions of Dollars)
<S> <C> <C> <C> <C>
Net income.......................................... $180 $176 $493 $407
Foreign currency translation........................ (10) -- (22) --
---- ---- ---- ----
Comprehensive income................................ $170 $176 $471 $407
==== ==== ==== ====
</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/Organization
Note 2. Rate Matters
Note 3. Regulatory Assets and Liabilities
Note 4. Commitments and Contingent Liabilities
Note 5. Financial Instruments and Risk Management
Note 6. Taxes
Note 7. Accounting Matters
Note 8. Guaranteed Preferred Beneficial Interest in Subordinated
Debentures
Note 6. Taxes
Since PSE&G is now subject to the New Jersey Corporate Business Tax, its
effective income tax rate is as follows:
<TABLE>
<CAPTION>
Quarter Ended Nine Months Ended
September 30, September 30,
----------------------- -----------------------
1998 1997 1998 1997
--------- --------- --------- ----------
<S> <C> <C> <C> <C>
Federal tax provision at statutory rate......................... 35.0 % 35.0 % 35.0 % 35.0 %
New Jersey Corporate Business Tax, net of Federal benefit....... 5.9 % -- 5.9 % --
Other-- net..................................................... 0.9 % (0.3)% 1.4 % (0.2)%
------- ------- ------- -------
Effective Income Tax Rate................................... 41.8 % 34.7 % 42.3 % 34.8 %
======= ======= ======= =======
</TABLE>
<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) 1997 Annual
Report on Form 10-K and the Quarterly Reports on Form 10-Q for the quarters
ended March 31, 1998 and June 30, 1998 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.
Results of Operations
Basic and diluted earnings per share of PSEG common stock (Common Stock)
were $0.78 for the quarter ended September 30, 1998, representing an increase of
$0.02 or 3% per share from the comparable 1997 period. Basic and diluted
earnings per share were $2.13 for the nine months ended September 30, 1998,
representing an increase of $0.38 or 22% per share from the comparable 1997
period.
Public Service Electric and Gas Company's (PSE&G) contribution to earnings
per share of Common Stock for the quarter and nine months ended September 30,
1998 increased $0.25 and $0.46 from the comparable 1997 periods, respectively.
The increases for the quarter and nine months ended September 30, 1998 were
primarily due to increased sales of electricity resulting from considerably
warmer weather in the third quarter of 1998 augmented by positive economic
factors in New Jersey, profits realized from other wholesale power activities
and decreased operating and maintenance expenses related to the return to
service of PSE&G's Salem Nuclear Generating Station (Salem). The increase for
the nine months ended September 30, 1998 was partially offset by higher
operation expenses, including Year 2000 readiness (see Note 4. Commitments and
Contingent Liabilities of Notes and Year 2000 Issues below), and depreciation
expenses. The increases for the nine months ended September 30, 1998 were
further impacted by the one-time charge to earnings of $64 million or $0.28 per
share recorded in 1997 resulting from the settlement of lawsuits filed by the
co-owners of Salem and from profits realized from energy trading and other
wholesale power activities in 1998. For a discussion of commodity trading, see
Item 3. Qualitative and Quantitative Disclosures about Market Risk.
PSEG Energy Holdings Inc.'s (Energy Holdings) contribution to earnings per
share of Common Stock for the quarter and nine months ended September 30, 1998
decreased $0.23 and $0.08 from the comparable 1997 periods, respectively,
primarily due to lower earnings of PSEG Resources Inc. (Resources). Resources'
earnings decreased for the quarter and nine months ended September 30, 1998
primarily due to lower income from its investment portfolio as a result of the
recent downturn in the equities market (see Note 5. Financial Instruments and
Risk Management of Notes). For the nine months ended September 30, 1998, the
decrease was partially offset by a gain resulting from the exercise of an early
buyout option in the first quarter of 1998 by the lessee in one of Resources'
leveraged lease investments and increased income from new investments (see
Energy Holdings -- Earnings/(Losses)).
PSE&G -- Revenues
Electric
Revenues increased $112 million or 10% and $146 million or 5% for the
quarter and nine months ended September 30, 1998 from the comparable periods in
1997, respectively, primarily due to higher sales resulting from considerably
warmer weather in the third quarter of 1998 augmented by positive economic
factors in New Jersey (see PSE&G -- Expenses -- Interchanged Power and Fuel for
Electric Generation). These increases were partially offset by a decrease to
revenue caused by New Jersey energy tax reform in 1998 (see Note 6. Taxes of
Notes and PSE&G -- Expenses -- Income Taxes). Collection of New Jersey Gross
Receipts and Franchise Tax (NJGRT) was reflected in revenue and expense in prior
years. As a result of energy tax reform, the portion of NJGRT replaced by the
New Jersey sales and use tax is no longer reflected in revenue or expense on the
income statement. State sales and use tax is a liability of the customer,
collected by PSE&G and remitted to the State and is recorded in Tax Collections
Payable, which is included in Other Current Liabilities on the Consolidated
Balance Sheets.
Gas
Revenues decreased $73 million or 27% and $247 million or 19% for the
quarter and nine months ended September 30, 1998 from the comparable periods in
1997, respectively. The decreases were primarily due to energy tax reform (see
PSE&G -- Revenues -- Electric above) and higher therm revenues recorded in 1997
resulting from a change in estimates of unbilled gas revenue due to refinements
of PSE&G's methodology. The decrease in the nine months ended September 30, 1998
was further impacted by lower recovery of fuel costs and decreased therm sales
resulting from milder winter weather in 1998.
PSE&G -- Expenses
Interchanged Power and Fuel for Electric Generation
Interchanged Power and Fuel for Electric Generation increased $23 million
or 9% and $34 million or 5% for the quarter and nine months ended September 30,
1998 from the comparable 1997 periods, respectively, primarily due to increased
sales of electricity resulting in increased purchases of fuel for electric
generation and purchases of power from the Pennsylvania-New Jersey-Maryland
Interconnection (PJM) pool. Effective January 1, 1998, the amount included for
Electric Levelized Energy Adjustment Clause (LEAC) under/overrecovery represents
the difference between fuel-related revenues and fuel-related expenses which are
comprised of the cost of generation and interchanged power at the PJM market
clearing price. Effective April 1, 1998, PJM, as independent system operator
(ISO), replaced the PJM uniform market clearing price with locational marginal
pricing (LMP) for determining the market clearing pricing to energy providers
(see Competitive Environment - PJM). Experience to date shows no material
adverse impact of this change to LMP on PSE&G's cost of Interchanged Power and
Fuel for Electric Generation. 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.
Effective July 1, 1998, energy trading purchases are netted against energy
trading revenue and gains/(losses) on such trading activity are presented in
Operating Revenues -- Electric on the Consolidated Statements of Income. There
was no impact on net income resulting from this reclassification (see Note 1.
Basis of Presentation/Organization of Notes).
Income Taxes
PSE&G became subject to New Jersey State income tax, effective January 1,
1998, due to energy tax reform in the State of New Jersey (see Note 6. Taxes of
Notes). Income Taxes increased $71 million or 85% and $120 million or 52% for
the quarter and nine months ended September 30, 1998 from the comparable 1997
periods, respectively. These increases are primarily due to the inclusion of
State income tax of $34 million and $90 million for the quarter and nine months
ended September 30, 1998, respectively. In the quarter and nine months ended
September 30, 1998, there were increases of $37 million and $30 million from the
comparable 1997 periods in Federal income taxes, respectively, due to higher
pre-tax operating income.
Transitional Energy Facility Assessment (TEFA) / New Jersey Gross Receipts
and Franchise Tax (NJGRT)
TEFA/NJGRT decreased $91 million or 69% and $293 million or 70% for the
quarter and nine months ended September 30, 1998 from the comparable 1997
periods, respectively, due to New Jersey energy tax reform. For 1998, the amount
represents TEFA unit-based taxes while the 1997 amount represents NJGRT
unit-based taxes. The TEFA unit tax rates are approximately 30% of the NJGRT
unit tax rates. See PSE&G -- Revenues and Income Taxes, above, and Note 6. Taxes
of Notes for other impacts of New Jersey energy tax reform.
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 Issues, below.
<PAGE>
Energy Holdings -- Earnings/(Losses)
<TABLE>
<CAPTION>
Increase (Decrease) Increase (Decrease)
-------------------------- -------------------------
Quarter Ended Nine Months Ended
September 30, September 30,
1998 vs. 1997 1998 vs. 1997
-------------------------- -------------------------
(Millions of Dollars)
<S> <C> <C>
Resources $(48) $(12)
PSEG Global Inc. (Global) (6) (7)
PSEG Energy Technologies Inc. (Energy Technologies) - (1)
------ -----
Total $(54) $(20)
====== =====
</TABLE>
Energy Holdings had net losses of $35 million for the quarter ended
September 30, 1998 compared to net earnings of $19 million for the same period
in 1997, representing a decrease of $54 million. Energy Holdings had net
earnings of $13 million for the nine months ended September 30, 1998 compared to
$33 million for the same period in 1997, representing a decrease of $20 million.
These decreases were primarily due to Resources' lower income from its
investments. The effects on PSEG's and Energy Holdings' earnings resulting from
fluctuations in the fair value of these investments for the quarter and nine
months ended September 30, 1998 were unrealized losses of $67 million and $22
million, respectively, compared to unrealized gains of $7 million and $15
million for the same periods of 1997, respectively (see Note 5. Financial
Instruments and Risk Management). Continuing volatility in the equities markets
may also impact PSEG's and Energy Holdings' financial condition, results of
operations and net cash flows. The results for the nine months ended September
30, 1998 were partially offset by a gain resulting from the exercise of an early
buyout option in the first quarter of 1998 by the lessee in a leveraged lease
and increased income from new investments.
Liquidity and Capital Resources
PSEG
PSEG is a 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
subsidiaries, PSE&G and Energy Holdings.
Cash generated from PSE&G's operations is expected to provide the major
source of funds for PSE&G's business. Energy Holdings' growth will be funded
through external financings, cash generated from operations and equity capital.
Dividend payments on Common Stock were $1.62 per share and totaled
approximately $376 million for the nine months ended September 30, 1998 and
1997, 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 and related legislation and PSEG's and PSE&G's response thereto
(see Note 2. Rate Matters and Note 3. Regulatory Assets and Liabilities of
Notes), the receipt of dividend payments from its subsidiaries and other
factors. PSE&G paid common dividends of approximately $376 million and
approximately $391 million to PSEG during the nine months ended September 30,
1998 and 1997, respectively. Changes in PSE&G's financial condition that could
result from the Energy Master Plan proceedings and related legislation could
have a material adverse effect on the ability to maintain the dividend at such
level (see PSE&G below). Due to the growth in Energy Holdings' investment
activities, no dividends on Energy Holdings' common stock were paid in the nine
months ended September 30, 1998 and 1997 or are anticipated for the remainder of
1998. Energy Holdings paid $12 million of dividends related to its preferred
stock issued to PSEG for the nine months ended September 30, 1998. Energy
Holdings had no preferred stock outstanding in the period ended September 30,
1997.
On September 15, 1998, in anticipation of securitization of PSE&G's
stranded costs afforded by the proposed Energy Competition Act and the ALJ's
decision, the Board of Directors of PSEG authorized the repurchase of up to 10
million shares of Common Stock. Under the authorization, repurchases will be
made in the open market at the discretion of PSEG. Until the expected
securitization process in connection with the Energy Master Plan occurs, the
Common Stock repurchase will be funded by PSEG debt with the repurchased shares
held as treasury stock. At September 30, 1998, PSEG had repurchased
approximately 2.4 million shares of Common Stock at a cost of $91 million, under
this authorization.
PSEG issued a total of $300 million of tax deductible preferred securities
in June and July 1998. The proceeds of the sales were used to invest an
additional $292 million in Energy Holdings, which made additional equity
investments in Global and Resources.
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,
respectively, has defaulted on an indenture related thereto or its guarantee
thereof, neither PSEG nor PSE&G, respectively, may pay any dividends on its
common or preferred stock.
As of September 30, 1998, PSEG's capital structure consisted of 48% common
equity, 41% long-term debt and 11% preferred stock and other preferred
securities.
As a result of the 1992 focused audit of PSEG's non-utility businesses
(Focused Audit), the New Jersey Board of Public Utilities (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 September 30, 1998 were
approximately 16% of assets); (2) the PSE&G Board of Directors will provide an
annual certification that the business and financing plans of Energy Holdings
will not adversely affect PSE&G; (3) PSEG will (a) limit debt supported by the
minimum net worth maintenance agreement between PSEG and PSEG Capital
Corporation (PSEG Capital), a wholly-owned subsidiary of Energy Holdings, to
$750 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. Beginning in 1995, the debt supported
by such minimum net worth maintenance agreement was limited to $650 million and
the affiliation fee has been proportionately reduced as such supported debt is
reduced. PSEG and Energy Holdings and its subsidiaries continue to reimburse
PSE&G for the cost of all services provided to them by employees of PSE&G.
As a result of PSEG's intent that Energy Holdings and its subsidiaries
provide growth vehicles for PSEG, financing requirements connected with the
continued growth of Energy Holdings, changes to the utility industry expected
from the final outcome of the Energy Master Plan proceedings and the related
legislation and potential accounting impacts resulting from the deregulation of
the generation of electricity, modifications will be required to certain of the
restrictions agreed to by PSEG with the BPU in response to the Focused Audit.
Inability to achieve satisfactory resolution of these matters could impact the
future relative size and financing of Energy Holdings and accordingly, PSEG's
future prospects, including financial condition, results of operations and net
cash flows (see Note 2. Rate Matters and Note 3. Regulatory Assets and
Liabilities of Notes).
PSE&G
Capital resources and capital requirements may be affected by the outcome
of the Energy Master Plan proceedings and related legislation. For a discussion
of the potential impact of the Energy Master Plan proceedings and related
legislation on PSE&G's future prospects, including financial condition, results
of operations and net cash flows, see Note 2. Rate Matters and Note 3.
Regulatory Assets and Liabilities of Notes.
For the nine months ended September 30, 1998, PSE&G had utility plant
additions, including Allowance for Funds Used During Construction, of $368
million, a $27 million decrease from the corresponding 1997 period. The decrease
was primarily due to the replacement of Salem 1 steam generators in 1997. PSE&G
expects that it will be able to generate all of its construction and capital
requirements over the next five years internally, assuming adequate and timely
recovery of costs, as to which no assurances can be given.
Energy Holdings
In June and July 1998, PSEG invested $147 million and $145 million,
respectively, in Energy Holdings which issued to PSEG like amounts of its 4.80%
and 4.875% Cumulative Preferred Stock and made additional equity investments in
Global and Resources. PSEG funded its additional investment in Energy Holdings
through the sale of tax deductible preferred securities (see External
Financings).
In July 1998, Global sold its 5% interest in a domestic cogeneration plant
and in August 1998, sold its 50% interest in a natural gas-fired generating
station in Colombia. The aggregate proceeds from these sales of $68 million
approximated Global's book value.
In July 1998, Resources purchased a 33.3% interest in a leveraged lease of
a natural gas-fired generating station in the United Kingdom for approximately
$40 million and in September 1998, purchased a 100% interest in a leveraged
lease of several gas distribution networks in the Netherlands for approximately
$45 million.
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 interest rates may affect PSEG's and Energy
Holdings' financial condition, results of operations and net cash flows.
External Financings
PSEG
On September 30, 1998, PSEG had a $25 million line of credit with a bank
with no debt outstanding under this line of credit. Also, at that date, PSEG had
a committed $150 million revolving credit facility which expires in December
2002 with $100 million outstanding under this facility. In addition, PSEG has
$200 million of debt registered on a registration statement which is effective
and has filed a registration statement for an additional $150 million of debt
which registration statement has not yet become effective.
In June 1998, Enterprise Capital Trust II, a special purpose statutory
business trust controlled by PSEG, issued $150 million of its Floating Rate
Capital Securities, Series B. At the time of issuance, PSEG's floating rate
obligation under its debentures was swapped for a fixed rate payment resulting
in an effective rate of 7.2% (see Note 5. Financial Instruments and Risk
Management of Notes). In July 1998, Enterprise Capital Trust III, a special
purpose statutory business trust controlled by PSEG, issued $150 million of its
7.25% Trust Originated Preferred Securities, Series C. Proceeds of both issues
were lent to PSEG and are evidenced by its deferrable interest subordinated
debentures. PSEG used the proceeds of these issues to make $292 million
preferred equity investments in Energy Holdings. The debentures and their
related indentures constitute a full and unconditional guarantee by PSEG of the
preferred securities issued by the trusts. If, and for as long as, payments on
PSEG's debentures have been deferred, or PSEG has defaulted on the indentures
related thereto or its guarantee thereof, PSEG may not pay any dividends on its
Common Stock (see Liquidity and Capital Resources -- PSEG).
As previously disclosed, both PSEG and PSE&G have issued a total of
approximately $525 million and $513 million, respectively, of deferrable
interest subordinated debentures which are treated as debt to the issuer for
Federal income tax purposes and as preferred equity for financial accounting and
rating agency purposes. In a case not involving PSEG or PSE&G, the Internal
Revenue Service (IRS) has proposed to disallow interest deductions claimed by
Enron Corp. (Enron) on two issues of similar long-term subordinated debentures.
That issue is now in litigation (Enron Corp. v. Commissioner, Tax Court Docket
No. 6149-98). There can be no assurance that Enron will prevail in this
litigation if it is not settled or, if Enron does prevail, that the IRS
nevertheless may seek to disallow the deductions that PSEG and PSE&G have taken
and will claim for interest paid on such debentures. The annualized interest
expense for these debentures for PSEG and PSE&G together is approximately $83
million. In total for 1994 through 1997, PSEG and PSE&G claimed approximately
$89 million in interest deductions for these debentures, which equates to
approximately $31 million in tax benefits. If challenged by the IRS, PSEG and
PSE&G would expect to vigorously defend the deductibility of the interest
payments taken as deductions on previously filed Federal tax returns. In the
event of the occurrence of a Tax Event as defined in the respective debenture
indentures, such as the receipt of an opinion of counsel that there is a more
than insubstantial risk that interest payable on the debentures will not be tax
deductible, PSEG and PSE&G have the right to redeem the preferred securities and
issue the debentures to the preferred securities holders or to refinance such
obligations as allowed in the respective debenture indentures.
<PAGE>
PSE&G
PSE&G has authority from the BPU, through December 31, 1998, to
opportunistically refinance essentially all of its long-term debt and to refund
up to $250 million of matured debt. PSE&G expects to be able to obtain BPU
approval to extend the authorization to opportunistically refinance essentially
all of its long-term debt through January 4, 2000.
Under its First and Refunding Mortgage (Mortgage), PSE&G may issue new
First and Refunding Mortgage Bonds (Bonds) against previous additions and
improvements and/or retired Bonds provided that its ratio of earnings to fixed
charges is at least 2:1. At September 30, 1998, the coverage ratio under PSE&G's
Mortgage was 4.19:1. As of September 30, 1998, the Mortgage would permit up to
approximately $3.5 billion aggregate principal amount of new Bonds to be issued
against previous additions and improvements.
In April 1998, $8 million of PSE&G's 7.50% Bonds, Series OO, were purchased
in the open market. On August 3, 1998, the remaining outstanding $234 million of
the Series OO Bonds were redeemed.
In May 1998, PSE&G sold $250 million of its Bonds, Remarketable Series YY,
due 2023, Mandatorily Tendered 2008. The Series YY Bonds will bear interest at
the rate of 6.375% per annum until May 1, 2008. PSE&G also entered into a
Remarketing Agreement with a third party that granted the third party the option
to call and remarket the Series YY Bonds on May 1, 2008 for the remaining term
of the Series YY Bonds. If not called by the third party, the Bonds must be put
by the holders to PSE&G. The proceeds of the sale were used primarily to redeem
PSE&G's Series OO Bonds.
On July 1, 1998, $18 million of PSE&G's 6% Debenture Bonds matured.
To provide liquidity for its commercial paper program, PSE&G has a $650
million revolving credit agreement expiring in June 1999 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 September 30, 1998,
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 2, 1999, not more than $1.3 billion of short-term obligations,
consisting of commercial paper and other unsecured borrowings from banks and
other lenders. On October 5, 1998, PSE&G filed a petition with the BPU to
increase this authorization to $1.5 billion and extend it through January 4,
2000. PSE&G expects a BPU decision before December 31, 1998. An inability to
issue short-term obligations would have a material adverse impact on PSEG's and
PSE&G's financial condition, results of operations and net cash flows. On
September 30, 1998, PSE&G had $996 million of short-term debt outstanding,
including $124 million borrowed against its uncommitted bank lines of credit
which lines of credit totaled $124 million at that date.
PSE&G Fuel Corporation (Fuelco), a wholly-owned subsidiary of PSE&G, has a
$125 million commercial paper program to finance its 42.49% share of Peach
Bottom nuclear fuel, which program is supported by a $125 million revolving
credit facility expiring on June 28, 2001. PSE&G has guaranteed repayment of
Fuelco's obligations under this program. At September 30, 1998, Fuelco had $86
million of commercial paper outstanding under this program.
Energy Holdings
At September 30, 1998, PSEG Capital had total debt outstanding of $521
million, including $498 million of Medium Term Notes (MTNs) and $23 million of
Senior Notes. In July 1998, $75 million of PSEG Capital's 9.00% MTNs matured. As
a result of the Focused Audit, PSEG Capital debt is to be phased out over a six
to ten year period from April 1993 (see Liquidity and Capital Resources).
As of September 30, 1998, Enterprise Capital Funding Corporation (Funding),
a wholly-owned subsidiary of Energy Holdings, had $150 million and $300 million
revolving credit facilities expiring in November 1998 and July 1999,
respectively, with two groups of banks, under which $24 million was outstanding
as of September 30, 1998. Funding expects to be able to renew both credit
agreements and has reached preliminary agreement with a group of banks to renew
for one year the facility expiring in November 1998. As of September 30, 1998,
Funding had $69 million of total debt outstanding, including $45 million of
privately placed Senior Notes.
Energy Holdings, Resources and Global are subject to restrictive business
and financial covenants contained in existing debt agreements. Energy Holdings
is required to maintain a debt to equity ratio of no more than 2.00:1 and a
twelve-months earnings before interest and taxes to interest (EBIT) coverage
ratio of at least 1.50:1. As of September 30, 1998, Energy Holdings had a
consolidated debt to equity ratio of 0.78:1. For the twelve months ended
September 30, 1998, the EBIT coverage ratio, as defined to exclude the effects
of EGDC, was 1.79:1. Compliance with applicable financial covenants will depend
upon future financial position and levels of earnings, as to which no assurance
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 (see Liquidity and
Capital Resources).
Nuclear Operations
As previously reported, PSE&G's Salem Units 1 and 2 (Salem 1 and 2)
returned to service on April 17, 1998 and August 30, 1997, respectively. On June
30, 1998, the Nuclear Regulatory Commission (NRC) closed its Confirmatory Action
Letter (CAL) concerning Salem noting that all commitments of the CAL had been
satisfactorily addressed. For a discussion of the operating performance standard
applicable to Salem, see Note 4. Commitments and Contingent Liabilities of
Notes.
At the July 1998 semi-annual NRC Senior Management Meeting, the NRC removed
Salem 1 and 2 from the NRC Watch List. The NRC noted that plant material
condition, safety culture and management oversight and effectiveness had
substantially improved. The NRC also observed that, while the maintenance
backlog resulting from discovery efforts during the outage remains high, PSE&G
is effectively managing the prioritization and resolution of those items.
Additionally, the NRC noted that PSE&G's management team has instituted robust
safety oversight and self-assessment at the site and that Salem has demonstrated
sustained successful plant performance.
Foreign Operations
In accordance with its growth strategy, Global has made approximately $860
million of international investments, primarily in Brazil, Argentina and China,
in projects that generate and distribute electricity. These investments
represent approximately 5% of PSEG's assets. As a primary vehicle for growth,
Global is expected to continue to emphasize international investments. Where
possible, Global structures its investments to manage the risk associated with
project development, including foreign currency devaluation and fluctuations.
PSEG has evaluated the current economic turmoil in these regions, including
potential devaluations of currencies affecting the emerging markets in which
Global invests, and has determined that although short-term growth in demand may
be negatively impacted, the long-term outlook for investments made to date has
not been impaired. However, PSEG cannot predict what impact further developments
in emerging market financial conditions may have on its financial condition,
results of operations and net cash flows.
Competitive Environment
State Regulatory Matters
For discussions of the New Jersey Energy Master Plan proceedings and
related legislation, non-utility generation buydown, the LGAC, the Gas
Unbundling Pilot Program, the LEAC/Demand Side Adjustment Factor, the RAC and
other rate matters, see Note 2. Rate Matters of Notes. The outcome of these
proceedings could have a material adverse impact on PSEG's and PSE&G's financial
condition, results of operations and net cash flows.
Federal Energy Regulatory Commission (FERC)
As previously reported, numerous parties, including PSE&G, have filed
petitions for judicial review of Orders No. 888, 888A and 888B before the Courts
of Appeals for the District of Columbia and the Second Circuits. In March 1998,
all of these appeals were consolidated in the Court of Appeals for the District
of Columbia Circuit (D.C. Circuit). On April 30, 1998, the D.C. Circuit entered
an order permitting certain additional parties to intervene and establishing
certain procedural guidelines for the hearing of these appeals. Briefs were
filed on October 1, 1998. Oral argument has not yet been scheduled.
Pennsylvania--New Jersey--Maryland Interconnection
On October 15, 1998, PJM began operating a centralized capacity credit
market, providing a new option to participants for procuring capacity to meet
capacity obligations within the PJM Control Area. Capacity is the capability to
produce electric power, typically from owned generation or third party purchase
contracts and differs from the electric energy markets, described below, which
trade the actual power being generated. A centralized capacity credit market
enables a participant to trade its capacity not required to meet its capacity
obligations for reliability purposes. The market facilitates the selling and
buying of capacity for participants by providing a single point of contact for
market participants and a published capacity market clearing price. The design
of the PJM capacity market is compatible with the already existing bilateral
capacity market and does not preclude any market participant from using the
generation it owns to satisfy its capacity obligations. PJM will accept offers
to buy and sell capacity credits, centrally clear the market and post the market
clearing prices for these credits. PSE&G will continue offering capacity for
sale through bilateral transactions and will also participate in the centralized
PJM capacity market.
Effective April 1, 1998, PJM implemented LMP to establish the market
clearing prices for energy and to price energy transactions when there are
congested areas within the PJM control area pursuant to FERC requirements. LMP
provides for an efficient allocation of congestion costs to transmission users
within the PJM control area based on system use. Experience to date shows no
material adverse impact as a result of the change to LMP on PSE&G's cost of
Interchanged Power and Fuel for Electric Generation. PSE&G does not anticipate
any material impact due to the implementation of LMP in the future.
On December 31, 1997, the PJM Supporting Companies filed market
enhancements with the FERC. PSE&G, one of the Supporting Companies, supports the
filing which includes the ability to auction residual and released Fixed
Transmission Rights, which are a financial hedge against congestion costs. It
also includes a multi-settlement system and provides a day-ahead settlement for
energy, which allows market participants to "lock-in" energy prices a day ahead
and only pay for the deviations from the amounts settled one day ahead at the
real-time energy price. As proposed, these systems would all be administered by
the PJM ISO.
Currently, the PJM Operating Agreement dictates that 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.
Transactions that are bid into the PJM pool from generation located outside the
PJM control area are capped at $1,000 per megawatt hour. All power providers are
paid at the PJM LMP under normal market operations. In the event that all
available generation within the PJM control area is insufficient to cover
demand, PJM could institute emergency purchases from adjoining regions. The cost
of such emergency purchases is dependent upon market conditions and not subject
to any PJM price cap. Certain of the PJM member companies have requested the
FERC to revise the PJM Operating Agreement to allow submission of market based
bids to the PJM interchange energy market. PSEG and PSE&G cannot predict the
outcome of this request or the impact on PSEG's and PSE&G's future financial
condition, results of operations and net cash flows if such request is
successful. For further discussion of price volatility of electricity, see Item
3.Qualitative and Quantitative Disclosures About Market Risk.
Year 2000 Issues
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's and PSE&G's Year 2000 readiness program addresses issues relating to
three principal types of systems:
Information technology systems, which include such business
applications as the customer information, administrative and "back
office" systems.
Process control systems, which include embedded devices as well as
real time systems such as energy management systems (EMS) and the
supervisory control systems for gas and electric (SCADA).
Infrastructure systems, which include such devices as servers,
routers, etc.
Inventory is more than 70% complete for all information technology, process
control and infrastructure systems. Substantial Assessment work has been
completed on the information technology, infrastructure systems and process
control systems. Remediation/Testing is in progress on information technology,
process control and infrastructure systems.
PSEG and PSE&G expect to complete required Year 2000 readiness work for
more than 50% of their critical systems by the end of 1998. The work required by
the remaining critical systems is expected to be completed by July 1999, except
for certain systems operated by PSE&G's Nuclear Business Unit (NBU), as
discussed below. By the end of 1999, a majority of PSEG's and PSE&G's
non-critical systems are 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
requiring submission of a written response within 90 days of that date
indicating whether or not nuclear plant operators have pursued and continue to
pursue Year 2000 programs and addressing the programs' 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 operators' Year 2000
program or no later than July 1, 1999 confirming that their facilities are Year
2000 ready, or will be Year 2000 ready, by 2000 with regard to compliance with
the terms and conditions of their licenses and NRC regulations. On July 23,
1998, PSE&G provided its written response to the first requirement noted above,
outlining for the NRC its NBU Year 2000 program and indicating that planned
implementation will allow the NBU to be Year 2000 ready and in compliance with
the terms and conditions of its licenses and NRC regulation by January 1, 2000.
As of September 30, 1998, PSE&G's NBU Year 2000 effort is on schedule.
Additionally, at a meeting held on September 29, 1998, PECO informed PSE&G that
Peach Bottom's Year 2000 effort is on schedule to meet the July 1999 NRC
response schedule. The NRC has recently begun audits of a representative sample
of operating nuclear power plants, including Hope Creek, to spot check measures
that licensees are taking to assure that key computer systems will be able to
function in 2000.
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). Sufficient information has not yet been received from
all key vendors to confirm their preparedness for Year 2000. PSEG and PSE&G are
aggressively pursuing the key vendors who have been unresponsive. However, PSEG
and PSE&G are not yet able to determine whether all of their key vendors will be
able to meet Year 2000 requirements. Failure of key vendors to meet these
requirements 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
The North American Electric Reliability Council (NERC) has been asked by
the Department of Energy (DOE) to lead national efforts for electric utility
industry Year 2000 readiness. In its report issued in September 1998, NERC
evaluated potential risks for the industry from both an impact and probability
basis. PSEG's and PSE&G's internal analyses of the risks posed by the Year 2000
are consistent with the risk assessment prepared by NERC. PSEG and PSE&G expect
that the Year 2000 project (specifically remediation and contingency planning
efforts) will mitigate these risks and allow PSEG and PSE&G to meet their
fiduciary, regulatory and safety commitments.
The following risks defined by NERC were assumed only for the purpose of
planning and preparing for operations. None of the risks identified in this plan
are predictions of Year 2000 events:
NERC NERC
Probability Impact
NERC Defined Scenario for Industry for Industry
- ------------------------------------------------------------- -----------------
Loss of generation High High
- ------------------------------------------------------------- -----------------
Loss of EMS, SCADA Systems High High
- ------------------------------------------------------------- -----------------
Loss of leased communications lines High High
- ------------------------------------------------------------- -----------------
Generation Restart/Loss of Load/Unusual load High Low
- ------------------------------------------------------------- -----------------
Environmental control or monitoring Medium Medium
- ------------------------------------------------------------- -----------------
Loss of internal communications Medium Medium
- ------------------------------------------------------------- -----------------
Loss of gas or oil supply Medium High
- ------------------------------------------------------------- -----------------
Sabotage Medium High
- ------------------------------------------------------------- -----------------
Distribution system failure/DC Tie Low High
Failure/Under-frequency or under-frequency
voltage load shed failure/Loss of system
protection/Loss of transmission/Loss of
security coordinator functions
- ------------------------------------------------------------- -----------------
Voltage control device failure Low High
- ------------------------------------------------------------- -----------------
Loss of control center access Low Medium
- ------------------------------------------------------------- -----------------
Loss of coal Low Medium
- ------------------------------------------------------------- -----------------
Operating Personnel/Generation and Low Low
Transmission Information Sharing
System (OASIS) Failure/Loss of
non-critical operating data/DSM
failure/Supplies
- ------------------------------------------------------------- -----------------
PSEG's and PSE&G's efforts have focused on reducing the "High" and "Medium"
probability scenarios and mitigating the effects of "High" and "Medium" impacts.
PSEG and PSE&G 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.
Future Year 2000 related liabilities will be determined through the courts and
the overall risk cannot be determined at this time. PSEG and PSE&G have not been
subject to specific or general Year 2000 regulatory action, other than
responding to inquiries from regulatory bodies such as the BPU and the NRC.
Contingency Plans
PSEG and PSE&G are in the process of developing contingency plans in
accordance with NERC guidelines. The cornerstone of NERC's guidance is to use a
"defense in depth" strategy by creating multiple defense barriers to reduce the
risk of catastrophic results to extremely small probability levels. Other areas
covered by NERC and PSEG's and PSE&G's responses include:
NERC Guidance PSEG's and PSE&G's Contingency Plan
- ----------------------------------- ----------------------------------------
Identify and fix known Year 2000 PSEG and PSE&G have focused their
problems. resources on the remediation of
non-compliant systems.
- ----------------------------------- ----------------------------------------
Identify most probable and PSEG and PSE&G are currently evaluating.
credible worst case scenarios.
- ----------------------------------- ----------------------------------------
Plan for the probable, prepare PSEG and PSE&G will develop special
for the worst. Develop special procedures and will conduct both
operating procedures, conduct internal drills and participate in
training and system wide drills. industry efforts.
- ----------------------------------- ----------------------------------------
Operate systems in a precautionary PSEG & PSE&G are working with the
posture during critical Year 2000 Mid-Atlantic Area Council (MAAC) and
periods. This may include reducing with PJM for detailed planning.
voluntary bulk transfers, ensuring
that adequate generation facilities
are in service and increasing
staffing.
- ----------------------------------- ----------------------------------------
The nature of contingency plans will include 1) using existing redundant
assets, such as PSE&G's mix of generating assets; 2) leveraging existing
business continuity plans, such as storm preparedness plans; 3) manual
work-arounds; and 4) using rapid-reaction teams. PSEG and PSE&G's emerging
strategy calls for the deployment of these plans in the following manner (using
risk scenarios shown above that NERC evaluated to have a high probability and a
high impact):
Scenario Initial Plan
- -------------------------- ---------------------------------------------
Loss of generation. Use existing redundant assets. Have available
a varied mix of generating assets, with
sufficient reserve capacity, to ensure that
if certain stations are unable to function,
the reserve can meet generating needs.
- -------------------------- ---------------------------------------------
Loss of EMS, SCADA Systems Use manual work-arounds and rapid reaction
teams.
- -------------------------- ---------------------------------------------
Loss of leased communications Use existing redundant assets such as
lines. existing radio and back-up communications
systems.
- -------------------------- ---------------------------------------------
PSEG and PSE&G have adopted NERC's timetable, guidelines and detailed
requirements for developing these contingency plans. PSEG and PSE&G expect to
have their preliminary contingency plans completed by December 31, 1998 with the
second version of their contingency plans completed by June 30, 1999, consistent
with NERC's timetable. PSEG and PSE&G will participate, with internal drills to
be completed beforehand, in NERC's industry-coordinated Year 2000 readiness
drills on April 8-9, 1999 and September 8-9, 1999. PSEG and PSE&G will evaluate
plan updates, as needed, from September 1999 through January 2000.
PSEG and PSE&G expect that with completion of the Year 2000 project and
implementation of SAP (see Note 4, Commitments and Contingent Liabilities of
Notes), 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 or PSEG's or PSE&G's critical vendors and/or customers 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.
Future Outlook
PSEG continues to pursue its strategies to grow its business. As previously
reported, more emphasis will be placed on finding opportunities for expansion
outside of traditional utility services and markets. PSE&G's strategy is to size
its electric generation fleet in New Jersey to meet its anticipated needs, while
seeking to increase its value through wholesale trading. PSE&G will also seek to
capitalize on synergies which may exist with its natural gas purchasing and
trading activities. PSE&G's transmission and distribution strategy, both gas and
electric, is to provide cost-effective, high quality service. PSEG will also
consider opportunities for expansion through business combinations. Global's
strategy is to invest in both generation and transmission and distribution
facilities worldwide with the goal of creating long-term value. Resources'
strategy is to continue focusing on passive investments in the energy sector
worldwide seeking to provide earnings and economic value. Energy Technologies'
strategy is to expand upon the current energy related services it provides to
industrial and commercial customers to create long-term value.
Successful implementation of these strategies, coupled with the
restructuring of the electric industry (see Note 2. Rate Matters and Note 3.
Regulatory Assets and Liabilities of Notes), could significantly change the
organizational structure of the PSEG family of businesses as well as PSEG's
earnings mix. Also significant among the changes in the earnings mix would be a
reduction in the percentage of earnings from the domestic generation business
and an increase from the international generation, transmission and distribution
businesses, and to a lesser extent, from the energy services business. As a
result of the deregulation of the electric industry, PSE&G may be required to
separate its electric generation services, and potentially other competitive
services, from its regulated utility operations and transfer those operations to
an entity functionally independent from PSE&G. To the extent that recovery of
stranded costs occasioned by deregulation are not probable of recovery and not
eligible for deferred accounting treatment under SFAS 71, PSE&G would incur an
extraordinary, non-cash charge to operations, which charge could be material to
the financial position and results of operations of PSEG and PSE&G (see Note 3.
Regulatory Assets and Liabilities).
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: Results of Operations; Liquidity and Capital Resources;
External Financings; Nuclear Operations; Foreign Operations; Competitive
Environment; Year 2000 Issues and Future Outlook.
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
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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; an increasingly competitive energy marketplace; sales retention
and growth potential in a mature service territory and a need to contain costs;
ability to obtain adequate and timely rate relief, cost recovery, including the
potential impact of 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; 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.
<PAGE>
ITEM 3. QUALITATIVE AND QUANTITATIVE
DISCLOSURES ABOUT MARKET RISK
Commodities
The availability and price of energy commodities are subject to
fluctuations from factors such as weather, environmental policies, changes in
demand, changes in supply and state and Federal regulatory policies. To reduce
price risk caused by market fluctuations, PSE&G enters into physical forward and
options contracts and financial derivatives including forwards, futures, swaps
and options with approved counterparties, to hedge its anticipated demand. These
contracts, in conjunction with owned electric generating capacity, are designed
to cover estimated electric and gas customer commitments. Gains and losses
resulting from physical forward and options contracts and financial derivatives
are recognized as a component of net electric revenue upon maturity of these
contracts. Additionally, PSE&G enters into physical forward and options
contracts that are speculative in nature which are immaterial to PSE&G's market
portfolio and do not have a material impact on PSE&G's financial condition,
results of operations and net cash flows.
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 percent
confidence level and assuming a one week horizon at September 30, 1998 was
approximately $8 million, which is significantly less than the June 30, 1998
level of $18 million due to the expiration of summer 1998 positions and their
associated volatilities. 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.
As discussed in Results of Operations of Item 2. Management's Discussion
and Analysis, energy trading operations at PSE&G positively impacted the results
of operations for the nine months ended September 30, 1998. Certain other
utilities and power marketers have experienced significant losses in their
energy trading operations during that period. These losses were primarily
attributable to extreme market volatility and counterparty defaults that
resulted.
PSEG is exposed to credit losses in the event of non-performance or
non-payment by counterparties. PSEG has a Risk Management Committee made up of
executive officers and an independent risk oversight function to enhance its
risk management practices. 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.
<PAGE>
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PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
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PUBLIC SERVICE ELECTRIC AND GAS COMPANY
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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) 1997 Annual Report on Form 10-K and the Quarterly Reports on
Form 10-Q for the quarters ended March 31, 1998 and June 30, 1998 is updated
below.
(1) Form 10-K, Pages 19-20 and June 30, 1998 Form 10-Q, Page 27. As
previously reported, PSE&G has been named as a potentially responsible
party and alleged to be liable for contamination at the Metal Bank
Cottman Avenue Superfund Site, a former non-ferrous scrap reclamation
facility located in Philadelphia, Pennsylvania. PSE&G estimates that
its share of the cost of performing the remedy selected by the U.S.
Environmental Protection Agency (EPA) could be $4 to $8 million. On
June 26, 1998, EPA Region III issued an Administrative Order For
Remedial Design And Remedial Action, Docket No. III-98-082-DC, to
thirteen Respondents including PSE&G, other utilities, and other
persons and entities, ordering the Respondents to implement the remedy
selected in the Record of Decision (ROD) issued by EPA Region III in
December, 1997. Additionally, with respect to this site, on July 1,
1998, the United States of America moved in the matter entitled United
States of America, et al, v. Union Corporation, et al, Civil Action
No. 80-1589, United States District Court for the Eastern District of
Pennsylvania, seeking leave of court to file an amended complaint
adding claims under the Federal Comprehensive Environmental Response,
Compensation and Liability Act of 1980 (CERCLA). PSE&G and one other
utility are third party defendants in the foregoing captioned matter.
On July 28, 1998, PSE&G and seven other utilities named as Respondents
in the above-referenced Administrative Order filed with EPA Region III
a Notice of Intent to Comply With Administrative Order for Remedial
Design and Remedial Action, Metal Bank Cottman Avenue Site, Docket No.
III-98-082-DC.
(2) Form 10-K, Page 27, March 31, 1998 Form 10-Q, Page 24 and June 30, 1998
Form 10-Q, Page 27. As previously reported, in October 1995, PSEG
received a letter from a representative of a purported shareholder
demanding that it commence legal action against certain of its officers
and directors with regard to nuclear operations of Salem and Hope Creek
Nuclear Generating Stations (Salem and Hope Creek). The Board of
Directors promptly commenced an investigation and advised the purported
shareholder thereof. While the investigation was pending, the purported
shareholder nevertheless commenced, by complaint filed in December
1995, a shareholder derivative action against the then incumbent
directors, except Dr. Remick. Similar derivative complaints were filed
by two profit sharing plans and one individual in February and March
1996 against Messrs. Ferland, Codey, Eliason and others. On March 19,
1996, the Board's investigation was concluded, and the Board determined
that this litigation should not have been instituted and should be
terminated. On July 3, 1996, another individual purported shareholder
filed a similar complaint naming the same defendants as the first
derivative lawsuit. The four complaints generally seek recovery of
damages for alleged losses purportedly arising out of PSE&G's operation
of Salem and Hope Creek, together with certain other relief, including
removal of certain executive officers of PSE&G and PSEG and certain
changes in the composition of PSEG's Board of Directors. On August 21,
1996, all defendants filed motions to dismiss all four derivative
actions, which motions were denied and attempts to appeal were
unsuccessful. Pursuant to a Court Order, on December 31, 1997, the
defendants filed motions for summary judgment to dismiss two of the
cases. In one of the other two cases, separate motions for partial and
complete summary judgment were filed by the defendants on April 1,
1998. In the fourth case, on April 1, 1998 the defendants filed a
motion for partial summary judgment. On May 21, 1998, the defendants
filed additional motions for complete summary judgment in the third and
fourth cases. All of these motions are pending. By stipulation filed on
June 15, 1998, the individual plaintiff in the action filed in March
1996 was voluntarily dismissed as a plaintiff in the action. The
outcome of these matters cannot be predicted.
(3) Form 10-K, Page 27. As previously reported, PSE&G and the three other
co-owners of Salem filed suit in February 1996 in the U.S. District
Court for the District of New Jersey against Westinghouse Electric
Corporation (Westinghouse) seeking damages to recover the cost of
replacing the steam generators at Salem 1 and 2. The suit alleges fraud
and breach of contract by Westinghouse in the sale, installation and
maintenance of the generators, including a claim under the Federal
Racketeering Influenced and Corrupt Organizations Act (RICO). In April
1996, Westinghouse filed an answer and $2.5 million counterclaim for
unpaid work related to services at Salem. Westinghouse has filed a
motion for summary judgment on the grounds that the claim of the
plaintiffs is barred by the statute of limitations and oral arguments
on this motion were held in February 1998. On November 6, 1998, the
Court granted Westinghouse summary judgment on the RICO claim but did
not address the plaintiffs' remaining claims, dismissing them without
prejudice since the Court only had original jurisdiction over the RICO
claim. The plaintiffs are considering whether to appeal this decision
and/or to re-file their remaining claims in the Superior Court of New
Jersey.
(4) Form 10-K, Page 45 and June 30, 1998 Form 10-Q, Page 27. As previously
reported, in October 1997, Old Dominion Electric Cooperative (ODEC)
filed a complaint at the Federal Energy Regulatory Commission (FERC)
seeking to modify its 1992 agreement with PSE&G for a ten year sale of
150 megawatts of capacity and energy. In May 1998, while the ODEC
complaint was pending, in a separate proceeding relating to the
restructuring of PJM, FERC ordered PSE&G to reduce its charges to ODEC
by $5.5 million annually for each of the remaining six years of the
agreement. FERC determined that a transmission charge, which it imputed
to the agreement, violated FERC policy, specifically, that users of the
PJM transmission system must pay one rate for transmission based on the
transmission zone in which they are delivering power rather than
multiple rates based on the transmission areas through which their
power transactions are moving. PSE&G has applied to the FERC for a
rehearing of its order which is pending at this time. On August 4,
1998, FERC dismissed ODEC's complaint, determining that certain issues
relating to rate "pancaking" for transmission had been appropriately
addressed in the separate FERC proceeding on PJM restructuring and that
ODEC had failed to show that it was entitled to relief on the remaining
issues. ODEC did not seek further review of this order.
(5) June 30, 1998 Form 10-Q, Page 28. On June 25, 1998, a complaint was
filed against the directors of PSEG, and PSEG as a nominal defendant,
by the same purported shareholder of PSEG who instituted the December
1995 shareholder derivative suit, alleging that the 1996, 1997 and 1998
proxy statements provided to shareholders of PSEG were false and
misleading by reason, among other things, of failure to disclose
certain material facts relating to (i) the controls over and oversight
of PSEG's nuclear operations, (ii) the condition of problems at and
reserves with respect to PSEG's nuclear operations, (iii) a demand
letter relating to the earlier shareholder derivative suit, (iv) PSEG's
liabilities to the Salem co-owners as a result of the shutdown of the
Salem plants and (v) a shareholder proposal relating to operations of
Salem 1 and 2 which was voted upon at the 1998 annual meeting of
shareholders. The complaint seeks to have declared illegal the 1996,
1997 and 1998 elections of directors of PSEG, the vote upon the
stockholder proposal at the 1998 annual meeting, ratification of the
selection of Deloitte & Touche LLP as PSEG's auditors at those annual
meetings, requiring 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 this matter, which will
include as nominees for election as directors persons having no
previous relationship with PSEG or the current directors and other
relief. A motion to dismiss the complaint has been filed. PSEG cannot
predict the outcome of this matter. G.E. Stricklin v. E. James Ferland,
et al, United States District Court for the Eastern District of
Pennsylvania, Civil Action No. 98-3279.
In addition, see the following at the pages hereof indicated:
(1) Pages 9 through 13. Proceedings before the New Jersey Board of Public
Utilities (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, EO97070462 and EO97070463.
(2) Page 13. Proceeding before the BPU relating to PSE&G's Levelized Gas
Adjustment Clause (LGAC) filed on November 14, 1997, Docket No.
GR97110839.
(3) Pages 13 and 14. Proceeding before the Superior Court of New Jersey,
Appellate Division in the matter of the motion of PSE&G to increase
the level of the Electric Demand Side Adjustment Factor, Appellate
Docket No. A-005257-97T2.
(4) Page 13. Proceedings before the BPU relating to the Electric
Levelized Energy Adjustment Clause (LEAC) rate increase to recover
Demand Side Management (DSM) costs, Docket No. ER97020101.
(5) Page 14. Proceedings before the BPU relating to an audit of PSE&G's
competitive services, Docket No. EC98080627.
(6) Page 30. Proceedings before the Federal Energy Regulatory Commission
(FERC) relating to competition and electric wholesale power markets.
(Inquiry Concerning the Pricing Policy for Transmission Services
Provided by Utilities Under the Federal Power Act, Docket No.
RM93-19.)
(7) Page 30. Proceedings before the United States Court of Appeals,
District of Columbia Circuit, in the matter of appeal of FERC Orders
No. 888, 888A and 888B. (Transmission Access Policy Study Group v.
Federal Energy Regulatory Commission, United States Court of Appeals
in the District of Columbia Circuit, Docket No. 97-1715.)
(8) Page 30. Proceeding before FERC relating to the development by PSE&G
and other regional transmission owners in PJM of a new transmission
service tariff and an Independent System Operator, FERC Docket Nos.
OA97-261-000, et al.
(9) Page 37. Suit filed by co-owners of Salem against Westinghouse.
Public Service Electric and Gas Company, et.al., v. Westinghouse
Electric Corporation, United States District Court for the District
of New Jersey, Civil Action No. CB-96-925.
(10) Page 39. Proceedings before the United States Court of Appeals,
District of Columbia Circuit, in the matter of the DOE's
unconditional obligation to begin spent fuel acceptance by January
31, 1998, Northern States Power v. Department of Energy, Docket No.
97-1064.
(11) Page 40. Proceedings before FERC relating to a declaratory judgment
action challenging PSE&G's interpretation of the capacity release
rules, Texas Eastern Transmission Corporation, FERC Docket No.
RP98-83-000.
ITEM 5. OTHER INFORMATION
Certain information reported under PSEG's and PSE&G's 1997 Annual Report
and March 31, 1998 and June 30, 1998 Quarterly Reports to the SEC is updated
below. References are to the related pages of the Form 10-K and the Quarterly
Reports on Form 10-Q for the quarters ended March 31, 1998 and June 30, 1998 as
printed and distributed.
Credit Ratings
Form 10-K, Page 5 and June 30, 1998 Form 10-Q, Page 29
During the second quarter of 1998, Standard and Poor's, Moody's and Duff
and Phelps reconfirmed the credit ratings for PSEG and PSE&G as disclosed in the
1997 Form 10-K. Additionally, Moody's changed its outlook from negative to
stable. In August 1998, Standard and Poor's changed its outlook from negative to
stable.
Nuclear Fuel Disposal
Form 10-K, Page 12 and June 30, 1998 Form 10-Q, Page 29
As a result of reracking the two spent fuel pools at Salem, the
availability of adequate spent fuel storage capacity is estimated through 2012
for Salem 1 and 2016 for Salem 2, prior to losing an operational full core
discharge reserve. The Hope Creek pool is also fully racked and it is expected
to provide storage capacity until 2006, again prior to losing an operational
full core discharge reserve. PSE&G is currently assessing available options
which could satisfy the potential need for additional storage capacity. PECO
Energy has advised PSE&G that spent fuel racks at Peach Bottom have storage
capacity until 2000 for Peach Bottom 2 and 2001 for Peach Bottom 3, prior to
losing full core discharge reserve capability. PECO Energy has also advised
PSE&G that it is constructing an on-site dry storage facility which is expected
to be operational in 2000 to provide additional storage capacity.
As previously reported, in accordance with the Nuclear Waste Policy Act
(NWPA), PSE&G has entered into contracts with the Department of Energy (DOE) for
the disposal of spent nuclear fuel. Payments made to the DOE for disposal costs
are based on nuclear generation and are included in Fuel for Electric Generation
and Net Interchanged Power in the Statements of Income. These costs are being
recovered until the start of retail competition through the LEAC (see Note 2.
Rate Matters and Note 3. Regulatory Assets and Liabilities of Notes).
DOE construction of a permanent disposal facility has not begun and DOE has
announced that it does not expect a facility to be available until 2010 at the
earliest. Accordingly, legislation which would have the DOE establish a
centralized interim spent fuel storage facility has been introduced in Congress.
In litigation brought by PSE&G, 40 other utilities and many state and local
governments, the United States Court of Appeals for the District of Columbia
Circuit reaffirmed DOE's unconditional obligation to begin spent fuel acceptance
by January 31, 1998. In November 1997, the court ruled that the utilities had
fulfilled their obligations under their respective contracts with DOE by
contributing to the Nuclear Waste Fund. The court further ruled that DOE's
argument of unavoidable delay to meet its obligation was without merit. However,
the court did not order DOE to commence spent fuel acceptance by January 31,
1998; instead, it decided that the standard contract provided a potentially
adequate remedy in the form of payment of damages if DOE failed its obligations.
In May 1998 the court denied a petition to order DOE to begin spent fuel
acceptance immediately and declare that the utilities are allowed to escrow
their Nuclear Waste Fund fees until DOE begins spent fuel acceptance. Following
this decision, DOE offered a proposal to settle issues related to its failure to
meet its obligation, which the utilities unanimously rejected. PSE&G is
continuing to work with the utility industry to develop a methodology for
determining damages incurred as a result of DOE's failure to meet its obligation
and a strategy for its implementation. PSE&G is presently studying options to
recover damages from DOE. No assurances can be given as to the ultimate
availability of a facility.
Nuclear Operations
Form 10-K, Page 8 and June 30, 1998 Form 10-Q, Page 30
On September 15, 1998, the NRC issued its latest Systematic Assessment of
Licensee Performance (SALP) Report for Salem for the period March 1, 1997 to
August 1, 1998. In the areas of Maintenance and Engineering, Salem was rated
Category 2 or "good" performance. In the areas of Operations and Plant Support,
Salem received "superior", or Category 1, ratings. The NRC noted improved
performance overall during the period, as demonstrated by the nearly event free
return of both units to operation following the extended outage. The NRC
identified strong management oversight, safe and conservative operations, good
engineering support and effective programs for independent oversight and
self-assessment. The NRC also noted that although human performance has improved
significantly due to extensive training interventions, continued close
management attention is warranted in the operations and maintenance areas.
On September 16, 1998, the NRC suspended its SALP program for an interim
period until the NRC staff completes a review of its nuclear power plant
performance assessment process. During the interim period while the SALP program
is suspended, the NRC will utilize the results of its plant performance reviews
to provide nuclear power plant performance information to licensees, state and
local officials and the public. These reviews are intended to identify
performance trends since the previous assessment and make any appropriate
changes to the NRC's inspection plans. At the end of the process, the NRC will
decide whether to resume the SALP program or substitute an alternative program.
PSE&G cannot predict the final outcome of this NRC review nor its impact on
PSE&G's nuclear operations.
In accordance with NRC Appendix R requirements, nuclear plants utilize
various fire barrier systems to protect equipment necessary for the safe
shutdown of the plant in the event of a fire. As part of an inspection by the
NRC in April 1997, the NRC noted certain weaknesses in PSE&G's fire barrier
systems. PSE&G sent a letter to the NRC in June 1997 addressing these issues
concerning the qualification of fire wrap barriers used to protect electrical
cabling at Salem. The letter outlined a resolution plan and schedule to address
the fire wrap issues. PSE&G has committed to alternative measures in the form of
fire watches until this plan is implemented. A review of the installed fire
barrier materials and safe shutdown analysis is currently in progress. If
certain modifications are mandated by the NRC, this could result in a material
adverse impact to PSE&G's financial condition, results of operations and net
cash flows. Additionally, failure to resolve these fire barrier issues could
result in potential NRC violations, fines and/or plant shutdown.
Other State Regulatory Matters
Form 10-K, Page 4, March 31, 1998 Form 10-Q, Page 27 and June 30, 1998 Form
10-Q, Page 30
As previously reported, on December 3, 1997 one of the interstate pipeline
companies from which PSE&G obtains service filed a declaratory judgment action
with FERC challenging PSE&G's interpretation of the capacity release rules.
Under the interpretation proposed by the interstate pipeline company, PSE&G
would be required to guarantee the performance of its subsidiary Public Service
Energy Trading Company (PSETC) under the transferred agreements. PSE&G disagreed
with these claims and filed a protest challenging the filing. On February 11,
1998, FERC ruled in favor of the interstate pipeline company finding that it was
not unreasonable for the pipeline company to refuse to discharge PSE&G under the
circumstances addressed in the order. On April 29, 1998, FERC issued an order on
rehearing in which it denied PSE&G's request for a rehearing. On June 26, 1998,
PSE&G filed a petition for review of FERC's order with the U.S. Court of
Appeals, District of Columbia Circuit. This matter is currently pending.
<PAGE>
Air Pollution Control
Form 10-K, Page 15 and 40 and June 30, 1998 Form 10-Q, Page 31
On September 24, 1998, EPA issued regulations (referred to as a State
Implementation Plan (SIP) Call) requiring the 22 states in the eastern half of
the United States to make significant NOx emission reductions by 2003 and to
subsequently cap these emissions. The NOx reduction requirements are consistent
with requirements already in place in New Jersey and thus are not likely to have
an additional impact on New Jersey facilities nor change the capacity
availability from PSE&G's New Jersey facilities. The impact on facilities in
Pennsylvania cannot be assessed at this time as such impacts are dependent upon
Pennsylvania's implementation of the SIP Call through state regulations which
have not been proposed. If implemented as adopted, these recommendations will
require power plants in the South and Midwest to meet NOx control requirements
that are similar to the requirements faced by PSE&G facilities in New Jersey.
PSE&G supports adoption and implementation of the EPA SIP Call because it
addresses the ozone transport problem which burdens much of the northeastern
United States. Also, see Note 4. Commitments and Contingent Liabilities for
information on the New Jersey Department of Environmental Protection's
regulations.
Hazardous Substances
Form 10-K, Page 20
As previously reported, PSE&G and over 60 other entities were joined in
1995 as additional third-party defendants in U.S. v. CDMG Realty Co., et al,
Civil Action No. 89-4246 (NHP), venued in the U.S. District Court for the
District of New Jersey. On July 31, 1998, PSE&G and 23 other third-party
defendants entered into a Settlement Agreement with third-party plaintiffs. The
Settlement Agreement provides the settling defendants, including PSE&G, a
release from all claims for contribution, diminution of property value, and
certain defined response costs. PSE&G's financial contribution to the settlement
was not material. By Order dated September 2, 1998, the matter was dismissed
with prejudice.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(A) A listing of exhibits being filed with this document is as follows:
PSEG
- ---------------------------------
Exhibit Number Document
12 Computation of Ratios of Earnings to Fixed Charges (PSEG)
27(A) Financial Data Schedule (PSEG)
PSE&G
- ---------------------------------
Exhibit Number Document
12(A) Computation of Ratios of Earnings to Fixed Charges (PSE&G)
12(B) Computation of Ratios of Earnings to Fixed Charges plus
Preferred Stock Dividend Requirements (PSE&G)
27(B) Financial Data Schedule (PSE&G)
(B) Reports on Form 8-K: None.
<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: November 10, 1998
<TABLE>
EXHIBIT 12
- --------------------------------------------------------------------------------
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
- --------------------------------------------------------------------------------
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
<CAPTION>
12 Months
Ended
YEARS ENDED DECEMBER 31, Sept. 30,
------------- ------------ ------------- ------------ ------------ -----------
1993 (B) 1994 1995 1996 1997 1998
------------- ------------ ------------- ------------ ------------ -----------
(Millions of Dollars, where applicable)
<S>
Earnings as Defined in Regulation S-K (A): <C> <C> <C> <C> <C> <C>
Income from Continuing Operations (C) $549 $667 $627 $588 $560 $646
Income Taxes (D) 296 320 348 297 313 453
Fixed Charges 539 535 549 528 543 564
------------- ------------ ------------- ------------ ----------- -----------
Earnings $1,384 $1,522 $1,524 $1,413 $1,416 $1,663
============= ============ ============= ============ =========== ===========
Fixed Charges as Defined in Regulation S-K (E):
Total Interest Expense (F) $471 $462 $464 $453 $470 $477
Interest Factor in Rentals 11 12 12 12 11 11
Subsidiaries' Preferred Securities
Dividend Requirements -- 2 16 28 44 61
Preferred Stock Dividends 38 41 34 23 12 10
Adjustment to Preferred Stock
Dividends to state on a
pre-income tax basis 19 18 23 12 6 5
------------ ------------ ------------- ------------ ------------ -----------
Total Fixed Charges $539 $535 $549 $528 $543 $564
============= ============ ============= ============ =========== ===========
Ratio of Earnings to Fixed Charges 2.57 2.84 2.78 2.68 2.61 2.95
============= ============ ============= ============ =========== ===========
(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 cumulative effect of $5.4 million credit to income reflecting
a change in income taxes.
(C) Excludes income from discontinued operations.
(D) Includes State income taxes and Federal income taxes for other income.
(E) 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.
(F) Excludes interest expense from discontinued operations.
</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, Sept. 30,
----------- ------------ ------------ ------------ ------------ -----------
1993 1994 1995 1996 1997 1998
----------- ------------ ------------ ------------ ------------ -----------
(Millions of Dollars, where applicable)
Earnings as Defined in Regulation S-K (A):
<S> <C> <C> <C> <C> <C> <C>
Net Income $615 $659 $617 $535 $528 $628
Income Taxes (B) 307 302 326 268 286 435
Fixed Charges 401 408 419 438 450 438
----------- ------------ ------------ ------------ ------------ -----------
Earnings $1,323 $1,369 $1,362 $1,241 $1,264 $1,501
=========== ============ ============ ============ ============ ===========
Fixed Charges as Defined in Regulation S-K (C):
Total Interest Expense $390 $396 $407 $399 $395 $383
Interest Factor in Rentals 11 12 12 11 11 11
Subsidiaries' Preferred Securities
Dividend Requirements -- -- -- 28 44 44
----------- ------------ ------------ ------------ ------------ -----------
Total Fixed Charges $401 $408 $419 $438 $450 $438
=========== ============ ============ ============ ============ ===========
Ratio of Earnings to Fixed Charges 3.30 3.35 3.25 2.83 2.81 3.42
=========== ============ ============ ============ ============ ===========
(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.
</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, Sept. 30,
------------ ------------ ------------- ------------ ------------ ------------
1993 1994 1995 1996 1997 1998
------------ ------------ ------------- ------------ ------------ ------------
(Millions of Dollars, where applicable)
Earnings as Defined in Regulation S-K (A):
<S> <C> <C> <C> <C> <C> <C>
Net Income $615 $659 $617 $535 $528 $628
Income Taxes (B) 307 302 326 268 286 435
Fixed Charges 401 408 419 438 450 438
------------ ------------- ------------- ------------ ------------ ------------
Earnings $1,323 $1,369 $1,362 $1,241 $1,264 $1,501
============ ============= ============= ============ ============ ============
Fixed Charges as Defined in Regulation S-K (C):
Total Interest Expense $390 $396 $407 $399 $395 $383
Interest Factor in Rentals 11 12 12 11 11 11
Subsidiaries' Preferred Securities
Dividend Requirements -- -- -- 28 44 44
Preferred Stock Dividends 38 42 49 23 12 10
Adjustment to Preferred Stock
Dividends to state on a pre-income
tax basis 19 19 24 12 6 7
------------ ------------- ------------- ------------ ------------ ------------
Total Fixed Charges $458 $469 $492 $473 $468 $455
============ ============= ============= ============ ============ ============
Ratio of Earnings to Fixed Charges 2.89 2.92 2.77 2.62 2.70 3.30
============ ============= ============= ============ ============ ============
(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.
</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> 9-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1998
<PERIOD-END> SEP-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 10,873
<OTHER-PROPERTY-AND-INVEST> 3,649
<TOTAL-CURRENT-ASSETS> 1,861
<TOTAL-DEFERRED-CHARGES> 1,574
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 17,957
<COMMON> 3,512 <F1>
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 1,720
<TOTAL-COMMON-STOCKHOLDERS-EQ> 5,195 <F2>
1,113
95
<LONG-TERM-DEBT-NET> 4,517
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 1,206
<LONG-TERM-DEBT-CURRENT-PORT> 419
0
<CAPITAL-LEASE-OBLIGATIONS> 50
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 5,362
<TOT-CAPITALIZATION-AND-LIAB> 17,957
<GROSS-OPERATING-REVENUE> 4,405
<INCOME-TAX-EXPENSE> 367 <F3>
<OTHER-OPERATING-EXPENSES> 3,164
<TOTAL-OPERATING-EXPENSES> 3,525
<OPERATING-INCOME-LOSS> 880
<OTHER-INCOME-NET> 12
<INCOME-BEFORE-INTEREST-EXPEN> 892
<TOTAL-INTEREST-EXPENSE> 399 <F4>
<NET-INCOME> 493
57
<EARNINGS-AVAILABLE-FOR-COMM> 493
<COMMON-STOCK-DIVIDENDS> 376
<TOTAL-INTEREST-ON-BONDS> 295
<CASH-FLOW-OPERATIONS> 941
<EPS-PRIMARY> 2.13
<EPS-DILUTED> 2.13
<FN>
<F1>Includes Treasury Stock of ($91).
<F2>Includes Foreign Currency Translation Adjustment of ($37).
<F3>State Income Taxes of $1 and Federal Income Taxes of $5 for Other Income
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 ecurities 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> 9-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1998
<PERIOD-END> SEP-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 10,873
<OTHER-PROPERTY-AND-INVEST> 749
<TOTAL-CURRENT-ASSETS> 1,727
<TOTAL-DEFERRED-CHARGES> 1,574
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 14,923
<COMMON> 2,563
<CAPITAL-SURPLUS-PAID-IN> 594
<RETAINED-EARNINGS> 1,455
<TOTAL-COMMON-STOCKHOLDERS-EQ> 4,612
588
95
<LONG-TERM-DEBT-NET> 4,044
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 1,082
<LONG-TERM-DEBT-CURRENT-PORT> 100
0
<CAPITAL-LEASE-OBLIGATIONS> 50
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 4,352
<TOT-CAPITALIZATION-AND-LIAB> 14,923
<GROSS-OPERATING-REVENUE> 4,193
<INCOME-TAX-EXPENSE> 357 <F1>
<OTHER-OPERATING-EXPENSES> 3,052
<TOTAL-OPERATING-EXPENSES> 3,403
<OPERATING-INCOME-LOSS> 790
<OTHER-INCOME-NET> 6
<INCOME-BEFORE-INTEREST-EXPEN> 796
<TOTAL-INTEREST-EXPENSE> 309 <F2>
<NET-INCOME> 487
40
<EARNINGS-AVAILABLE-FOR-COMM> 480
<COMMON-STOCK-DIVIDENDS> 376
<TOTAL-INTEREST-ON-BONDS> 230
<CASH-FLOW-OPERATIONS> 968
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
<FN>
<F1>State Income Taxes of $1 and Federal Income Taxes of $5 for Other Income
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>
