PSEG Nuclear LLC P.O. Box 236, Hancocks Bridge, New Jersey 08038-0236
APR 16 2001 0" PSEG Nuclear LLC LRN-01-01 11
United States Nuclear Regulatory Commission Document Control Desk Washington, DC 20555
GUARANTEED RETROSPECTIVE PREMIUMS FOLLOWING A NUCLEAR ACCIDENT SALEM AND HOPE CREEK GENERATING STATIONS DOCKET NOS. 50-272, 50-311 & 50-354 FACILITY OPERATING LICENSE NOS. DPR-70, -75 AND NPF-57
Gentlemen:
Pursuant to the 1975 Amendments to the Price-Anderson Act (Public Law 94-197), the owners of Salem Generating Station, Unit Nos. 1 and 2, and the Hope Creek Generating Station submit the following statements and supporting documents to satisfy guarantee requirements as provided under 10CFR140.21(e):
1. 2000 Stockholders' Annual Report and/or Form 10-K of each owner (except as noted below).
2. Individual certified Internal Cash Flow Statements showing 2000 Actual and 2001 Projected with Explanation of Significant Variations (except as noted below).
Similar documents are filed by the Exelon Energy Company for the owners of the Peach Bottom Atomic Power Station, Unit Nos. 2 and 3 and are therefore not included in this submittal. The PSEG documents that are submitted are for PSEG (the Enterprise) which has been undergoing a reorganization under the New Jersey Energy Master Plan. Generation assets have been transferred to PSEG Power, a wholly owned subsidiary of PSEG. This is discussed in detail in the 10-K.
Should you have any questions regarding this request, we will be pleased to discuss them with you.
Sincerely,
Gabor Salamon
Manager - Nuclear Safety and Licensing
Enclosures (4)
95-2168 REV. 7/99 Document Control Desk -2- (AW 6 2001 LRN-01-0111
C All w/o 2000 Stockholders' Annual Reports
Mr. H. Miller, Administrator - Region I U. S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406
Mr. R. Ennis Licensing Project Manager - Hope Creek U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 14E21 11555 Rockville Pike Rockville, MD 20852
Mr. R. Fretz Licensing Project Manager - Salem U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 4D3 11555 Rockville Pike Rockville, MD 20852
USNRC Resident Inspector Office (X24)
Mr. K. Tosch, Manager IV Bureau of Nuclear Engineering P. O. Box 415 Trenton, NJ 08625
Mr. Ira Dinitz U. S. Nuclear Regulatory Commission Mail Stop 11 F10 Washington, DC 20555 Atlantic City Electric Company Projected Internal Cash Flow Statement For Year 2001 Compared to 2000 Actual ($000)
2001 2000 Projected Actual Explanation of Significant Variances
Net Income $ 41,325 $ 54,434 Electric generating plants are expected to be sold.
Adjustments: Depreciation and amortization 58,081 101,527 Electric generating plants are expected to be sold. Amortization of deferred state excise taxes 10,360 12,207 Deferred energy costs (42,221) (13,839) Higher purchased energy costs due to sale of electric generating plants Deferred Income Taxes 17,339 23,121 Investment Tax Credits (2,062) (3,157) Other non-cash expense (income) 4,972 12,023
Operating cash flow 87,794 186,316
Common & Preferred Dividends Paid (69,641) (69,641)
Internal Cash Flow After Dividends 18,153 116,675
Average Quarterly Cash Flow $ 4,538 $ 29,1691
TheBy: Co, ny has sT ient cash flow to ensure that its respectiveDate: premiums April 4. would2001 be available for payment. Jqie P.11Lavin CkntrollI and Chief Accounting Officer PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED (Salem and Hope Creek) Projected Intemal Cash Flow Statement For Year 2001 Compared to 2000 Actual IMIIE1ors .roDIlanl
2000 2D01 PrelectUd Explanation of Significant Varliallons
Net Income 764 $ 778
Less: Dividends Paid 464 449
Relained in Business 300 329
Adjustments:
Depredation and Amortization 382 334
Amodization of Nuclear Fuel 130 109
Deterred Income Taxes and Inveslment Tax Credits (11) 2
Allowance for Funds Used During Construction and Interest Capilalized Dwing Construction (36) Primarily due to increased cortrl•0c D and ldevelopment activity scheduled for 2001.
Total Adjustments 445 358
Internal Cash Flow $ 745 S 687
Average Quartedy Cash Flow $ 186 $ 172
As indicated by 1this statement, the Average Quarterly Cash Flow covers the maximum contingent liability, which amounts to $19.5 million annually, of Public Service Enterprise Group Incorporated as defined under the Price Anderson Act. The presenlation of Ihis statement in prior years' filings was for Public Service Elecltic and Gas Company, a wholly-owrned subsidiary of Public Service Entwprise Group Incorporated. In August 2000, the Salem and Hope Creek generating stations were transferred to PSEG Power LLC, a separate unregulated wholly-owned subsidiary of Public Service Enterprise Group Incorporated.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
DATE: t Vlk; Prasifanl and Contralie, UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-K (Mark One) [ X I ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2000 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _ to I.R.S. Employer Commission Registrant, State of Incorporation, Identification No. Address, and Telephone Number File Number 22-2625848 001-09120 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED (A New Jersey Corporation) 80 Park Plaza P.O. Box 1171 Newark, New Jersey 07101-1171 973 430-7000 http://www.pseg.com
Securities registered pursuant to Section 12 (b) of the Act:
Title of Each Class Name of Each Exchange on Which Registered New York Stock Exchange Common Stock without par value
Trust Originated Preferred Securities (Guaranteed Preferred Beneficial Interest in PSEG's Debentures), $25 par value at 7.44%, issued by Enterprise Capital Trust I (Registrant). par value at Trust Originated Preferred Securities (Guaranteed Preferred Beneficial Interest in PSEG's Debentures), $25 7.25%, issued by Enterprise Capital Trust III (Registrant). Securities registered pursuant to Section 12 (g) of the Act: par value issued Floating Rate Capital Securities (Guaranteed Preferred Beneficial Interest in PSEG's Debentures), $1,000 by Enterprise Capital Trust II (Registrant), LIBOR plus 1.22%.
Extendible Notes, Series C, LIBOR plus 0.375%, Due 2001. Floating Rate Notes, LIBOR plus 0.875%, Due 2002. as The aggregate market value of the Common Stock of Public Service Enterprise Group Incorporated held by non-affiliates closing price. of January 31, 2001 was $8,508,106,619 based upon the New York Stock Exchange Composite Transaction Stock, as of the latest The number of shares outstanding of Public Service Enterprise Group Incorporated's sole class of Common practicable date, was as follows: Outstanding at January 31, 2001 Class 207,971,318 Common Stock, without par value
DOCUMENTS INCORPORATED BY REFERENCE
Part of Form 10-K Documents Incorporated by Reference III Portions of the definitive Proxy Statement for the Annual Meeting of Stockholders of Public Service Enterprise Group Incorporated to be held April 17, 2001, which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 12, 2001, as specified herein. Commission Registrant, State of Incorporation, I.R.S. Employer File Number Address, and Telephone Number Identification No. 001-00973 PUBLIC SERVICE ELECTRIC AND GAS COMPANY 22-1212800 (A New Jersey Corporation) 80 Park Plaza P.O. Box 570 Newark, New Jersey 07101-0570 973 430-7000
Securities registered pursuant to Section 12(b) of the Act: Name of Each Exchange Title of Each Class Title of Each Class On Which Registered Cumulative PreferredStock Firstand Refunding Mortgage Bonds: $100 par value Series: Series Due 4.08% 9 1/8% BB 2005 4.18% 9 1/4% CC 2021 4.30% 8 7/8% DD 2003 5.05% 77/8% FF 2001 5.28% 6 7/8% MM 2003 5.97% 6 1/2% PP 2004 6.92% 6 1/8% RR 2002 New York Stock Exchange 7% SS 2024 $25 par value Series: 7 3/8% "TT 2014 6.75% 6 3/4% UU 2006 6 3/4% VV 2016 6 1/4% WW 2007 6 3/8% YY 2023 8% 2037 5% 2037
Monthly Income Preferred Securities (Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures), $25 par value at 9.375%, $25 par value at 8.00%, issued by Public Service Electric and Gas Capital, L.P. (Registrant) and registered on the New York Stock Exchange.
Quarterly Income Preferred Securities (Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures), $25 par value at 8.625%, issued by PSE&G Capital Trust I (Registrant) and registered on the New York Stock Exchange.
Quarterly Income Preferred Securities (Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures), $25 par value at 8.125%, issued by PSE&G Capital Trust II (Registrant) and registered on the New York Stock Exchange.
Securities registered pursuant to Section 12(g) of the Act:
Registrant Title of Class Public Service Electric and Gas Company 6.92% Cumulative Preferred Stock $100 par value Medium-Term Notes, Series A
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports) and (2) have been subject to such filing requirements for the past 90 days. Yes [ X ] No[ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ X ]
As of January 31, 2001, 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. TABLE OF CONTENTS
Pace PART I 2 Item 1. Business ...... General ...... 2 Risk Factors ...... 9 Competitive Environm ent ...... 10 Regulatory Issues ...... 11 Customers ...... 15 Employee Relations ...... 16 Segment Information ...... 16 Environm ental M atters ...... 16 19 Item 2. Properties ...... 25 Item 3. Legal Proceedings ...... 28 Item 4. Subm ission of M atters to a Vote of Security Holders ......
PART II 29 Item 5. Market for Registrant's Common Equity and Related Stockholder Matters ...... 30 Item 6. Selected Financial Data ...... 32 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ...... PSEG ...... 32 Corporate Structure ...... 32 Overview of 2000 and Future Outlook ...... 33 Results of Operations ...... 34 Liquidity and Capital Resources ...... 41 External Financings ...... 44 Qualitative and Quantitative D isclosures About M arket Risk ...... 47 Foreign Operations ...... 48 Accounting Issues ...... 48 PSE& G ...... 48 Forward Looking Statements ...... 48 49 Item 7A . Qualitative and Quantitative D isclosures About M arket Risk ...... Item 8. Financial Statem ents and Supplem entary Data ...... 49 Consolidated Financial Statem ents ...... 50 N otes to Consolidated Financial Statem ents ...... 60 Financial Statem ent Responsibility ...... 99 Independent Auditors' Reports ...... 101 Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure ...... 103
PART III Item 10. D irectors and Executive Offi cers of the Registrants ...... 104 106 Item 11. Executive Compensation ...... Item 12. Security Ownership of Certain Beneficial Owners and Management ...... 110 Item 13. Certain Relationships and Related Transactions ...... 111
PART IV Item 14. Exhibits, Financial Statem ent Schedules and Reports on Form 8-K ...... 112 Schedule II- Valuation and Qualifying Accounts ...... 114 Signatures ...... 115 Exhibit Index ...... 117
i PART I
ITEM 1. BUSINESS GENERAL
PSEG
Public Service Enterprise Group Incorporated (PSEG), incorporated under the laws of the State of New Jersey with its principal executive offices located at 80 Park Plaza, Newark, New Jersey 07102, is an exempt public utility holding company. PSEG has four principal direct wholly-owned subsidiaries: Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power), PSEG Energy Holdings Inc. (Energy Holdings) and PSEG Services Corporation (Services).
The following organization chart shows PSEG and its principal subsidiaries, as well as the principal operating subsidiaries of Power and Energy Holdings.
PSEG Organizational Chart
PSE&G
PSE&G is a New Jersey corporation with its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. PSE&G is an operating public utility company engaged principally in the transmission, distribution and sale of electric energy and gas service in New Jersey. In August 2000, pursuant to the terms of the Final Decision and Order (Final Order) issued by the New Jersey Board of Public Utilities (BPU) under the New Jersey Energy Master Plan and the New Jersey Electric Discount and Energy Competition Act (Energy Competition Act), PSE&G transferred its generation-related assets and liabilities to Power and its wholly-owned subsidiaries PSEG Nuclear LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources and Trade LLC (ER&T) and its wholesale power contracts to ER&T.
2 Electric Operationsand Supply
Since August 1, 1999, all electric customers in New Jersey have had the ability to choose an electric energy supplier. PSE&G supplies customers that do not choose a third party supplier (TPS). PSE&G transports electric energy supply from generation sources and distributes it to end-use customers within its designated service territory. PSE&G's electric revenues are based upon tariffs approved by the BPU for this service (see Regulatory Issues PSE&G). Pursuant to BPU requirements, PSE&G also serves as the supplier of last resort for electric customers within its service territory. PSE&G has contracted with Power to provide the capacity and electricity necessary for this basic generation service (BGS) obligation through July 31, 2002. For each annual period thereafter, PSE&G is required to determine the BGS supplier by competitive bid in accordance with BPU requirements.
In addition, PSE&G purchases power under various non-utility generation (NUG) contracts and sells such power into the wholesale energy market with the costs and proceeds applied to the non-utility generation market transition clause (NTC) component of its rates (see Note 3. Regulatory Assets and Liabilities of Notes to Consolidated Financial Statements (Notes)). Rates for electricity sold in the wholesale energy market are not subject to BPU ratemaking and are subject to market forces.
The demand for electricity by PSE&G's customers is affected by customer conservation, economic conditions, weather and other factors not within PSE&G's control.
Gas Operationsand Supply
Since January 1, 2000, all gas customers in New Jersey have had the ability to choose a gas supplier. PSE&G supplies, principally with natural gas, customers that do not choose a competitive gas supplier. PSE&G supplements natural gas with purchased refinery/landfill gas and liquefied petroleum gas produced from propane. The adequacy of supply of all types of gas is affected by the nationwide availability of all sources of fuel for energy production.
As of December 31, 2000, the daily gas capacity of PSE&G was as follows:
Type of Gas Therms Per Day Natural gas ...... 23,319,550 Liquefied petroleum gas ...... 2,200,000 Refinery/landfill gas ...... 223,000 T otal ...... 25,742,550
About 40% of the daily gas capacity is firm transportation which is available every day of the year. The remainder comes from field storage, liquefied natural gas, seasonal purchases, contract peaking supply, propane and refinery/landfill gas. PSE&G's total gas sold to and transported for its various customer classes in 2000 was 3.9 billion therms. Included in this amount was 1.1 billion therms of gas delivered to customers under PSE&G's transportation tariffs and individual cogeneration contracts. During 2000, PSE&G purchased approximately 3.2 billion therms of gas for its combined gas and electric operations directly from natural gas producers and marketers. These supplies were transported to New Jersey by four interstate pipeline suppliers.
The majority of PSE&G's gas transportation and supply contracts expire at various times over the next 10 years. Since the quantities of gas available to PSE&G under its supply contracts are more than adequate in warm months, PSE&G nominates part of such quantities for storage, to be withdrawn during the winter season. Underground storage capacity currently is approximately 775 million therms. PSE&G does not presently anticipate any difficulty in obtaining adequate supplies of natural gas.
The demand for gas by PSE&G's customers is affected by customer conservation, economic conditions, weather, the price relationship between gas and alternative fuels and other factors not within PSE&G's control. Rates for gas sold in interstate commerce are not subject to cost of service ratemaking but are subject to market forces.
3 PSE&G was able to meet all of the demands of its firm customers during the 1999-2000 winter season and expects to continue to meet such energy-related demands of its firm customers during the 2000-2001 and 2001-2002 winter seasons. However, the sufficiency of supply could be affected by several factors not within PSE&G's control, including curtailments of natural gas by its suppliers, the severity of the winter and the availability of feedstocks for the production of supplements to its natural gas supply.
Power
Power is a Delaware limited liability company with its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. Power is engaged in the generation and wholesale energy marketing and trading of electric energy. Power and its three principal wholly-owned subsidiaries were formed in 1999 to acquire, own and operate the electric generation-related assets of PSE&G. Power has contracted with PSE&G to provide the energy, capacity and ancillary services required to fulfill its BGS obligation through July 31, 2002. Power and its subsidiaries are Exempt Wholesale Generators (EWG) and do not directly serve any retail customers. Power also has a finance company subsidiary, PSEG Power Capital Investment Co. (Power Capital), which provides certain financing for Power's other subsidiaries.
The nature of the supply and capacity markets are changing due to deregulation in various states and Federal Energy Regulatory Commission (FERC) initiatives. The resulting development of new markets has increased volatility and risks and also has created opportunities for Power. Power will seek to pursue growth opportunities through expansion of its capacity, acquisitions, in whole or in part, of existing plants and formation of partnerships with independent power producers. Power's growth strategy is designed to increase its generating portfolio by 3,000 MW to 8,000 MW over the next five years.
Electric Fuel Supply and Disposal
The following table indicates Power's mWh output by source of energy in 2000 and the estimated output by Power for 2001: Actual Estimated Source 2000 2001 (A) Nuclear: N ew Jersey facilities ...... 39% 43% Pennsylvania facilities ...... 21% 21% Fossil: Coal: N ew Jersey facilities ...... 16% 13% Pennsylvania facilities ...... 15% 15% Natural Gas ...... 7% 7% Oil ...... 1% 1% Pumped Storage ...... 1% Total ...... 100% 100%
(A) No assurances can be given that actual output will match estimates.
Fossil
Fossil has an ownership interest in 14 fossil generating stations and one hydroelectric pumped storage facility in New Jersey, Pennsylvania and New York. For additional information, see Item 2. Properties-Power-Electric Generation Properties. Fossil uses coal, natural gas and oil for electric generation. These fuels are purchased through various contracts and in the spot market. Fossil does not presently anticipate any difficulties in obtaining adequate coal, natural gas and oil supplies.
4 Fossil owns approximately 23% of the Keystone and Conernaugh coal-fired generating stations located in western Pennsylvania and operated by Reliant Energy. Fossil has been advised that there are presently no anticipated difficulties in obtaining adequate coal supplies for these facilities.
Nuclear
Nuclear has an ownership interest in five nuclear generating units and operates three of them, the Salem Nuclear Generating Station, Units 1 and 2 (Salem 1 and 2), and the Hope Creek Nuclear Generating Station (Hope Creek). Exelon Generation LLC (Exelon) operates the Peach Bottom Atomic Power Station Units 2 and 3 (Peach Bottom 2 and 3). Operation of nuclear generating units involves continuous close regulation by the Nuclear Regulatory Commission (NRC). Such regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety and environmental requirements. Continuous demonstrations to the NRC that plant operations meet requirements are also necessary. The NRC has the ultimate authority to determine whether any nuclear generating unit may operate.
Nuclear owns 50.00% of the Salem units and operates them on behalf of Power and two other owners: Exelon 42.59%; and Atlantic City Electric Company (ACE)--7.41%. Nuclear owns 95% of Hope Creek and operates the unit on behalf of itself and ACE, which owns the remaining 5%. In September 1999, Power entered into a contract to purchase ACE's interest in Salem and Hope Creek. Exelon owns 46.25% of the Peach Bottom units and operates them on behalf of itself and two other owners: Power-46.25%; and ACE-7.5 1%. Nuclear and Exelon have each contracted to purchase one-half of ACE's interest in Peach Bottom. Refueling outages, which have been reduced in duration due to operating efficiencies, are expected to last for approximately five to six weeks and are scheduled for Salem 1, Hope Creek and Peach Bottom 3 in 2001. For 2000, Salem, Hope Creek and Peach Bottom achieved average capacity factors of approximately 89%, 80% and 94%, respectively. For additional information, see Item 2. Properties-Power-Electric Generation Properties.
In accordance with NRC 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 Salem's fire barrier systems. PSEG 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. The completion date, based on each unit's refueling outage schedule, is currently November 2002. PSEG has committed to alternative measures in the form of fire watches until this plan is implemented. A review of the installed fire barrier materials has been completed, and replacement materials have been selected. Revision of the safe shutdown analysis and design of the necessary modifications are currently in progress, the cost of which are not expected to be material. The option to cross connect certain plant systems on both Salem units is also being pursued to further reduce the reliance on fire wrap materials. However, failure to resolve these fire barrier issues could result in potential NRC violations, fines and/or plant shutdown which could have a material adverse impact to PSEG's financial condition, results of operations and net cash flows.
For certain litigation relating to Salem, see Item 3. Legal Proceedings. For information on the operating performance standard applicable to Salem, see Note 10. Commitments and Contingent Liabilities of Notes. For discussion of the renewal of New Jersey Pollutant Discharge Elimination System (NJPDES) permit related to Salem and its operations, see Water Pollution Control.
NuclearDecommissioning
In accordance with Federal regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning. PSE&G currently recovers from its customers the amounts paid into the trust fund each year and remits the amounts collected to Power. Also, upon closing, Nuclear will receive the portion of ACE's Nuclear Decommissioning Trust (NDT) Fund related its acquisition of ACE's nuclear assets. For information concerning nuclear decommissioning costs, see Regulatory Issues and Note 11. PSE&G Nuclear Decommissioning of Notes.
5 Nuclear Fuel
Nuclear has several long-term contracts with uranium ore operators, converters, enrichers and fabricators to meet the currently projected fuel requirements for Salem and Hope Creek. Nuclear has been advised by Exelon that it has similar contracts to satisfy the fuel requirements of Peach Bottom.
Nuclear Fuel Disposal
Pursuant to NRC rules, spent nuclear fuel generated in any reactor can be stored in reactor facility storage pools or in independent spent fuel storage installations located at or away-from-reactor sites for at least 30 years beyond the licensed life for reactor operation (which may include the term of a revised or renewed license). The availability of adequate spent fuel storage capacity is estimated through 2011 for Salem 1, 2015 for Salem 2 and 2007 for Hope Creek. Nuclear presently expects to construct an on-site storage facility that would satisfy the spent fuel storage needs of both Salem and Hope Creek, which construction will require certain regulatory approvals, the timely receipt of which cannot be assured. Exelon has advised Nuclear that it has constructed an on-site dry storage facility at Peach Bottom which is now operational to provide additional storage capacity through the end of the current licenses for the two Peach Bottom units.
Under the Nuclear Waste Policy Act of 1982 (NWPA), as amended, the Federal government has entered into contracts with operators of nuclear power plants for transportation and ultimate disposal of the spent fuel and mandated that the nuclear plant operators contribute to a Nuclear Waste Fund at a rate of one mil per kWh of nuclear generation, subject to such escalation as may be required to assure full cost recovery by the Federal government. Under the NWPA, the United States Department of Energy (DOE) was required to begin taking possession of all spent nuclear fuel generated by the Power's nuclear units for disposal by no later than 1998. DOE construction of a permanent disposal facility has not begun and DOE has announced that it does not expect a facility to be available earlier than 2010. Exelon has advised Power that it had signed an agreement with the DOE applicable to Peach Bottom under which Exelon would be reimbursed for costs resulting from the DOE's delay in accepting spent nuclear fuel. The agreement allows Exelon to reduce the charges paid to the Nuclear Waste Fund to reflect costs reasonably incurred due to the DOE's delay. Past and future expenditures associated with Peach Bottom's recently completed on-site dry storage facility would be eligible for this reduction in future DOE fees. On November 22, 2000, a group of eight utilities filed a petition against DOE in the Eleventh Circuit U.S. Court of Appeals seeking to set aside the receipt of credits out of the Nuclear Waste Fund, as stipulated in the Peach Bottom agreement. No assurances can be given as to any damage recovery or the ultimate availability of a disposal facility.
Uranium EnrichmentDecontamination and DecommissioningFund
In accordance with the National Energy Policy Act of 1992 (EPAct), domestic entities that own nuclear generating stations are required to pay into a decontamination and decommissioning fund, based on their past purchases of U.S. government enrichment services. These amounts are being collected from PSE&G's customers over a period of 15 years. Under this legislation, Nuclear's obligation for the nuclear generating stations in which it has an interest is $73 million (adjusted for inflation). Since 1993, $42 million has been paid, resulting in a balance due of $31 million. Nuclear believes that it should not be subject to collection of any such fund payments under EPAct. Along with other nuclear generator owners, Nuclear has filed suit in the U.S. Court of Claims and in the U.S. District Court, Southern District of NY to recover these costs.
Low Level Radioactive Waste (LLR H9
On July 1, 2000, New Jersey, Connecticut and South Carolina formed the Atlantic Compact. This arrangement gives New Jersey nuclear generators, including Power, continued access to the Bamwell LLRW disposal facility (Barnwell), which is owned by South Carolina. Nuclear believes that the formation of the Atlantic Compact will provide for adequate LLRW disposal for Salem and Hope Creek through the end of their current licenses, although no assurances can be given.
6 ER&T
ER&T purchases all of the capacity and energy from Fossil and Nuclear. In conjunction with these purchases ER&T uses commodity and financial instruments designed to cover estimated commitments for BGS and other bilateral contract agreements (see Note 8. Financial Instruments and Risk Management of Notes). ER&T also markets electricity, capacity, ancillary services and natural gas products on a wholesale basis throughout the Eastern and Midwestern United States. ER&T is a fully integrated marketing and trading organization that is active in the long-term and spot wholesale energy markets.
Enerr' Holdines
Energy Holdings participates in three energy-related lines of business through its principal wholly-owned subsidiaries: PSEG Global Inc. (Global), PSEG Resources Inc. (Resources), and PSEG Energy Technologies Inc. (Energy Technologies). Energy Holdings seeks investment opportunities in the rapidly changing global energy markets, with Global and Energy Technologies focusing on the operating segments of the electric and gas industries and Resources making financial investments in these industries.
Energy Holdings also has a finance subsidiary, PSEG Capital Corporation (PSEG Capital), which provides privately-placed debt financing to Energy Holdings' operating subsidiaries on the basis of a minimum net worth maintenance agreement with PSEG. Energy Holdings is also the parent of Enterprise Group Development Corporation (EGDC), a nonresidential real estate development and investment business and has been conducting a controlled exit from this business since 1993.
Global
Global's goal is to develop, own and operate electric generation and distribution facilities in selected high growth areas of the worldwide energy market. In carrying out its strategy, Global's assessment of potential opportunities includes a multi-faceted analysis of the resident country, potential partners and transaction economics. As a result of this strategic approach, Global has developed or acquired interests in electric generation and/or distribution facilities in the United States, Argentina, Brazil, Chile, China, Peru and Venezuela. In addition, projects are in construction or advanced development in the United States, Argentina, China, India, Italy, Poland, Tunisia and Venezuela. Global expects that future development of additional projects will take place primarily outside of the United States.
As of December 31, 2000, Global has ownership interests in 23 operating generation projects totaling 3,136 MW (1,076 MW net) and 15 projects totaling 3,918 MW (1,964 MW net) in construction or advanced development. Of Global's generation projects in operation, construction or advanced development, 1,294 MW net or 43% are located in the United States. Global currently owns interests in seven distribution companies in Argentina, Brazil, Chile and Peru. Global has expanded its business to include electric distribution where it can be linked to existing or prospective generation opportunities. For additional information, see Item 2. Properties - Global - Electric Generation Properties.
Fuel supply arrangements are designed to balance long-term supply needs with price considerations. Global's project affiliates utilize long-term contracts and spot market purchases. Global believes that there are adequate fuel supplies for the anticipated needs of its generating projects. Global also believes that transmission access and capacity are sufficient at this time for its generation projects.
It is Global's policy to limit its financial exposure to each project and to mitigate development and operating risk, including fuel and foreign currency exposure, through contracts. In addition, the project loan agreements are structured on a non-recourse basis. Further, Global structures project financing so that a default under one project's loan agreement will have no effect on the loan agreements of other projects or the debt of Energy Holdings.
7 Resources
Resources focuses on providing energy infrastructure financing in developed countries. Resources invests in energy-related financial transactions and manages a diversified portfolio of assets, including leveraged leases, leveraged buyout funds, limited partnerships and marketable securities. Resources seeks to invest in transactions where its expertise and understanding of the inherent risks and operating characteristics of energy-related assets provide a competitive advantage. Resources currently expects to concentrate its future investment activity on energy related financial transactions.
As of December 31, 2000 and December 31, 1999, Resources had approximately $2.3 billion and $1.8 billion, respectively, invested in leveraged lease transactions which represented approximately 88% and 84% of Resources' total assets. Leveraged leases of energy-related plant and equipment totaled approximately $1.8 billion and $1.3 billion as of December 31, 2000 and December 31, 1999, respectively. The remainder of Resources' portfolio is further diversified across a wide spectrum of asset types and business sectors including leveraged leases of aircraft, railcars and real estate, limited partnership interests in project finance transactions and leveraged buyout and venture funds. Approximately 85% of the lease investments in Resources' portfolio are with lessees that have investment grade credit ratings. Resources does not manage any fund or partnership in its portfolio. The timing of distributions from these investments is not within Resources' control.
Energay Technologies
Energy Technologies is an energy management company that provides energy-related engineering, consulting and mechanical contracting services to and constructs, operates and maintains heating, ventilating and air conditioning (HVAC) systems for industrial and commercial customers in the Northeastern and Middle Atlantic United States. Energy Holdings will assess the growth prospects and opportunities for Energy Technologies' business before committing additional capital.
Energy Technologies has established a presence in the energy services business through the acquisition of nine companies involved in the engineering, construction, installation, operation and maintenance of energy equipment and HVAC systems. The combination of these companies created a regional energy service capability from New England to Virginia.
In February 2000, Energy Technologies entered into a business arrangement with a third party to provide an internet-based auction exchange that will allow its customers an alternative method in purchasing their energy requirements. In June 2000, Energy Technologies outsourced certain supply services under its retail gas service agreements. With these transactions, Energy Technologies has changed the manner in which it operates its electric and gas commodity business. Energy Technologies plans to grow from existing operations by utilizing the recently acquired companies to deliver expanded energy-related services and products to new and existing customers.
Services
Services is a New Jersey Corporation with its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. Services provides management and administrative services to PSEG and its subsidiaries.
8 RISK FACTORS
These factors should be considered when reviewing PSEG's and PSE&G's businesses, and are relied upon by PSEG and PSE&G in issuing any forward-looking statements. Such factors could affect actual results and cause such results to differ materially from those expressed in any forward-looking statements made by, or on behalf of, PSEG and PSE&G. Some or all of these factors may apply to PSEG and PSE&G.
"* Deregulation and the unbundling of energy supplies and services and the establishment of a competitive energy marketplace.
"* Changes in operation and availability of the electric generation plants compared to historical performance and changes in the historical operating cost structure.
"* Ability to obtain adequate and timely rate relief, cost recovery, including unsecuritized stranded costs, and other necessary regulatory approvals.
"* The need to manage operating and capital costs in a competitive environment and in light of mandated rate reductions.
"* The need to manage wholesale energy trading operations in conjunction with electricity production and gas supply activities, transmission and distribution systems, including commodity price fluctuations, volatility and credit risk from counterparties.
"* Inability to purchase or generate electricity at prices lower than BGS rates approved by the BPU.
"* Ability to replace BGS and other revenues following current contract periods.
"* In certain foreign markets: the ability of PSEG and its subsidiaries to hedge against foreign exchange rates and fluctuations in those rates; the economic, political and military conditions; and repatriation of earnings or other cash flow.
"* Changes in trade, monetary and fiscal policies, laws and regulations
"* Inability to raise capital on favorable terms to refinance existing indebtedness or to fund future acquisitions and other capital commitments.
"* Successful and timely completion of electric generating projects and capital improvements to existing facilities.
"* Changes in the economic and electricity consumption growth rates in the U.S. and foreign countries.
"* Ability to economically and safely operate power generation facilities, including nuclear facilities, in accordance with regulatory requirements and the potential impact of nuclear decommissioning and the availability of storage facilities for spent nuclear fuel.
"* Operating conditions and increased capital investments attributable to environmental regulations.
"* Limited control of minority interests.
"* Ability to maintain sufficient insurance coverages.
9 COMPETITIVE ENVIRONMENT
The regulatory structure which has historically governed the electric and gas utility industries in the United States and in New Jersey is in transition. Deregulation is essentially complete in New Jersey and is complete or well under way in other states in the Northeast and across the United States. States have acted independently to deregulate and recent experience in California, with energy shortages, high costs, and financial difficulties of the utilities have caused States to re-evaluate and in some cases stop the move toward deregulation. The deregulation and restructuring of the nation's energy markets, the unbundling of energy and related services, the diverse strategies within the industry related to holding, buying or selling generation capacity and the anticipated resulting industry consolidation could have a profound effect on PSEG and its subsidiaries, providing them with new opportunities and exposing them to new risks (see Overview of 2000 and Future Outlook of MD&A).
PSE&G
As a regulated monopoly, PSE&G's regulated electric and gas transmission and distribution business has minimal risks to competition. Also, there is minimal financial impact on PSE&G's transmission and distribution business due to customers choosing an alternate electric or gas supplier.
Power
Federal and state legislative and regulatory initiatives have laid the groundwork for competition in the wholesale and retail electricity markets. Electric power marketers, independent power producers, EWGs and utilities now compete actively in the wholesale markets. As a result, the highly regulated market structure of the past is giving way to one where electricity customers have the right to choose their supplier and competition is setting the price of the generation component of electricity bills.
Through July 31, 2002, PSE&G will be Power's main customer pursuant to the BGS contract. Due to retail competition, PSE&G's retail market is expected to moderately erode. As of December 31, 2000, TPS in the New Jersey electric generation market gained approximately 10% of the customer load traditionally served by PSE&G. Power will attempt to market the resulting excess generation capacity to supply retail aggregators and other load serving entities (LSE) and, following the completion of the BGS contract period, Power anticipates that the majority of its generation output will continue to be dedicated to supplying similar long-term contracts.
As markets continue to evolve, several types of competitors have or will emerge in the markets in which Power participates. These competitors include independent power producers, with or without trading capabilities, other utility affiliates that have formed generating and/or trading affiliates, aggregators and wholesale power marketers. Power expects to compete as a large, diverse supplier of wholesale electricity and related products and services. Power's success as a competitive generator will be due in part to the extent it can produce power at rates lower than its long-term contract prices and prevailing market prices.
Enerzr Holdings
Energy Holdings and its subsidiaries are subject to substantial competition in the United States as well as in the international markets from independent power producers, domestic and multi-national utility generators, fuel supply companies, energy marketers, engineering companies, equipment manufacturers, well capitalized investment and finance companies and affiliates of other industrial companies. Restructuring of worldwide energy markets, including the privatization of government-owned utilities and the sale of utility-owned assets, is creating opportunities for Energy Holdings, and likewise is creating substantial competition from well-capitalized entities which may adversely affect Energy Holdings' ability to make investments on favorable terms and achieve its growth objectives.
10 REGULATORY ISSUES
State Regulation
As a New Jersey public utility, PSE&G has been subject to comprehensive regulation by the BPU including, among other matters, regulation of intrastate rates and service and the issuance and sale of securities. As a participant in the ownership of certain transmission facilities in Pennsylvania, PSE&G is subject to regulation by the Pennsylvania Public Utility Commission (PPUC) in limited respects in regard to such facilities. PSEG, Power and Energy Holdings are not subject to direct regulation by the BPU, except potentially with respect to certain transfers of control, reporting requirements and affiliate standards.
FederalRegulation
PSEG and certain of its subsidiaries' domestic operations are subject to regulation by FERC with respect to certain matters, including interstate sales and exchanges of electric transmission, capacity and energy. PSEG has claimed an exemption from regulation by the Securities and Exchange Commission (SEC) as a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA), except for Section 9(a)(2), which relates to the acquisition of 5% or more of the voting securities of an electric or gas utility company. Fossil and Nuclear are EWGs and Global's investments include EWGs and foreign utility companies (FUCOs) under PUHCA. Failure to maintain status of these plants as EWGs or FUCOs could subject PSEG and its subsidiaries to regulation under PUHCA.
If PSEG were no longer exempt from PUHCA, PSEG and its subsidiaries would be subject to additional regulation by the SEC with respect to their financing and investing activities, including the amount and type of non utility investments. PSEG believes, however, that this would not have a material adverse affect on PSEG and its subsidiaries.
Construction, operation and decommissioning of nuclear generating facilities are regulated by the NRC. In addition, the Federal Emergency Management Agency is responsible for the review, in conjunction with the NRC, of certain aspects of emergency planning relating to the operation of nuclear plants. PSE&G, Fossil, Nuclear and Global are also subject to the rules and regulation of the United States Environmental Protection Agency (EPA), U.S. Department of Transportation (DOT) and U.S. Department of Energy (DOE). For information on environmental regulation, see Environmental Matters.
PSE&G
New Jersey Energy MasterPlan Proceedingsand Related Orders
Following the enactment of the Energy Competition Act, the BPU rendered its Final Order relating to PSE&G's rate unbundling, stranded costs and restructuring proceedings providing, among other things, for the transfer to an affiliate of all of PSE&G's electric generation facilities, plant and equipment for $2.443 billion and all other related property, including materials, supplies and fuel at the net book value thereof, together with associated rights and liabilities. PSE&G, pursuant to the Final Order, transferred its electric generating facilities and wholesale power contracts to Power and its subsidiaries on August 21, 2000 in exchange for a promissory note from Power in an amount equal to the purchase price of $2.786 billion. Power settled the promissory note on January 31, 2001 at which time the transferred assets were released from the lien of PSE&G's First and Refunding Mortgage.
The Energy Competition Act and the related BPU proceedings, including the Final Order, referred to as the Energy Master Plan Proceedings, opened the New Jersey energy markets to competition by allowing all New Jersey retail electric and gas customers to select their suppliers. For further discussion of the Energy Master Plan Proceedings, see Note 2. Regulatory Issues and Accounting Impacts of Deregulation of Notes.
11 Securitization Filing and Finance Order
For a discussion of the appeals of the Final Order and Finance Order which were denied by the New Jersey Supreme Court in December 2000 and the related issuance of securitization bonds in January 2001, see Note 2. Regulatory Issues and Accounting Impacts of Deregulation of Notes.
In accordance with the Final Order, PSE&G reduced customer rates an additional 2% after the securitization transaction and will reduce rates another 2% in August 2001 and 4.9% in August 2002, for a total 13.9% rate reduction since August 1999.
Affiliate Standards
In February 2000, the BPU approved affiliate standards and fair competition standards which apply to transactions between a public utility and its affiliates that provide competitive services to retail customers in New Jersey. On March 15, 2000, the BPU issued a written order (Affiliate Standards) related to these matters. PSE&G filed a compliance plan on June 15, 2000 to describe the internal policy and procedures necessary to ensure compliance with such Affiliate Standards. The BPU has conducted an audit of utilities' competitive activities and compliance with such Affiliate Standards and is expected to issue an order on the audit in 2001. The adoption of Affiliate Standards did not have a material adverse effect on PSEG's or PSE&G's financial condition, results of operations or net cash flows.
Gas Unbundling
The Energy Competition Act also required that all customers have the ability to choose a competitive gas supplier. During 2000, the BPU issued a written order providing for the unbundling of firm rate schedules into commodity and transportation components and for changes in existing rate schedules. The new rates were implemented for all service provided on and after August 1, 2000.
The main features of the gas unbundling are: the development of a Societal Benefits Clause (SBC) to recover specific costs including, social programs, Demand Side Management costs (DSM), Remediation Adjustment Clause (RAC) and consumer education; the development of a Realignment Adjustment Charge to recover lost revenues incurred by PSE&G (subject to certain criteria) as a result of customers switching from commodity service to transportation service; the reallocation of approximately $40 million from transportation rates to commodity and balancing rates; an incentive of approximately 0.9 cents per therm for all customers who leave PSE&G to shop with a TPS and an additional incentive of 1.4 cents per therm for residential customers who leave PSE&G to shop with a TPS; and PSE&G must propose a daily delivery option to the current monthly based balancing mechanism to be in place prior to the next winter season.
Gas Contract Transfer
On August 11, 2000, PSE&G filed a gas merchant restructuring plan with the BPU which provides for, among other things, the transfer of PSE&G's gas supply, transportation, storage and peaking contracts to a subsidiary of Power and a requirements contract between PSE&G and Power's subsidiary enabling PSE&G to fulfill its basic gas supply service. PSE&G cannot predict the outcome of this matter.
12 Other Regulatory Issues
Levelized Gas Adjustment Clause (LGAC)
On July 31, 2000, PSE&G filed a motion with the BPU requesting interim authorization by September 1, 2000 gas price to change the Monthly Pricing Mechanism (MPM) in PSE&G's LGAC to cover currently estimated BPU increases on a per month basis, exercisable in any month without an annual limit. On November 1, 2000, the months issued a written order granting PSE&G a provisional rate increase of 16% with a 2% MPM for each of the On from December 2000 through April 2001 for the amounts that PSE&G is permitted to charge customers. and to December 1, 2000, PSE&G filed a supplemental motion to finalize the approved provisional rate increases 1, 2001. request that the authority to change the MPM be extended to July 2001 and then reinstituted on December
Tax Sharing Agreement
The issue of PSEG sharing the benefits of consolidated tax savings with PSE&G or its customers was addressed discussed in by the BPU in 1995 in a letter which informed PSE&G that the issue of consolidated tax savings can be taxes the context of its next base rate case or plan for an alternative form of regulation. PSEG believes that PSE&G's should be treated on a stand-alone basis for rate making purposes, based on the separate nature of the utility and non utility businesses. However, neither PSEG nor PSE&G is able to predict what action, if any, the BPU may take concerning consolidated tax savings in future proceedings.
Focused Audit
For information regarding the 1992 BPU proceeding concerning the relationship of PSE&G to PSEG's non utility businesses (Focused Audit), see Liquidity and Capital Resources-Regulatory Restrictions of MD&A.
Enermy HoldinuRs
Energy Holdings is not subject to direct regulation by the BPU, except for reporting requirements and affiliate standards and, potentially, with respect to certain transfers of control.
Energy Holdings' foreign subsidiaries generally are subject to regulation in the countries in which they operate. charged to Global's electric and gas distribution facilities in Latin America are rate-regulated enterprises. Rates and customers are established by governmental authorities and are currently sufficient to cover all operating costs provide a fair return. Energy Holdings can give no assurances that future rates will be established at levels sufficient on to cover such costs, provide a return on its investment or generate adequate cash flow to pay principal and interest also its debt or to enable it to comply with the terms of debt agreements. Global's Latin American facilities are attempt subject to quality of service standards. Global intends to implement capital improvement budgets which will to have a to meet these standards. Failure to meet required standards could result in penalties which are not expected are material adverse impact on these investments, although no assurances can be given. Certain generation projects also subject to rate regulation.
PJM InterconnectionLLC (PJM)
PSE&G, Power and Power's operating subsidiaries are members of the PJM regional power pool and participate on the PJM Members Committee as part of its governance structure. The PJM electric system is interconnected with other major electric utility companies in the eastern half of the United States. The PJM area of the power grid is to operated as one system to provide increased reliability, an assurance of an adequate supply of electricity, security withstand disturbances and reduced operating costs to its members. The PJM Independent System Operator (ISO) U.S. conducts the largest centrally dispatched energy market in North America serving nearly 9% of the total population. PJM has over 194 active member organizations that operate a total of 540 generating units.
13 There are a number of factors that distinguish the PJM market from California, and make less likely the types of problems recently experienced there. The most prominent difference is the extent to which there is adequate generating capacity to meet demand in the region. PJM's reserve margin (installed capacity less peak demand) is 18 percent, which is considerably higher than that in California where reserve margins have slipped below 6 percent. The two markets have also operated differently. Initially, California utilities were required to buy their energy in the day-ahead, or spot, market. While longer-term forward contracts have been permitted more recently, the initial rules resulted in considerable price risk for utilities. In contrast, in PJM utilities have been permitted to lock in prices through long-term contracts, and to mitigate risk with use of other hedging instruments. Finally, California is highly dependent on gas-fired generation and hydro (51 percent and 26 percent, respectively), both of which are highly dependent on weather. In contrast, PJM has a more diverse fuel mix, including substantial base of coal and nuclear generators, whose cost structures have remained stable.
Currently, bids for electric energy offered for sale in PJM 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 regional power pool from generation located outside the PJM control area are capped at $1,000 per megawatt hour. All power providers in PJM are paid the locational marginal price (LMP) set through power providers' bids. The LMP will be higher in transmission congested areas reflecting the price bids of those higher cost generating units that are dispatched to supply demand and alleviate the transmission constraint. Furthermore, in the event that all available generation within the PJM control area is insufficient to satisfy demand, the PJM ISO may institute emergency purchases from adjoining regions. The cost of such emergency purchases is not subject to the $1,000 per mWh PJM price cap. To the extent Power provides less energy than required to supply PSE&G's customers, the lifting of such caps would present additional risks with respect to the difference between the cost of such purchases and the BGS rate. Transmission constraints have and will affect energy pricing when the PJM system is congested. For further discussion of price volatility of electricity, see Qualitative and Quantitative Disclosures About Market Risk.
In December 1999, FERC promulgated a Final Rule (Order 2000) in the Regional Transmission Organization (RTO) rulemaking proceeding. In October 2000, PJM and nine PJM transmission owners, including PSE&G, made a filing with FERC stating that PJM is an RTO that meets or exceeds the requirements of Order 2000. Included in this filing was a PJM rate proposal designed to provide for deferral recovery of reasonable, risk-adjusted returns on new transmission investments in the PJM region, an accelerated recovery period for such new investments, and a rate moratorium of current charges through December 31, 2004.
On June 1, 2000, the PJM Energy Market began to transition from a Single Settlement System to a Two Settlement System. In the Two Settlement System market participants will have the option to "lock in" day-ahead scheduled quantities at prices based upon predicted day-ahead hourly LMP values (Day Ahead Settlement). Actual demand will be satisfied through a real time balancing market based upon real-time hourly average LMP values. PJM advises that the Two Settlement System will provide: (i) a means for market participants to obtain increased price certainty; (ii) financial incentive for resources and demand to submit day-ahead schedules that match their actual schedules; (iii) financial incentive for generation to follow real-time dispatch. Management cannot predict the effect of the implementation of the Two Settlement System in the PJM Energy Market.
Other Power Markets
In the Eastern U.S., there are three centralized electricity markets now operated by ISO organizations: (PJM (operated by PJM ISO), New York (operated by New York ISO) and New England (operated by ISO New England) In addition to Power's involvement in the formation and ongoing operation of all three organizations, it actively trades in their wholesale markets. Power is also active in other major electricity markets in the Midwestern and Southern United States, principally in the Virginia-Carolina Reliability Group (VACAR) area and the East Central Area Reliability Council (ECAR) area. Although these markets are not yet centrally dispatched or operated by an ISO, they do have wholesale markets in which Power is able to actively participate.
14 CUSTOMERS
PSE&G
PSE&G's demand for electricity and natural gas will come from customers that do not choose or are not for otherwise served by an alternate energy supplier. PSE&G expects to be able to continue to meet the demand of electricity on its system through its BGS contract with Power through July 31, 2002. Thereafter, the supply with electricity to serve BGS will be determined by competitive bid. If periods of unusual demand should coincide outages of equipment, unavailability of supply or large increases in customer load switch back to BGS , PSE&G of its could find it necessary at times to reduce voltage or curtail load in order to safeguard the continued operation energy delivery systems.
PSE&G supplies electric and gas service in areas of New Jersey in which approximately 5.5 million people, about 70% of the State's population, reside. PSE&G's electric and gas service area is a corridor of approximately 2,600 square miles running diagonally across New Jersey from Bergen County in the northeast to an area below the City of Camden in the southwest. The greater portion of this area is served with both electricity and gas, but some provided parts are served with electricity only and other parts with gas only. As of December 31, 2000, PSE&G heavily service to approximately 1.9 million electric customers and approximately 1.6 million gas customers. This populated, commercialized and industrialized territory encompasses most of New Jersey's largest municipalities, to including its six largest cities-Newark, Jersey City, Paterson, Elizabeth, Trenton and Camden-in addition approximately 300 suburban and rural communities. This service territory contains a diversified mix of commerce and industry, including major facilities of many corporations of national prominence. PSE&G's load requirements the are almost evenly split among residential, commercial and industrial customers. PSE&G believes that it has all franchises (including consents) necessary for its electric and gas distribution operations in the territory it serves. Such franchise rights are not exclusive.
Power
Power sells generation and capacity to PSE&G through the BGS contract. Power also sells generation and capacity into the wholesale power market, including PJM and other power pools and to other LSEs through bilateral contracts. Currently, PSE&G is Power's most significant customer. Power is obligated to supply all of PSE&G's energy and capacity requirements through July 31, 2002. For the period beginning August 1, 2002 and thereafter, the lost BGS contract will be bid out by PSE&G. If Power is not the successful bidder, Power will have to replace revenues from the BGS contract by entering into other bilateral supply contracts and selling into the wholesale power markets.
Enerry Holdings
Global
Global has ownership interests in seven distribution companies which serve approximately three million customers and has developed or acquired interests in electric generation facilities which sell energy, capacity and ancillary services to numerous customers through power purchase agreements (PPAs) as well as into the wholesale market.
Energf Technologies
Energy Technologies currently provides services to approximately 13,000 customers.
15 EMPLOYEE RELATIONS
PSEG has no employees. As of December 31, 2000, PSE&G had 6,514 employees, Power and its subsidiaries had 3,124 employees and Services had 1,071 employees. There are six-year collective bargaining agreements in place with all of PSE&G's, Power's and Services' union groups which expire on April 30, 2002. As of December 31, 2000, PSEG Energy Holdings and its subsidiaries had a total of 2,376 employees. Energy Technologies had a total of 1,739 employees who are represented by various construction trade unions. Energy Technologies and its operating subsidiaries are party to agreements with various trade unions through multi employer associations. PSE&G, Power, Services and Energy Holdings believe that they maintain satisfactory relationships with their employees.
For information concerning employee pension plans and other postretirement benefits, see Note 13. Pension, Other Postretirement Benefit and Savings Plans of Notes. SEGMENT INFORMATION
Financial information with respect to business segments of PSEG and PSE&G is set forth in Note 15. Financial Information by Business Segments of Notes.
ENVIRONMENTAL MATTERS
Federal, regional, state and local authorities regulate the environmental impacts of the operations of PSEG and its subsidiaries. Global has ownership interests in facilities, including operating power plants and distribution companies and power plants under construction or in development which are subject to similar regulation in the United States and numerous other countries. Areas of regulation include air quality, water quality, site remediation, land use, waste disposal, aesthetics and other matters. Generators of hazardous substances potentially face joint and several liability, without regard to fault, when they fail to manage these hazardous substances properly and when they are required to clean up property affected by the production and discharge of hazardous substances.
Compliance with environmental requirements has caused PSEG and its subsidiaries to modify the day-to-day operation of their facilities, to participate in the cleanup of various properties that have been contaminated and to modify, supplement and replace existing equipment and facilities. During 2000, PSE&G and Power expended approximately $13 million for capital related expenditures to improve the environment and comply with laws and regulations and estimates that they will expend approximately $21 million, $29 million and $16 million in the years 2001 through 2003, respectively, for such purposes.
Air Pollution Control
Federal, state, and local air pollution laws (such as the Federal Clean Air Act (CAA) and the New Jersey Air Pollution Control Act) require controls of emissions from sources of air pollution, as well as recordkeeping, reporting and permit requirements.
To reduce emissions of sulfur dioxide (SO 2), the CAA sets a cap on total emissions of SO 2 from affected units, and allocates SO 2 "allowances" (each allowance authorizes the emission of one ton of SO ) to those units. Generating units 2 needing to cover emissions above their allocations can buy allowances from sources that have excess allowances. Similarly, to reduce emissions of nitrogen oxides (NOx), which contribute to the formation of smog, Northeastern states and the District of Columbia have set a cap on total emissions of NOx from affected units, and allocated NOx allowances (with each allowance authorizing the emission of one ton of NOx) to those units. NOx allowances can be bought and sold through a regional trading program similar to the trading of SO2 allowances. In 2003, the cap will be reduced to limit NOx emissions further.
To comply with the SO 2 and NOx requirements, affected units may choose one or more strategies, including installing air pollution control technologies, changing or limiting operations, changing fuels or obtaining additional
16 allowances. At this time, Power does not expect that it will incur material expenditures to continue complying with the S02 program. Power's current analysis leads it to believe that the potential costs for purchasing additional NOx allowances will also not be material through December 31, 2002. When the NOx cap is reduced in 2003, the cost of complying with the cap may increase significantly. Whether the cost will increase or decrease will depend upon whether Power will be a net purchaser or seller of NOx allowances. The extent of any increase or decrease will depend upon a number of factors that may increase or decrease total NOx emissions from affected units, thus increasing or decreasing demand for a fixed supply of allowances. Power has been implementing measures to reduce NOx emissions at several of its units, which will reduce the cost of purchasing allowances.
In December 1999, the EPA proposed to approve plans by several states (including New Jersey and certain other Northeastern states) to attain the ozone National Ambient Air Quality Standards. That approval is contingent on these states implementing new programs to further reduce emissions of smog-forming chemicals (including NOx). The affected Northeastern states have committed to make these reductions, and by October 1, 2001, must select measures that could affect Power's electric generating units directly. Measures currently under consideration may increase demand for NOx allowances and thus increase the price of those allowances.
In September 1998, the EPA issued regulations (commonly known as the "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, New York and Pennsylvania, and thus are not likely to have an additional impact on Power's facilities in those states nor change the capacity availability from these facilities. On March 3, 2000, a federal court upheld nearly all provisions of the SIP Call regulations.
The EPA adopted a new air quality standard in July 1997 for fine particulate matter. To attain the fine particulate matter standard, states may require further reductions in NOx and SO 2. However, under the time schedule announced by the EPA when the new standard was adopted, non-attainment areas will not be designated until 2002 and control measures to meet this standard will not be identified until 2005. The timing of these actions is uncertain due to a federal court decision that overturned the new standard. That decision was appealed to the United States Supreme Court, which is expected to reach a decision in the case by June 2001. Even if the fine particulate matter standard is not upheld, similar NOx and S02 reductions may be required to satisfy requirements of an EPA rule protecting visibility in 156 of the nation's scenic areas, including some areas near facilities operated by Power.
Under the CAA, states must require each major facility to obtain a facility-wide operating permit. Operating permits for certain Power facilities may require changes to facility operations or technology, installation of additional air pollution controls and performance of supplemental emissions monitoring.
In November 1999, the federal government announced the filing of lawsuits by several states against seven companies operating power plants in the Midwest and Southeast, charging that 32 coal-fired plants in ten states violated the Prevention of Significant Deterioration (PSD)/New Source Review requirements of the CAA. Generally, these regulations require major sources of criteria air pollutants to obtain permits, install pollution control technology and obtain offsets in some circumstances when those sources undergo a "major modification," as defined in the regulations. Various environmental and public interest organizations have given notice of their intent to file similar lawsuits. The federal government is seeking to order these companies to install the best available air pollution control technology at the affected plants and to pay monetary penalties of up to $27,500 for each day of continued violation. For additional information on PSD/New Source Review as it is applicable to PSEG, see Note 10. Commitments and Contingent Liabilities of Notes.
17 Water Pollution Control
The Federal Water Pollution Control Act (FWPCA) authorizes the imposition of technology and water-quality based effluent limitations to regulate the discharge of pollutants into surface waters through the issuance of National Pollutant Discharge Elimination System (NPDES) permits. Certain PSE&G and Power facilities are directly regulated by NPDES permits.
The NPDES permit renewal application for Power's Hudson Station is in the process of being reviewed by the NJDEP. As part of that renewal, the NJDEP has requested updated information in part, to address issues identified by a consultant hired by NJDEP. The consultant recommended that Hudson Station be retrofitted to operate with closed cycle cooling to address alleged adverse impacts associated with the thermal discharge and intake structure. Power proposed certain modifications to the intake structure and submitted these demonstrations to NJDEP in the fourth quarter of 1998. While Power believes that these demonstrations address the issues identified by the NJDEP's consultant and provide an adequate basis for favorable determinations under the FWPCA without the imposition of closed cycle cooling, it is impossible to predict the outcome of the agency's review at the present time. Power presently estimates that the cost of retrofitting Hudson Station to operate with closed cycle cooling, if required, to be approximately $100 million. Such amount is not currently included in Power's estimate of construction expenditures (see Liquidity and Capital Resources of MD&A).
NJDEP has advised Power that it is reviewing a renewal application for Mercer Station and, in connection with that renewal, will be reexamining the effects of Mercer Station's cooling water system pursuant to the FWPCA. Power is preparing updated demonstrations for submittal to the NJDEP. It is not possible to predict the outcome of such review.
Power is implementing the 1994 NJPDES permit issued for Salem which requires, among other things, water intake screen modifications and wetlands restoration. Under the 1994 permit, which remains in effect until such time as a renewed permit is issued, Power is continuing to restore wetlands and to conduct the requisite management and monitoring associated with the implementation of the special conditions of that permit. The existing permit remains in full force and effect based upon the timely submission of a renewal filing. A timely and comprehensive application for the renewal of Salem's NJDEP permit which included updated FWPCA demonstrations as well as a demonstration of the implementation of the Special Conditions of the 1994 NJPDES permit and their biological efficacy was filed in March 1999. On December 8, 2000, the NJDEP issued a draft NJPDES Permit that proposes to authorize the continued discharge of cooling water and other effluents from the Salem Generating Station to the Delaware River. The comment period on the draft permit expires March 14, 2001. Various regulatory and environmental groups have commented on the draft permit, including comments that oppose NJDEP's proposed action. PSEG cannot predict the outcome of this proceeding.
If the NJDEP or the EPA were to impose a requirement at Salem, Hudson or Mercer, or at other Power generating stations, that closed cycle cooling be implemented, or that material operating restrictions be imposed, the continued operation of the station would need to be reassessed. Power believes that the current operations of its stations are in compliance with FWCPA and will vigorously prosecute its applications to continue operations of its generating stations with present cooling water intake structures. The EPA, as a result of litigation by environmental groups, is conducting a rulemaking under Section 316(b) of the Federal Clean Water Act that may result in the establishment of regulatory guidance on material issues with respect to 316(b) permitting decisions, such as guidance on determinations of adverse environmental impacts and best technology available. The rulemaking may impact NJDEP determinations with respect to Power's permit renewal applications.
The Delaware River Basin Commission (DRBC) issued a Revised Docket for Salem in 1995 (Revised Docket) approving a modification to the 1970 Salem Docket that approved the construction and operation of the station's cooling water system and the continued operation of the station's cooling water system for an additional five years. The DRBC modified the Revised Docket to provide that it shall remain in effect until six months after the NJDEP acts on Power's application for renewal of Salem's NPDES Permit, or at a later date established by the DRBC. While it is impossible to predict the timing and/or outcome of the review of these applications presently, an
18 unfavorable determination could have a material adverse effect on PSEG's financial position, results of operations and net cash flows.
Control of HazardousSubstances
PSE& G Manufactured Gas PlantRem ediation Program
For information regarding PSE&G's Manufactured Gas Plant Remediation Program, see Note 10. Commitments and Contingent Liabilities of Notes.
Hazardous Substances
Certain Federal and state laws authorize the 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 and Power's businesses, 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. For discussions of these hazardous waste issues and a discussion of potential liability for remedial action regarding the Passaic River, see Note 10. Commitments and Contingent Liabilities. For a discussion of remediation/clean-up actions involving PSE&G, see Item 3. Legal Proceedings.
PSE&G's transfer of generation-related assets to Power was considered under the requirements of the New Jersey Industrial Site Recovery Act (ISRA). In October 1999, PSE&G filed a request with the NJDEP for a determination that the sale involves a transfer to an affiliate and, as such, is not a covered transaction under ISRA. In January 2000, NJDEP concurred with this consensus. In the second quarter of 1999, PSE&G recorded a $53 million liability related to these obligations reflecting the estimated cost of remediation (see Note 2. Regulatory Issues and Accounting Impacts of Deregulation of Notes).
Other liabilities associated with environmental remediation include natural resource damages. The Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and the New Jersey Spill Compensation and Control Act (Spill Act) authorize Federal and state trustees for natural resources to assess "damages" against persons who have discharged a hazardous substance, which discharge resulted in an "injury" to natural resources. Until recently, the State trustee, NJDEP, has not aggressively pursued natural resource damages. In 1997, the NJDEP adopted changes to the Technical Requirements for Site Remediation pursuant to the Spill Act. Among these changes was a new provision requiring all persons conducting remediation to characterize "injuries" to natural resources. Further, these changes required persons to address those injuries through restoration or damages. The State's program is still developing and PSEG cannot assess the magnitude of the potential impact of this regulatory change. Although not currently estimable, these costs could be material.
ITEM 2. PROPERTIES PSE&G
PSE&G's First and Refunding Mortgage (Mortgage), securing the bonds issued thereunder, constitutes a direct first mortgage lien on substantially all of PSE&G's property. The asset transfer from PSE&G to Power in August 2000 was in exchange for a promissory note from Power in an amount equal to the purchase price of $2.786 billion. Power settled the promissory note on January 31, 2001 at which time the transferred assets were released from the lien of PSE&G's Mortgage.
19 The electric lines and gas mains of PSE&G are located over or under public highways, streets, alleys or lands, except where they are located over or under property owned by PSE&G or occupied by it under easements or other rights. These easements and rights are deemed by PSE&G to be adequate for the purposes for which they are being used.
PSE&G believes that it maintains insurance coverage against loss or damage to its principal properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost
Electric Transmission and DistributionProperties
As of December 31, 2000, PSE&G's transmission and distribution system included approximately 156,000 circuit miles, of which approximately 39,000 miles were underground, and approximately 813,000 poles, of which approximately 540,000 poles were jointly owned. Approximately 99% of this property is located in New Jersey.
In addition, as of December 31, 2000, PSE&G owned four electric distribution headquarters and five subheadquarters in four operating divisions, all located in New Jersey.
Gas DistributionProperties
As of December 31, 2000, the daily gas capacity of PSE&G's 100%-owned peaking facilities (the maximum daily gas delivery available during the three peak winter months) consisted of liquid petroleum air gas (LPG) and liquefied natural gas (LNG) and aggregated 3,317,000 therms (approximately 3,220,000 cubic feet on an equivalent basis of 1,030 Btu/cubic foot) as shown in the following table:
Daily Capacity Plant Location (Therms) Burlington LNG ...... Burlington, NJ 773,000 Camden LPG ...... Camden, NJ 384,000 Central LPG ...... Edison Twp., NJ 1,080,000 Harrison LPG ...... Harrison, NJ 1,080,000 Total ...... 33317,000
As of December 31, 2000, PSE&G owned and operated approximately 16,551 miles of gas mains, owned 11 gas distribution headquarters and two subheadquarters all in two operating regions located in New Jersey and owned one meter shop in New Jersey serving all such areas. In addition, PSE&G operated 61 natural gas metering or regulating stations, all located in New Jersey, of which 28 were located on land owned by customers or natural gas pipeline companies supplying PSE&G with natural gas and were operated under lease, easement or other similar arrangement. In some instances, the pipeline companies owned portions of the metering and regulating facilities.
Office Buildings and Facilities
2 6 PSE&G leases substantially all of a -story office tower for its corporate headquarters at 80 Park Plaza, Newark, New Jersey, together with an adjoining three-story building. PSE&G also leases other office space at various locations throughout New Jersey for district offices and offices for various corporate groups and services. PSE&G also owns various other sites for training, testing, parking, records storage, research, repair and maintenance, warehouse facilities and for other purposes related to its business.
20 In addition to the facilities in New Jersey and Pennsylvania as discusses above, as of December 31, 2000, PSE&G owned 41 switching and/or generating stations in New Jersey with an aggregate installed capacity of 30,417,670 kilovolt-amperes and 223 substations with an aggregate installed capacity of 7,396,000 kilovolt-amperes. In addition, six substations in New Jersey having an aggregate installed capacity of 108,000 kilovolt-amperes were operated on leased property.
Power
Power subleases approximately 60,000 square feet of office space from PSE&G in Newark, New Jersey. Other leased properties include an emergency media center (9,300 square feet) near Salem which is designed as an information clearinghouse in the event of a nuclear emergency. It also leases approximately 19,600 square feet of space in Hadley Road Training Center in South Plainfield, New Jersey from PSE&G. This space is used for fossil fuel procurement and materials management staff.
Through a subsidiary, Power owns a 50% interest in about 20,000 acres of restored wetlands and conservation facilities in the Delaware Estuary. This subsidiary was formed to formed acquire and own lands and other conservation facilities required to satisfy the condition of the NJPDES permit issued for Salem. Power also owns several other facilities including Hancock Bridge Administration and Processing Center buildings, as well as the Nuclear Training Center near Salem. Power also has an ownership interest in the 650-acre Merrill Creek Reservoir in Warren County, New Jersey which was constructed to store water for release to the Delaware River during periods of low flow. Power also owns the Maplewood Test Center and the Central Maintenance Shop at Sewaren.
Power believes that it maintains insurance coverage against loss or damage to its principal plants and properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost. For a discussion of nuclear insurance, see Note 10. Commitments and Contingent Liabilities of Notes.
21 Electric GenerationProperties
As of December 31, 2000, Power's share of installed generating capacity was 11,167 MW, as shown in the following table:
Total Owned Principal Capacity Capacity Fuels Name and Location (MW) Used Missions Steam: Hudson, Jersey City, NJ ...... 991 991 Coal/Gas Load Following M ercer, Hamilton, NJ ...... 648 648 Coal/Gas Load Following Sewaren, W oodbridge Twp., NJ ...... 453 453 Gas/Oil Load Following Linden, Linden, NJ ...... 430 430 Oil Load Following Keystone, Shelocta, PA- 22.84%(A)(B) ...... 1,700 388 Coal Base Load Conemaugh, New Florence, PA- 22.50% (A)(B) ...... 1,700 382 Coal Base Load Kearny, Kearny, NJ ...... 300 300 Oil Load Following Albany, Albany, NY ...... 380 380 Oil Load Following Total Steam ...... 6,602 3,972 Nuclear: (Capacity calculated in accordance with industry maximum dependable capability standards) Hope Creek, Lower Alloways Creek, NJ 95%(A) ...... 1,031 979 Nuclear Base Load Salem 1, Lower Alloways Creek, NJ 50%(A) ...... 1,106 553 Nuclear Base Load Salem 2, Lower Alloways Creek, NJ 50%(A) ...... 1,106 553 Nuclear Base Load Peach Bottom 2, Peach Bottom, PA 46.25%(AXC) ...... 1,092 506 Nuclear Base Load Peach Bottom 3, Peach Bottom, PA 46.25%(A)(C) ...... 1,092 506 Nuclear Base Load Total Nuclear ...... 5,427 3,097 Combined Cycle: Bergen, Ridgefield, NJ ...... 675 675 Gas Load Following Burlington, Burlington, NJ ...... 245 245 Gas Load Following Total Combined Cycle ...... 920 920 Combustion Turbine: Essex, Newark, NJ ...... 617 617 Gas/Oil Peaking Edison, Edison Township, NJ ...... 504 504 Gas/Oil Peaking Kearny, Kearny, NJ ...... 464 464 Gas/Oil Peaking Burlington, Burlington, NJ ...... 561 561 Oil Peaking Linden, Linden, NJ ...... 337 337 Gas/Oil Peaking Hudson, Jersey City, NJ ...... 129 129 Oil Peaking M ercer, Hamilton, NJ ...... 129 129 Oil Peaking Sewaren, W oodbridge Township, NJ ...... 129 129 Oil Peaking Bayonne, Bayonne, NJ ...... 42 42 Oil Peaking Bergen, Ridgefield, NJ ...... 21 21 Gas Peaking National Park, National Park, NJ ...... 21 21 Oil Peaking Salem, Lower Alloways Creek, NJ 50%(A) ...... 38 19 Oil Peaking Total Combustion Turbine ...... 2,992 2,973 Internal Combustion: Conemaugh, New Florence, PA- 22.50% (A) ...... 11 2 Oil Peaking Keystone, Shelocta, PA- 22.84%(A) ...... 11 3 Oil Peaking Total Internal Combustion ...... 22 5 Pumped Storage: Yards Creek, Blairstown, NJ- 50% (A)(D)(E) ...... 400 200 Peaking Total Operating Generation Plants ...... 16,363 11,167
(A) Power's share ofjointly owned facility. (B) Operated by Reliant Energy (C) Operated by Exelon (D) Operated by GPU Energy (E) Excludes energy for pumping and synchronous condensers.
22 As of December 31, 2000, Power had 3,660 MW of generating capacity in construction and advanced development as shown in the following table:
Total Owned Principal Capacity Capacity Fuels Used Missions Name and Location Expected Completion Date 0MW) Single Cycle: 500 500 Load Following Waterford (Phase 1), Ohio (June 2002) ...... Gas Combined Cycle: Gas Load Following Ridgefield, NJ (June 2002) ...... 510 510 Load Following Bergen, 1,150 1,150 Gas Indiana (May 2003) ...... Load Following Lawrenceburg, 350 350 Gas (Phase I1), Ohio (May 2003) ...... Load Following Waterford 1,150 1,150 Gas Linden, Linden, NJ (June 2003) ...... 3,660 3,660 Total Construction and Advanced Development ......
Energy Holdings
Energy Holdings does not own any real property. Energy Holdings subleases office space for its corporate headquarters at 80 Park Plaza, Newark, New Jersey from PSE&G. Energy Holdings' subsidiaries also lease office that it space at various locations throughout the world to support business activities. Energy Holdings believes to maintains adequate insurance coverage for properties in which its subsidiaries have an equity interest, subject cost. certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable
GenerationFacilities
Global has invested in the following generation facilities which are in operation or under construction or advanced development: Global's Net Equity Interest in Global's Total Ownership Total MW Interest MW Power Plants Location Primary Fuel Overatine Location Primarv Fuel United States Texas Independent Energy Guadalupe ...... TX Natural gas 1,000 50% 500113 NJ Natural gas 225 50% Eagle Point (A) ...... 90 HI Oil 180 50% Kalaeloa ...... GWF 21 50% 10 Petroleum coke Bay Area I ...... CA 50% 10 CA Petroleum coke 21 Bay Area II ...... 50% 10 CA Petroleum coke 21 Bay Area III ...... 50% 10 CA Petroleum coke 21 Bay Area IV ...... 50% 10 CA Petroleum coke 21 Bay Area V ...... 50% 14 CA Petroleum coke 27 Hanford ...... 35% 7 CA Biomass 21 Tracy ...... 40% 7 NH Biomass 16 Bridgewater ...... 9% 3 CA Solar 30 SEGS III ...... 16% 2 ME Hydro 15 Kennebec ...... 50% 8 PA Hydro 15 Conemaugh ...... 1,634 794 Total United States
23 GenerationFacilities-continued
Global's Net Equity Global's Interest in Total Ownership Total Overatin2 Power Plants Location Primary Fuel MW Interest MW International CTSN ...... Argentina Coal/Natural gas/Oil 650 19% 124 MPC Jingyuan - Units 5 and 6 ...... China Coal 600 15% 90 Tongzhou ...... China Coal 30 40% 12 Nantong ...... China Coal 24 46% 11 Jinqiao (Thermal Energy) ...... China Coal/Oil N/A 30% N/A Zuojiang - Units 1, 2 and 3 ...... China Hydro 72 30% 21 Fushi - Units I and 2 ...... China Hydro 36 35% 13 Shanghai BFG ...... China Blast furnace gas 50 16% 8 TGM ...... Venezuela Natural gas 40 9% 3 Total International 1,502 282 Total Operating Power Plants 3,136 1,076
In Power Plants in Construction or Service Advanced Develonment Date Texas Independent Energy Odessa ...... Texas Natural gas 1,000 50% 500 2001 Turboven M aracay ...... Venezue la Natural gas 60 50% 30 2001 Cagua ...... Venezue "la Natural gas 60 50% 30 2001 Valencia ...... Venezue la Natural gas 80 50% 40 2002 MPC Fushi - Unit 3 ...... China Hydro 18 35% 6 2001 Prisma 2000 Strongoli ...... Italy Biomass 40 35% 14 2002 Porto Empedocle ...... Italy Biomass 24 35% 8 2002 Crotone ...... Italy Biomass 20 35% 7 2001 Bando ...... Italy Biomass 20 70% 14 2001 Parana ...... Argentin a Natural gas 830 33% 274 2001 Rades ...... Tunisia Natural gas 471 60% 283 2001 PPN ...... India Naptha/Natural gas 330 20% 66 2001 Tri-Sakthi ...... India Coal 525 63% 331 2003 Tanir Bavi ...... India Naphtha 220 74% 163 2001 Chorzow ...... Poland Coal 220 90% 198 2003 Total Construction or Advanced Development 3,918 1,964 TOTAL GENERATION FACILITIES 7,054 3,040
(A) Subsequent to December 31, 2000, Global retired from its interest in the Eagle Point Cogeneration Partnership in exchange for a series of payments expected to total up to $290 million, to be received over the next five years, subject to certain contingencies.
24 DistributionFacilities
Global also has invested in the following distribution facilities: Global's Number of Ownership Location Customers Interest EDEN ...... Argentina 280,000 30% EDES ...... Argentina 140,000 30% EDELAP ...... Argentina 290,000 30% EDEERSA ...... Argentina 230,000 41% Rio Grande Energia ...... Brazil 960,000 32% Chilquinta Energia ...... Chile 450,000 50% Luz del Sur ...... Peru 680,000 43%
ITEM 3. LEGAL PROCEEDINGS
As previously disclosed, by complaints filed in 1995 and 1996, shareholder derivative actions on behalf of PSEG shareholders were commenced by purported shareholders against certain directors and officers. The four complaints generally sought recovery of damages for alleged losses purportedly arising out of PSE&G's operation of the Salem and Hope Creek generating stations, together with certain other relief, including removal of certain executive officers of PSE&G and PSEG and certain changes in the composition of PSEG's Board of Directors. By decision dated July 28, 1999, the Court granted the defendants' motions for summary judgment dismissing all four derivative actions. The plaintiffs have appealed in all three of these actions. PSEG cannot predict the outcome of these appeals. Public Service Enterprise Group Inc. by G. E. Stricklin, derivatively v. E. James Ferland, et. al., Superior Court of New Jersey, Chancery Division, Essex County, Docket No. C-160-96. Dr. Steven Fink and Dr. David Friedman, P.C. Profit Sharing Plan, derivatively, Lawrence R. Codey, et. al., Superior Court of New Jersey, Chancery Division, Essex County, Docket No. C-65-96. A. Harold Datz Pension and Profit Sharing Plan derivatively, et. al., v. Lawrence R. Codey, et. al., Superior Court of New Jersey, Chancery Division, Essex County, Docket No. C-68-96.
A complaint dated April 19, 1999 was received by PSEG naming as defendants the current directors of PSEG, and naming PSEG as a nominal defendant, from the same purported shareholder of PSEG who instituted the June 1998 proxy litigation, alleging that the 1999 proxy statement provided to shareholders of PSEG was false and misleading by reason, among other things, of failure to disclose certain material facts relating to (i) the controls over and oversight of PSEG's nuclear operations, (ii) the condition of problems at PSEG's nuclear operations and (iii) the derivative litigation described above. The complaint sought to have the 1999 proxy statement declared to be in violation of law, to set aside the election of directors of PSEG and the ratification of the selection of Deloitte & Touche LLP as PSEG's auditors at the 1999 annual shareholder meeting, and to require PSEG to conduct a special meeting of shareholders providing for election of directors following timely dissemination of a proxy statement approved by the Court hearing the matter, which should include as nominees for election as directors persons having no previous relationship with PSEG or the current directors, and other relief. On August 2, 1999, the Court issued an order granting the defendants' motion to dismiss this complaint. Plaintiff appealed, and on March 29, 2000, the Third Circuit Court of Appeals issued an order affirming the lower court's dismissal of this action. G. E. Stricklin v. L Lerner,et. al., United States District Courtfor the Eastern District of Pennsylvania. Civil Action No. 99-1950.
The Brazilian Consumer Association of Water and Energy has filed a lawsuit against Rio Grande Energia S.A. (RGE), a Brazilian distribution company of which Global is a 32% owner, and two other utilities, claiming that certain value added taxes and the residential tariffs that are being charged by such utilities to their respective customers are illegal. RGE believes that its collection of the tariffs and value added taxes are in compliance with applicable tax and utility laws and regulations. While it is the contention of RGE that the claims are without merit, and that it has valid defenses and potential third party claims, an adverse determination could have a material adverse effect on PSEG's financial condition, results of operations and net cash flows. Assobraee-Associacao Brasileira de Consumidores de Agua e Energia Eletrica v. Rio Grande Energia S/A -RGE, CEEE and AES Sul, FirstPublic Treasury Court/City of Porto Alegre. ProceedingNo. 101214451.
25 Brasileira de Consumidores de Agua e Energia Eletrica v. Rio Grande Energia S/A -RGE, CEEE and AES Sul, FirstPublic Treasury Court/City of Porto Alegre. ProceedingNo. 101214451.
See information on the following regulatory proceedings at the pages indicated:
(1) Pages 11, 32, 64, and 65. Proceedings before the BPU in the matter of the Energy Master Plan Phase II Proceeding to investigate the future structure of the Electric Power Industry, Docket Nos. EX94120585Y, E097070461, E097070462 and E097070463.
(2) Pages 11, 32, 64 and 65. Appeals of the BPUs Final Order and Finance Order in the Energy Master Plan Proceedings. Docket Nos. C-1263-99, C-1265-99 and C-1413-99.
(3) Page 18. Administrative proceedings before the NJDEP under the FWPCA for certain electric generating stations.
(4) Page 81. Investigation and additional investigation by the EPA regarding the Passaic River site. Docket No. EX93060255.
(5) Pages 19 and 81 regarding PSE&G's MGP Remediation Program.
In addition, see the following environmental related matters involving governmental authorities. Based on current information, PSEG and PSE&G do not expect expenditures for any such site, individually or all such current sites in the aggregate, to have a material effect on their financial condition, results of operations and net cash flows.
(1) Claim made in 1985 by U.S. Department of the Interior under CERCLA with respect to the Pennsylvania Avenue and Fountain Avenue municipal landfills in Brooklyn, New York, for damages to natural resources. The U.S. Government alleges damages of approximately $200 million. To PSE&G's knowledge there has been no action on this matter since 1988.
(2) Duane Marine Salvage Corporation Superfund Site is in Perth Amboy, Middlesex County, New Jersey. PSE&G was named as one of several potentially responsible parties (PRPs) with regard to contamination of this site.
(3) Various Spill Act directives were issued by NJDEP to PRPs, including PSE&G with respect to the PJP Landfill in Jersey City, Hudson County, New Jersey, ordering payment of costs associated with operating and maintenance expenses, interim remedial measures and a Remedial Investigation and Feasibility Study (RI/FS) in excess of $25 million. The directives also sought reimbursement of NJDEP's past and future oversight costs and the costs of any future remedial action.
(4) Claim by the EPA, Region III, under CERCLA with respect to a Cottman Avenue Superfund Site, a former non-ferrous scrap reclamation facility located in Philadelphia, Pennsylvania, owned and formerly operated by Metal Bank of America, Inc. PSE&G, other utilities and other companies are alleged to be liable for contamination at the site and PSE&G has been named as a PRP. A Pre-Design Investigative Report was submitted to the EPA on January 21, 2000, which presents several alternatives for implementation of an EPA selected remediation remedy. Dependent upon the EPA's approval of the proposed remedy implementation alternatives, the costs of remedy implementation are estimated to range from $14 million to $24 million. PSE&G's share of the remedy implementation costs are estimated between $4 million and $8 million.
Additionally, with respect to this site, the United States of America application 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 CERCLA was granted. PSE&G and one other utility were named as third party defendants in the foregoing captioned matter.
26 (5) The Klockner Road site is located in Hamilton Township, Mercer County, New Jersey, and occupies approximately two acres on PSE&G's Trenton Switching Station property. PSE&G has entered into a memorandum of agreement (MOA) with the NJDEP for the Klockner Road site pursuant to which PSE&G will conduct an RI/FS and remedial action, if warranted, of the site. Preliminary investigations indicated the potential presence of soil and groundwater contamination at the site.
(6) In 1991, the NJDEP issued Directive and Notice to Insurers Number Two (Directive Two) to 24 Insurers and 52 Respondents, including PSE&G, in connection with an investigation and remediation of the Global Landfill Site in Old Bridge Township, Middlesex County, New Jersey seeking recovery of past and anticipated future NJDEP response costs ($37 million). PSE&G and other participating PRPs have agreed with NJDEP to a partial settlement of such costs and to perform the remedial design and remedial action. In 1996, 13 of the Directive Two Respondents, including PSE&G, filed a contribution action pursuant to CERCLA and the Spill Act against approximately 190 parties seeking contribution for an equitable share of all liability for response costs incurred and to be incurred in connection with the site. In September 1997, the NJDEP issued a Superfund record of decision (ROD) with estimated cost of $3.7 million.
(7) In 1991, the NJDEP issued Directive and Notice To Insurers Number One (Directive No. One) to 50 insurers and 20 respondents, including PSE&G, seeking from the respondents payment of $5.5 million of NJDEP's anticipated costs of remedial action and .of administrative oversight at the Combe Fill South Sanitary Landfill in Washington and Chester Townships, Morris County, New Jersey (Combe Site). The $5.5 million represents NJDEP's 10% share of total estimated site remediation costs and administrative oversight costs pursuant to a cooperative agreement with the United States concerning the selected remedial action for the site. In 1996, the NJDEP issued Directive Number Two (Directive No. Two) to 37 respondents, including PSE&G, directing the respondents to arrange for the operation, maintenance and monitoring of the implemented remedial action described therein or pay the NJDEP's future costs of these activities, estimated to be $39 million. In addition, Directive No. Two directs the respondents to prepare a work plan for the development and implementation of a Natural Resource Damage Restoration Plan. In October 1998, the NJDEP and The United States of America filed separate cost recovery actions pursuant to CERCLA and/or the Spill Act against approximately 30 parties seeking recovery of their respective shares of past and future site investigation and remediation response and administrative oversight costs incurred and to be incurred at the site. Third party contribution actions were also filed in each of the foregoing cost recovery actions seeking contribution for an equitable share of all liability for these same costs from approximately 170 third party defendants. PSE&G is a named defendant in the NJDEP cost recovery action and a named third party defendant in the contribution action filed in the United States' lawsuit.
(8) Spill Act Multi-Site Directive (Directive) issued by the NJDEP to PRPs, including PSE&G, listing four separate sites, including the former solid waste bulking and transfer facility called the Marvin Jonas Transfer Station (Sewell Site) in Deptford Township, Gloucester County, New Jersey. With regard to the Sewell Site, this Directive ordered approximately 350 PRPs, including PSE&G, to enter into an Administrative Consent Order (ACO) with NJDEP, requiring them to remediate the Sewell Site. PSE&G and certain other de minimis parties have accepted a settlement offer from other PRPs to resolve their liability for response and removal costs at the site.
(9) The NJDEP assumed control of a former petroleum products blending and mixing operation and waste oil recycling facility in Elizabeth, Union County, New Jersey (Borne Chemical Co. site) and issued various directives to a number of entities including PSE&G requiring performance of various remedial actions including: establishment of security at the site; removal and off-site disposal of containerized wastes at the site; and conduct of a remedial investigation of the site. PSE&G's nexus to the site is based upon the shipment of certain waste oils to the site for recycling. PSE&G and certain of the other entities named in NJDEP directives are members of a PRP group that have been working together to satisfy NJDEP
27 requirements including: funding of the site security program; containerized waste removal; and a site remedial investigation program.
(10) One Argentine electric distribution company in which Global has an interest has been notified of a claim regarding alleged PCB contamination at one of its sites. Clean up costs are estimated at approximately $100,000 and the distribution company is subject to penalties of approximately $1 million. Global has a 30% interest in this company. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
PSEG and PSE&G: Inapplicable.
28 PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
PSEG's Common Stock is listed on the New York Stock Exchange, Inc. As of December 31, 2000, there were 126,706 holders of record of PSEG Common Stock. All of PSE&G's common stock is owned by PSEG.
The following table indicates the high and low sale prices for PSEG's Common Stock and dividends paid for the periods indicated:
Dividend Common Stock High Low Per Share 2000: First Quarter ...... $36.00 $25.69 $0.54 Second Quarter ...... 38.19 29.25 0.54 Third Quarter ...... 45.69 32.88 0.54 Fourth Quarter ...... 50.00 38.88 0.54
1999: First Quarter ...... $40.38 $36.50 $0.54 Second Quarter ...... 42.63 37.50 0.54 Third Quarter ...... 42.00 37.06 0.54 Fourth Quarter ...... 40.00 32.00 0.54
For additional information concerning dividend history, policy and potential preferred voting rights, restrictions on payment and common stock repurchase programs, see Liquidity and Capital Resources and External Financings of MD&A and Note 6. Schedule of Consolidated Capital Stock and Other Securities of Notes.
29 ITEM 6. SELECTED FINANCIAL DATA
PSEG
The information presented below should be read in conjunction with PSEG's Consolidated Financial Statements and Notes thereto. Years Ended December 31, 2000 1999 1998 1997 1996 (Millions of Dollars, where applicable)
Total Operating Revenues ...... $6,848 $6,458 $6,010 $6,177 $6,106
Income from Continuing Operations ...... $764 $723 $644 $560 $588 Income from Discontinued Operations (A) ...... 24 Income Before Extraordinary Item ...... 764 723 644 560 612 Extraordinary Item (B) ...... (804) Net Income (Loss) ...... $764 $(81) $644 $560 $612
Earnings per Average Share (Basic and Diluted): From Continuing Operations ...... $3.55 $3.29 $2.79 $2.41 $2.42 From Discontinued Operations (A) ...... 10 Before Extraordinary Item ...... 3.55 3.29 2.79 2.41 2.52 Extraordinary Item (B) ...... (3.66) Total Earnings per Average Share ...... $3.55 $(0.37) $2.79 $2.41 $2.52
Dividends Paid per Share ...... $2.16 $2.16 $2.16 $2.16 $2.16
As of December 3 1: Total Assets ...... $20,796 $19,015 $17,991 $17,979 $16,795 Long-Term Liabilities: Long-Term Debt ...... $5,297 $4,575 $4,763 $4,885 $4,580 Other Noncurrent Liabilities ...... $1,762 $1,562 $764 $609 $544
Preferred Stock With Mandatory Redemption ...... $75 $75 $75 $75 $150 Monthly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures ...... $210 $210 $210 $210 $210 Quarterly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures ...... $303 $303 $303 $303 $208 Quarterly Guaranteed Preferred Beneficial Interest in PSEG's Subordinated Debentures ...... $525 $525 $525
Ratio of Earnings to Fixed Charges (C) ...... 2.73 3.09 2.86 2.55 2.68
(A) On July 31, 1996, Energy Holdings sold Energy Development Corporation (EDC). As a result, Consolidated Financial Statements previously issued were restated to give effect to the classification of EDC as discontinued operations.
(B) See Note 2. Regulatory Issues and Accounting Impacts of Deregulation.
(C) Excludes income and expenses from discontinued operations and Extraordinary Item.
30 PSE&G Financial The information presented below should be read in conjunction with PSE&G's Consolidated Statements and Notes thereto. Years Ended December 31, 2000 1999 1998 1997 1996 (Millions of Dollars, where applicable) $5,803 Total Operating Revenues ...... $5,888 $5,840 $5,568 $5,833 $587 $653 $602 $528 $535 Income Before Extraordinary Item ...... (804) Extraordinary Item (A)...... $(l51) $602 $528 $535 Net Income (Loss)...... $587
As of December 31: T otal A ssets ...... $15,267 $14,724 $14,669 $14,844 $14,700 Long-Term Liabilities: $3,099 Long-Term Debt...... $3,590 $4,045 $4,127 $4,107 $1,535 $741 $586 $536 Other Noncurrent Liabilities ...... $690 $75 $150 Preferred Stock With Mandatory Redemption ...... $75 $75 $75 Monthly Guaranteed Preferred Beneficial Interest in $210 $210 PSE&G's Subordinated Debentures ...... $210 $210 $210 Quarterly Guaranteed Preferred Beneficial Interest in $303 $303 $303 $303 $208 PSE&G's Subordinated Debentures ...... 3.15 3.58 3.26 2.74 2.83 Ratio of Earnings to Fixed Charges (B) ...... Ratio of Earnings to Fixed Charges plus Preferred 3.04 3.46 3.15 2.64 2.62 Securities Dividend Requirements (B) ......
(A) See Note 2. Regulatory Issues and Accounting Impacts of Deregulation.
(B) Excludes extraordinary item.
31 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS PSEG
This discussion makes reference to the Consolidated Financial Statements and related Notes to Consolidated Financial Statements (Notes) of Public Service Enterprise Group Incorporated (PSEG) and should be read in conjunction with such statements and notes.
CORPORATE STRUCTURE
PSEG has four principal direct wholly-owned subsidiaries: Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power), PSEG Energy Holdings Inc. (Energy Holdings) and PSEG Services Corporation (Services). As of December 31, 2000, PSE&G, Power and Energy Holdings comprised approximately 60%, 14% and 25% of PSEG's consolidated assets and contributed approximately 76%, 14% and 12% of PSEG's net income for the year ended December 31, 2000.
PSE&G is an operating public utility company engaged principally in the transmission, distribution and sale of electric energy and gas service in New Jersey. Power has three principal direct wholly-owned operating subsidiaries: PSEG Fossil LLC (Fossil), which owns and operates fossil fueled electric generation facilities; PSEG Nuclear LLC (Nuclear), which owns and operates nuclear fueled electric generation facilities; and PSEG Energy Resources and Trade LLC (ER&T), which operates a wholesale energy trading business. On August 21, 2000, pursuant to the terms of the Final Order issued by the New Jersey Board of Public Utilities (BPU) under the New Jersey Energy Master Plan (Energy Master Plan Proceedings) and the New Jersey Electric Discount and Energy Competition Act (Energy Competition Act), PSE&G transferred its generation-related assets and liabilities to Power and its subsidiaries Nuclear, Fossil, and its wholesale power contracts to ER&T in exchange for a promissory note from Power in an amount equal to the total purchase price of $2.786 billion. Power settled the promissory note on January 31, 2001 at which time the transferred assets were released from the lien of PSE&G's First and Refunding Mortgage. PSE&G continues to own and operate its regulated electric and gas transmission and distribution business.
Through its subsidiaries, Power provides energy and capacity to PSE&G, including PSE&G's BPU-mandated basic generation service (BGS) obligation, under certain contracts and markets electricity, natural gas, capacity and ancillary services throughout the Eastern United States.
Energy Holdings is the parent of three energy-related lines of business through its principal wholly-owned subsidiaries: PSEG Global Inc. (Global), which develops, acquires, owns and operates electric generation and distribution facilities and engages in power production and distribution, including wholesale and retail sales of electricity, in selected domestic and international markets; PSEG Resources Inc. (Resources), which provides energy infrastructure financing and invests in energy-related financial transactions and manages a diversified portfolio of investments including leveraged leases, leveraged buyout (LBO) funds, limited partnerships and marketable securities; and PSEG Energy Technologies Inc. (Energy Technologies), an energy management company that constructs, operates and maintains heating, ventilating and air conditioning (HVAC) systems for, and provides energy-related engineering, consulting and mechanical contracting services to, industrial and commercial customers in the Northeastern and Middle Atlantic United States. Enterprise Group Development Corporation (EGDC) has been conducting a controlled exit from the real estate business. Energy Holdings also has a finance subsidiary, PSEG Capital Corporation (PSEG Capital), which serves as a financing vehicle for Energy Holdings' subsidiaries and borrows on the basis of a minimum net worth maintenance agreement with PSEG. Energy Holdings is also the parent of Enterprise Group Development Corporation (EGDC), a nonresidential real estate development and investment business and has been conducting a controlled exit from this business since 1993.
Services was formed in 1999 and provides management and administrative services to PSEG and its subsidiaries.
32 OVERVIEW OF 2000 AND FUTURE OUTLOOK
The electric and gas utility industries in the United States and around the world continue to experience significant change. Deregulation, restructuring, privatization and consolidation are creating opportunities and risks for PSEG and its subsidiaries. PSEG has successfully completed the transition from a regulated New Jersey utility to a competitive global energy company and estimates a 7% compound annual growth rate in earnings per share over the next five years.
The Energy Competition Act and the related BPU proceedings, including the Final Order, referred to as the Energy Master Plan Proceedings, have dramatically reshaped the utility industry in New Jersey and have directly affected how PSEG will conduct business, and therefore, its financial prospects in the future. PSEG has realigned its organizational structure to address the competitive environment brought about by the deregulation of the electric generation industry in New Jersey and the Eastern U.S. PSEG has been engaged in the competitive energy business for a number of years through certain of its unregulated subsidiaries; however, competitive businesses now constitute a much larger portion of PSEG's activities. It is expected that by July 31, 2003, the end of the transition period under the Energy Master Plan Proceedings, PSEG's unregulated subsidiaries (Energy Holdings and Power) will contribute approximately 75% of PSEG's earnings. Additionally, PSEG will be more dependent on cash flows generated from its unregulated operations for its capital needs. As the unregulated portion of the business continues to grow, financial risks and rewards will be greater, financial requirements will change and the volatility of earnings and cash flows will increase.
In the Final Order, the BPU concluded that PSE&G should recover up to $2.94 billion (net of tax) of its generation-related stranded costs, through securitization of $2.4 billion and an opportunity to recover up to $540 million (net of tax) of its unsecuritized generation-related stranded costs on a net present value basis through a market transition charge (MTC). Following the issuance of the Final Order, the BPU issued its Finance Order approving, among other things, the issuance and sale of $2.525 billion of transition bonds, including an estimated $125 million of transaction costs, by PSEG Transition Funding LLC, a wholly owned subsidiary of PSE&G. On January 31, 2001, PSE&G Transition Funding LLC purchased PSE&G's property right in the securitization transition charge (STC) and remitted the proceeds of the issuance of the transition bonds as consideration for such property right. PSE&G used the proceeds to retire a portion of PSEG's outstanding debt and equity. In accordance with the Final Order, PSE&G reduced customer rates an additional 2% after the securitization transaction, will reduce rates another 2% in August of 2001 and 4.9% in August 2002, for a total 13.9% rate reduction since August 1999.
PSEG will continue to pursue its strategies to grow its energy-related businesses, including expansion through business combinations. More emphasis will be placed on finding opportunities for expansion outside of its traditional utility services and markets. Power's business strategy is to size its fleet of generation assets to take advantage of market opportunities, while seeking to increase its value and manage commodity price risk through its wholesale trading activity. Much of PSEG's earnings growth is expected to come from its generation business. Power has plans to increase capacity an additional 3,000 MW to 8,000 MW over the next five years by adding capacity to existing sites in New Jersey as well as new sites in the Northeast and Midwest. PSEG has also positioned Energy Holdings as a major part of its planned growth'strategy. In order to achieve this strategy, Global will focus on generation and distribution investments within targeted high-growth regions. A significant portion of Global's growth is expected to occur internationally due to the current and anticipated growth in electric capacity required in certain regions of the world. This growth was evidenced in 2000 by its commitment to construct several significant power plants in Texas, India, Poland and Tunisia and its acquisition of an electric distribution company in Argentina. Global expects that certain generation projects (totaling 1,373 MW net) will reach commercial operation in 2001. Resources will utilize its market access, industry knowledge and transaction structuring capabilities to expand its energy-related financial investment portfolio. Energy Technologies will continue to provide HVAC contracting and other energy-related services to industrial and commercial customers in the Northeastern and Middle Atlantic United States. PSE&G's transmission and distribution objective is to provide safe, cost-effective, high quality, reliable service.
To the extent that the discussion that follows reports on business conducted under full monopoly regulation of the utility businesses, it must be understood that such businesses have changed due to the deregulation of the electric
33 generation and natural gas commodity sales businesses and the subsequent sale of the generation business to Power. Past results are not an indication of future business prospects or financial results.
RESULTS OF OPERATIONS
Earnings (Losses) Year Ended December 31, 2000 1999 1998 (Millions of Dollars) PSE&G, Before Extraordinary Item ...... $ 5,78 $644 $ 593 PSE&G Extraordinary Item ...... (804) Total PSE&G ...... 5778 (160) 593 9 Energy Holdings ...... 90 83 51 Power ...... 10 $4 PSEG* ...... 8) (4) 64 S$(81) Total PSEG ...... $ 76 $ 644
* Includes after-tax effect of interest on certain financing transactions.
Contribution to Earnings Per Share (Basic and Diluted) Year Ended December 31, 2000 1999 1998 PSE&G, Before Extraordinary Item $ 2.69 $ 2.93 $ 2.57 PSE&G Extraordinary Item - (3.66) Total PSE&G 2.69 (0.73) 2.57 Energy Holdings 0.42 0.38 0.22 Power 0.48 - PSEG* (0.04) (0.02) Total PSEG $ 3.55 $ (0.37) $ 2.79
* Includes after-tax effect of interest on certain financing transactions.
Basic and diluted earnings per share of PSEG common stock (Common Stock) were $3.55 for the year ended December 31, 2000, an increase of $0.26 per share, or 8% from the comparable 1999 period, excluding the extraordinary charge discussed below.
Excluding the extraordinary charge, PSE&G's and Power's combined contribution to earnings per share of Common Stock in 2000 increased $0.24 from 1999, including $0.08 of accretion as a result of PSEG's stock repurchase program. This increase was primarily due to lower depreciation and amortization resulting from the amortization of the Excess Depreciation Reserve beginning in January 2000 and the lower depreciation resulting from the lower recorded amounts of the generation-related assets resulting from the 1999 impairment recorded pursuant to Statement of Financial Accounting Standards (SFAS) 121, "Accounting for the Impairment of Long Lived Assets and for Long-Lived Assets to Be Disposed Of' (SFAS 121). Also contributing to the increase were increased sales due to favorable weather conditions in the fourth quarter of 2000 and higher profits realized from energy trading activities. The increase in earnings was partially offset by the 5% electric rate reduction, beginning August 1, 1999 coupled with a charge to income in the third quarter of 2000 related to MTC recovery.
Energy Holdings' contribution to earnings per share of Common Stock in 2000 increased $0.04 from 1999 primarily due to the better overall performance of Global, which benefited from favorable performance by its domestic generation assets and by its investments made in Latin America distribution assets in 1999. The increase in
34 earnings was partially offset by increased losses at Energy Technologies, primarily due to a pre-tax restructuring charge of $6.6 million.
In 1999, PSE&G recorded an extraordinary charge to earnings of $804 million, net of tax, as a result of the BPU's Summary Order in the Energy Master Plan Proceedings. For further discussion, see Note 2. Regulatory Issues and Accounting Impacts of Deregulation. Excluding that extraordinary charge, basic and diluted earnings per share of Common Stock were $3.29 in 1999, representing an increase of $0.50 per share, or 18% from 1998.
Excluding the extraordinary charge, PSE&G's contribution to earnings per share of Common Stock in 1999 increased $0.36 from 1998, including $0.14 as a result of PSEG's stock repurchase program. This increase was primarily due to increased sales of gas and electricity resulting from favorable weather conditions in 1999 augmented by positive economic factors in New Jersey and profits realized from wholesale energy activities. In addition, generation-related depreciation expenses were lower for a portion of 1999 as a result of the SFAS 121 impairment write-down, partially offset by changes in depreciation and capitalization policies stemming from the discontinuation of SFAS 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). The increase in earnings was also partially offset by the 5% electric rate reduction, beginning August 1, 1999 coupled with higher operating and maintenance expenses, including higher transmission, distribution and wholesale energy costs, than those incurred in 1998.
Energy Holdings' contribution to earnings per share of Common Stock in 1999 increased $0.16 from 1998 primarily due to the better overall performance of Resources, Global and Energy Technologies and $0.02 of accretion due to PSEG's stock repurchase program. The improvements were attributable largely to Resources which benefited from an upturn in the equity markets as compared to 1998. In addition, Energy Holdings' results reflect Global's gain from the sale of its interest in a co-generation facility partially offset by impairment write-downs of other investments in Global's portfolio.
PSE&G and Power - Revenues
Under the BGS contract between PSE&G and Power, PSE&G pays a fixed price for energy and capacity provided by Power and charges such costs to its BGS customers. As a result, Power, rather than PSE&G, is subject to price risk related to market exposures for supplying BGS customers. Power has entered into forwards, futures, swaps and options to manage price risk exposure for its commitments to meet PSE&G's BGS obligation in addition to Power's other supply contracts. The BGS contract between Power and PSE&G expires July 31, 2002. Thereafter, supply of electricity to serve PSE&G's BGS load will be determined by competitive bid in accordance with the requirements of the BPU.
Power's earnings are exposed to the risks of the competitive wholesale electricity market to the extent that Power has to purchase energy and/or capacity or generate energy to meet its obligations to supply power to PSE&G at market prices or costs, respectively, which approach or exceed the BGS contract rate. To mitigate this risk, Power's policy is to use derivatives, consistent with its business plans and prudent practices and to build and purchase additional capacity in the PJM and surrounding regions. This risk will be further affected by PSE&G customer migration from BGS to third party suppliers (TPS) and from TPS back to BGS. Power also participates in the competitive wholesale electricity market for other items such as energy, capacity and ancillary services. Certain of the below listed year-to-year variances did not impact earnings as there was an offsetting variance in expense.
To the extent fuel revenue and expense flowed through the Electric Levelized Energy Adjustment Clause (LEAC) through July 31, 1999, the Levelized Gas Adjustment Clause (LGAC), the Societal Benefits Clause (SBC) or the non-utility generation market transition charge (NTC) mechanisms, as established by the BPU with respect to PSE&G's rates, variances in certain revenues and expenses offset and thus had no effect on earnings. On August 1, 1999, the LEAC mechanism was eliminated as a result of the Final Order. This has increased earnings volatility since Power now bears the full risks and rewards of changes in nuclear and fossil generating fuel costs and replacement power costs. See Note 2. Regulatory Issues and Accounting Impacts of Deregulation and Note 3. Regulatory Assets and Liabilities of Notes for a discussion of LEAC, LGAC, SBC, NTC, Remediation Adjustment Clause (RAC) and Demand Side Management (DSM) and their status under the Energy Master Plan Proceedings.
35 Electric
Year Ended December 31, 2000 1999 1998 (Millions)
PSE&G $3,748 $4,123 $4,009 Power 1,037 - Intercompany Eliminations* (871) - Total Electric Revenues $3,914 $4,123 $4,009
* Represents the revenue Power receives from PSE&G for BGS and MTC.
Revenues decreased $209 million or 5% in 2000 as compared to 1999 primarily due to a $115 million decrease in MTC revenues, primarily resulting from an $88 million pre-tax charge to income related to MTC recovery, combined with the effects of the 5% rate reduction required by the Final Order which decreased generation revenues by approximately $120 million. The reduction in revenues resulting from customer migration was substantially offset by higher interchanged sales. Also offsetting the decrease in revenues were higher profits related to wholesale energy trading activities and higher revenues relating to Power's acquisition of the Albany Steam Station in May 2000.
Revenues increased $114 million or 3% in 1999 as compared to 1998 primarily due to favorable weather conditions in 1999 augmented by positive economic factors in New Jersey. These factors increased both generation and transmission and distribution revenues; however, the increase in generation revenues was partially offset by a 5% rate reduction, effective on August 1, 1999, which decreased generation revenues by approximately $80 million through December 31, 1999. The increase was also due to higher margins realized from wholesale energy trading activities than in 1998. Also, higher DSM revenues in 1999 than in 1998 contributed to increased distribution revenues.
Gas
Revenues increased $423 million or 25% in 2000 as compared to 1999 primarily due to increases in natural gas prices being passed along to customers under certain transportation only contracts. Under these contracts, PSE&G is responsible only for delivery of gas to its customers. Such customers are responsible for payment to PSE&G for the cost of the commodity and as PSE&G's costs for these customers increase, the customer's rates will increase. Also contributing to this increase were higher sales resulting from colder weather in the fourth quarter of 2000 as compared to the same period in 1999 and higher rates approved by the BPU to allow PSE&G to recover for increasing natural gas costs. The potential loss of residential customers due to the opening of competition in 2000 could reduce future revenues.
Revenues increased $158 million or 10% in 1999 as compared to 1998. The increase was primarily due to increased revenues from gas appliance service contracts and higher sales to large commercial and industrial customers than in 1998. Additionally, favorable weather in 1999 contributed to the increases.
36 PSE&G and Power - Expenses
ElectricEnergT Costs Year Ended December 31, 2000 1999 1998 (Millions)
PSE&G $1,520 $908 $945 - Power 284 -- Intercompany Eliminations* (871) Total Electric Energy Costs $933 $908 $945
* Represents the amounts PSE&G paid Power for BGS and MTC.
Electric Energy Costs increased $25 million or 3% in 2000 as compared to 1999. The increase was primarily 2000. due to higher fuel costs and additional costs related to the acquisition of the Albany Steam Station in May
Electric Energy Costs decreased $37 million or 4% in 1999 as compared to 1998. The decrease was primarily due to lower prices for power purchases. an Due to the elimination of the LEAC on August 1, 1999, the historical trends can no longer be considered that indication of future Electric Energy Costs. Given the elimination of the LEAC, the lifting of the requirements cost of electric energy offered for sale in the PJM Interconnection LLC (PJM) regional pool not exceed the variable involving producing such energy (capped at $1,000 per megawatt-hour), the absence of a PJM price cap in situations on PSEG's emergency purchases and the potential for plant outages, price movements could have a material impact and Power's financial condition, results of operations or net cash flows.
Gas Costs for Gas Costs increased $391 million or 38% in 2000 as compared to 1999 primarily due to the higher prices the fourth natural gas. Also contributing to the increase was higher demand for natural gas due to colder weather in quarter of 2000 as compared to the same period in 1999.
Gas Costs increased $68 million or 7% in 1999 as compared to 1998 due to higher sales to large commercial of and industrial customers and increased sales of gas resulting from colder weather in the first and second quarters 1999 than in 1998.
Due to the operation of the Levelized Gas Adjustment Clause (LGAC) mechanism, variances in gas revenues and costs offset and had no direct effect on earnings.
37 Operation and Maintenance
Year Ended December 31, 2000 1999 1998 (Millions)
PSE&G $1,214 $1,573 $1,385 Power 363 -- - Total Operation and Maintenance $1,577 $1,573 $1,385
Operation and Maintenance expense increased $4 million or 0.3% in 2000 as compared to 1999.
Operation and Maintenance expense increased $188 million or 14% in 1999 as compared to 1998. The increase was primarily due to the change in the capitalization policy for PSE&G's electric generation business (see Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies of Notes) and higher costs related to wholesale power activities. In addition, there were higher information technology costs, including costs related to Year 2000 readiness, and higher material and outside services costs in 1999 attributable to several factors, including restoration work required in the wake of Tropical Storm Floyd and the flooding and damage it caused. Also contributing to the increase were higher costs associated with the preparation for deregulation and higher DSM recovery of previously deferred expenses in 1999 than in 1998.
Depreciation and Amortization
Year Ended December 31, 2000 1999 1998 (Millions)
PSE&G $291 $529 $649 Power 58 -- - Total Depreciation and Amortization $349 $529 $649
Depreciation and Amortization expense decreased $180 million or 34% in 2000 as compared to 1999. The decrease was primarily due to the amortization of the regulatory liability for the excess electric distribution depreciation reserve at PSE&G, which amounted to approximately $125 million as of December 31, 2000. Also contributing to the decrease was lower depreciation resulting from the lower net book value balances of the generation-related assets, which were transferred to Power. The generation-related asset balances were reduced as of April 1, 1999 as a result of the impairment recorded pursuant to SFAS 121. In 2001, with the securitization transaction complete, the regulatory asset recorded in April 1999 for PSE&G's stranded costs will be amortized with such amortization expense partially offsetting these decreases (See Note 3. Regulatory Assets and Liabilities of Notes).
Depreciation and Amortization expense decreased $120 million or 18% in 1999 as compared to 1998. The 1999 decrease was due to lower net book value balances of PSE&G's generation-related assets, which were reduced as a result of the impairment write-down recorded pursuant to SFAS 121. These decreases were partially offset by higher depreciation rates for generation-related assets beginning April 1, 1999 due to the change in depreciation policy and by higher depreciation expense related to capital additions to the transmission and distribution business.
38 Interest Expense
Year Ended December 31, 2000 1999 1998 (Millions)
PSE&G $254 $387 $378 Power 147 $387 $378 Total Interest Expense $401
Interest expense increased $14 million or 4% in 2000 as compared to 1999 and $9 million or 2% in 1999 as compared to 1998. The increases were primarily due to increased short-term debt.
Income Taxes
Year Ended December 31, 2000 1999 1998 (Millions)
$404 PSE&G $407 $510 Power 66 $510 $404 Total Income Taxes $473
Income Taxes decreased $37 million or 7% in 2000 as compared to 1999. The decrease was primarily due to lower effective tax rates relating to the amortization of the excess depreciation reserve for electric distribution.
Income Taxes increased $106 million or 26% in 1999 as compared to 1998. The increase was primarily due to higher pre-tax operating income.
Taxes Other Than Income Taxes Year Ended December 31, 2000 1999 1998 (Millions) $208 PSE&G $166 $194 Power 16 $194 $208 Total Taxes Other Than Income Taxes $182
Taxes Other Than Income Taxes include the Transitional Energy Facility Assessment (TEFA). Taxes Other Than Income Taxes decreased $12 million or 6% in 2000 as compared to 1999. This decrease was due to New Jersey energy tax reform and the five-year phase out of the TEFA commencing in January 1999. Effective January 1, 2000, revised rates became effective which reflected two years phase out of the TEFA. See Note 13. Income Taxes of Notes for other impacts of New Jersey energy tax reform.
Taxes Other Than Income Taxes decreased $14 million or 7% in 1999 as compared to 1998. This decrease was also due to New Jersey energy tax reform and the five-year phase out of the TEFA commencing in January 1999.
39 Energf Holdings - Revenues
Revenues increased $177 million from $618 million to $795 million in 2000 as compared to 1999. The increase was due to an increase of $28 million at Resources due to higher leveraged lease income from new leveraged lease investments, a $120 million increase in revenues at Energy Technologies due to the addition of revenues from acquisitions of various HVAC companies in 2000 and 1999 and a $28 million increase in revenues at Global primarily due to improvement in revenues from domestic generation assets as well as the addition of revenues from the distribution companies in Chile and Peru acquired in 1999.
Revenues increased $178 million from $440 million to $618 million in 1999 as compared to 1998. The increase was due to an increase of $34 million at Resources due to higher income from financial investments and new leveraged lease investments, a $126 million increase in revenues at Energy Technologies due to the addition of revenues from acquisitions of various HVAC companies in 1999 and a $17 million increase in revenues at Global primarily due to improvement in revenues from domestic generation assets as well as the addition of revenues from the distribution companies in Chile and Peru acquired in 1999.
Enermy Holdings - Expenses
OperatingExpenses
Operating expenses increased $79 million from $424 million to $503 million in 2000 as compared to 1999 primarily due to the addition of $123 million in operating expenses from the HVAC and mechanical service contracting companies acquired by Energy Technologies in 2000 and 1999. A pre-tax charge of approximately $55 million, to reduce the carrying value of certain assets was recorded in 1999 and is discussed below.
Operating expenses increased $173 million from $251 million to $424 million in 1999 as compared to 1998. The increase was primarily due to higher operating expenses from the entities acquired by Energy Technologies in 1999. In addition, Global recognized a pre-tax charge of approximately $44 million to reduce the carrying value of certain assets and EGDC recorded a charge of $11 million to reflect a write-down to net realizable value of a property in the portfolio.
Interest Expense and PreferredDividends
Interest expense increased $42 million from $95 million to $137 million in 2000 as compared to 1999. Interest expense associated with recourse financing activities at Energy Holdings increased $51 million primarily due to additional borrowings incurred as a result of equity investments in distribution and generation facilities and the repayment of non-recourse debt. Interest expense associated with non-recourse debt financing decreased by $9 million due to the repayment of approximately $157 million of non-recourse debt.
Interest Expense increased by $5 million from $90 million to $95 million for the year ended December 31, 1999 as compared to 1998 primarily due to an increase of $8 million related to the debt financing associated with Global's acquisition of an interest in distribution facilities in Chile and Peru in June 1999. Interest Expense associated with recourse financing activities at Energy Holdings decreased $3 million for the year ended December 31, 1999 as compared to 1998 primarily due to lower average debt outstanding. Preferred Stock dividends increased $8 million from $17 million to $25 million due to the issuance of $509 million of cumulative preferred stock to PSEG in January, June and July of 1998.
40 Income Taxes
Income Taxes decreased $24 million from $69 million to $45 million in 2000 as compared to 1999. The year ended December 31, 2000 reflects a lower effective tax rate due to a decrease in the foreign tax liability from foreign investments at Global. Income from such investments is assumed to be permanently reinvested outside of the United States. During 1999, there was an increase in state income taxes at Resources totaling $11 million due to the early termination of a leveraged lease.
Income Taxes increased $39 million from $30 million to $69 million in 1999 as compared to 1998. The increase was primarily due to higher pre-tax income for the year ended December 31, 1999. In addition, state income taxes increased by approximately $11 million due to the payment of state taxes associated with the early termination of a leveraged lease interest.
Energy Holdings - Other Income (Loss)
Other income (loss) decreased by $74 million from $77 million to $3 million in 2000 as compared to 1999 primarily from Global's sale in 1999 of its interest in a co-generation facility, which yielded a pre-tax gain of $69 million.
Other Income increased $79 million from a loss of $2 million to income of $77 million in 1999 as compared to 1998. The 1999 increase was primarily due to a pre-tax gain of $69 million on the sale of Global's interest in a co generation facility.
PSEG - Preferred Securities Dividend Requirements of Subsidiaries
There was no change in Preferred Securities Dividend Requirements in 2000 as compared to 1999. Preferred Securities Dividend Requirements increased $14 million or 18% in 1999 as compared to 1998 due to the issuance of trust preferred securities in aggregate principal amount of $525 million in January, June and July 1998.
LIQUIDITY AND CAPITAL RESOURCES
PSEG is a 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 three direct operating subsidiaries in 2000, PSE&G, Power and Energy Holdings.
As of December 31, 2000, PSEG's capital structure consisted of 38.1% common equity, 50.4% long-term debt and 11.5% preferred securities. As of December 31, 1999, PSEG's capital structure consisted of 40.9% common equity, 46.8% long-term debt and 12.3% preferred stock and other preferred securities.
PSEG's Board of Directors authorized the repurchase of up to an aggregate of 30 million shares of Common Stock in the open market. At December 31, 2000, PSEG had repurchased approximately 24.2 million shares of Common Stock, at a cost of approximately $905 million since 1998. The repurchased shares have been primarily held as treasury stock with the balance used for other corporate purposes. In December 2000, PSEG settled a Forward Purchase Agreement with a third party which had purchased approximately 6.4 million shares at a cost of approximately $226 million, which is included in the 24.2 million shares. PSEG does not currently anticipate purchasing additional shares under this authorization.
Dividend payments on Common Stock were $2.16 per share and totaled approximately $464 million and $474 million for the years ended December 31, 2000 and 1999, respectively. PSEG has not increased its dividend rate in nine years in order to retain additional capital for reinvestment and to reduce its payout ratio as earnings grow.
Although PSEG presently believes it will have adequate earnings and cash flow in the future from its subsidiaries to maintain Common Stock dividends at the current level, earnings and cash flows required to support the dividend will become more volatile as PSEG's business changes from one that is principally regulated to one that
41 is principally competitive. Future dividends declared will necessarily be dependent upon PSEG's future earnings, cash flows, financial requirements, alternate investment opportunities and other factors.
PSEG and PSE&G have each issued Deferrable Interest Subordinated Debentures in connection with the issuance of their respective tax deductible preferred securities. If payments on those Deferrable Interest Subordinated Debentures are deferred, or PSEG or PSE&G defaults on the applicable indenture related thereto or its guarantee thereof, neither PSEG nor PSE&G may pay any dividends on its common or preferred stock until such default is cured. Currently, there has been no deferral or default.
PSE&G
As of December 31, 2000, PSE&G's capital structure consisted of 51.3% common equity, 40.9% long-term debt and 7.8% preferred stock and other preferred securities. As of December 31, 1999, PSE&G's capital structure consisted of 49.8% common equity, 41.1% long-term debt and 9.1% preferred stock and other preferred securities.
Cash generated from PSE&G's transmission and distribution business is expected to provide the majority of the funds for PSE&G's business needs. Also as a result of the delay in securitization, pending resolution of the appeals of the Final Order and the Finance Order, PSEG and PSE&G utilized various medium-term financings to refinance existing debt and maturities.
On January 31, 2001, $2.525 billion of transition bonds were issued by PSE&G Transition Funding LLC, a bankruptcy-remote, wholly-owned subsidiary of PSE&G, in eight classes with maturities ranging from 1 year to 15 years. PSE&G also received payment from Power on its $2.786 billion promissory note used to finance the transfer of its generation business to Power. The proceeds from these transactions were used to pay for certain debt issuance and related costs for securitization, retire a portion of PSE&G's outstanding short-term debt, reduce PSE&G common equity, loan funds to PSEG and make various short term investments. These funds will also be used for the further debt and/or equity reduction of PSE&G in 2001 including payment of maturing and certain redeemable securities.
Since 1986, PSE&G has made regular cash payments to PSEG in the form of dividends on outstanding shares of PSE&G's common stock. PSE&G paid common stock dividends of $638 million and $629 million to PSEG for the years ended December 31, 2000 and 1999, respectively. These amounts were used to fund PSEG's Common Stock dividends and to support a portion of PSEG's stock repurchase program.
Power
In 2000 Power financed its acquisition of the generation business from PSE&G through a $2.786 billion promissory note. On January 31, 2001, through equity infusions and loans from PSEG, Power repaid this note to PSE&G. Power expects to replace its interim financing from PSEG with its own debt financing in the first half of 2001. Power's capital needs will be funded with cash generated from operations and may be supplemented with external financings, equity infusions from PSEG and other project financing alternatives as dictated by Power's growth strategy.
Energy Holdings
It is intended that Global and Resources will provide the earnings and cash flow for Energy Holdings' long-term growth. Resources' investments are designed to produce immediate cash flow and earnings that enable Global and Energy Technologies to focus on longer investment horizons. During the next five years, Energy Holdings will need significant capital to fund its planned growth. In addition to cash generated from operations, Energy Holdings' growth will be funded through external financings and equity infusions from PSEG.
42 Over the next several years, Energy Holdings, certain of its project affiliates and PSEG Capital will be required to refinance maturing debt, incur additional debt and provide equity to fund investment activity. Any inability to obtain required additional external capital or to extend or replace maturing debt and/or existing agreements at current net levels and reasonable interest rates may affect Energy Holdings' financial condition, results of operations and cash flows.
Regulatory Restrictions
As a result of a 1992 BPU proceeding concerning the relationship of PSE&G to PSEG's non-utility businesses (Focused Audit), the BPU approved a plan which, among other things, provided that: (1) PSEG would not permit PSEG's non-utility assets to exceed 20% of PSEG's consolidated assets without prior notice to the BPU (as of December 31, 2000, these assets were in excess of the 20% limit and such notice had been given); (2) the PSE&G Board of Directors would provide an annual certification that the business and financing plans of Energy Holdings will not adversely affect PSE&G; (3) PSEG would (a) limit debt supported by the minimum net worth maintenance agreement between PSEG and PSEG Capital to $650 million and (b) make a good-faith effort to eliminate such support by May 2003; and (4) Energy Holdings would pay PSE&G an affiliation fee of up to $2 million a year to be applied by PSE&G to reduce utility rates.
The Final Order addressed the Focused Audit, noting that PSEG's non-regulated assets would likely exceed 20% and that, due to significant changes in the industry and, in particular, PSEG's corporate structure as a result of the Final Order, modifications to or relief from the Focused Audit might be warranted. In March 2000, PSE&G submitted a letter to the BPU notifying the BPU of its intention to make a filing to modify the terms of the Focused Audit within 120 days after the Final Order becomes final and non-appealable. In December 2000, the New Jersey Supreme Court affirmed the appellate decision upholding the Final Order. PSE&G plans to make the filing within the 120 day period. Also, Energy Holdings believes that, if still required, it is capable of eliminating PSEG support of PSEG Capital debt within the time period set forth in the Focused Audit.
Regulatory oversight by the BPU to ensure that there is no harm to utility customers from PSEG's non-utility investments is expected to continue. PSEG and PSE&G believe that these issues will be satisfactorily resolved, although no assurances can be given.
CapitalRequirements
PSE&G
PSE&G has substantial commitments as part of its ongoing construction programs. These programs are continuously reviewed and periodically revised as a result of changes in economic conditions, revised load forecasts, business strategies, site changes, cost escalations under construction contracts, requirements of regulatory authorities and laws, the timing of and amount of electric and gas transmission and/or distribution rate changes and the ability of PSE&G to raise necessary capital.
Construction expenditures were related to improvements in PSE&G's transmission and distribution system, gas system and common facilities. For the years ended December 31, 2000 and 1999 PSE&G had net plant additions of $401 million and $479 million, respectively, excluding Allowance for Funds Used During Construction (AFDC). Projected construction and investment expenditures for PSE&G from 2001 to 2005 range from approximately $415 million to $430 million per year, excluding AFDC and capitalized interest.
Power
Construction expenditures were related to acquisitions by Power and improvements in Power's existing power plants. Power had net plant additions for the year ended December 31, 2000 of $479 million, excluding capitalized interest. Power's growth strategy is designed to increase its generating portfolio 3,000 MW to 8,000 MW over the next five years. Power's projected construction and investment expenditures, excluding AFDC and capitalized interest, are approximately $1.4 billion in 2001, $1.1 billion in 2002, $830 million in 2003 and range from $250
43 million to $300 million per year for 2004 and 2005. Changes in environmental regulations and unexpected impacts of existing regulations could impact both Power's construction and growth strategy as well as the capital expenditure amounts. For further information, including Prevention of Significant Deterioration/New Source Review requirements under the Federal Clean Air Act (CAA), see Note. 10. Commitments and Contingent Liabilities.
Power has installed four new combustion turbines at Burlington Generating Station and two new combustion turbines at Linden Generating Station, adding 168 MW and 164 MW, respectively, of electric generating capacity, at a cost of approximately $151 million. The new combustion turbines were all operational as of July 2000.
In May 2000, Power acquired the Albany Steam Station for $49.9 million. Under the terms of the acquisition agreement, the seller Niagara Mohawk could also receive up to an additional $9 million if Power chooses to pursue redevelopment of the Albany Steam Station.
In September 1999, Power announced that it had signed an agreement to acquire all of Conectiv's interests in the Salem Nuclear Generating Station (Salem) and the Hope Creek Nuclear Generating Station (Hope Creek) and half of Conectiv's interest in the Peach Bottom Atomic Power Station (Peach Bottom), totaling 544 MW for an aggregate purchase price of $15.4 million plus the net book value of nuclear fuel at closing. In December 2000, the sale to Power of the DP&L portion of Conectiv's interests in Salem (7.41%) and Peach Bottom (7.51%, split equally between Power and Exelon) was completed. For further information, including a discussion of the Wholesale Transaction Confirmation letter agreements between Power and Conectiv, see Note 10. Commitments and Contingent Liabilities.
Energy Holdings
Energy Holdings plans to continue the growth of Global and Resources. Energy Holdings will assess the growth prospects and opportunities for Energy Technologies' business before committing substantial amounts of additional capital. In 2000, Energy Holdings' subsidiaries made investments totaling approximately $783 million. These investments included leveraged lease investments by Resources and acquisitions by Global. Investment expenditures for 2001 are expected to be approximately $1 billion, comprised of investments in generation and distribution facilities and leveraged lease transactions. Projected investment expenditures for 2002 to 2005 are approximately $600 million per year, comprised of investments in generation and distribution facilities and projects and leveraged lease transactions. Factors affecting actual expenditures and investments include availability of capital and suitable investment opportunities, market volatility and local economic trends. EXTERNAL FINANCINGS
The changes in the utility industry are attracting increased attention from bond rating agencies which regularly assess business and financial matters including how utility companies are responding to competition. Given the changes in the industry, attention to and scrutiny of PSEG's, PSE&G's, Power's and Energy Holdings' competitive strategies by rating agencies will likely continue. These changes could affect the bond ratings, cost of capital and market prices of their respective securities. In addition, capital structure changes and other actions which might be taken by PSEG and PSE&G in connection with energy industry restructuring is likely to affect the market prices of their respective securities.
PSEG, PSE&G, Power and Energy Holdings are continually analyzing their future capital and financing needs as part of their business strategies.
44 PSEG
At December 31, 2000, PSEG had a committed $150 million revolving credit facility which will expire in December 2002. At December 31, 2000, there was a $150 million loan outstanding under this revolving credit facility. On September 8, 1999, PSEG entered into an uncommitted line of credit with a bank with no stated limit. At December 31, 2000, PSEG had $95 million outstanding under this line of credit.
PSEG has an $850 million commercial paper program to provide funds for general corporate purposes and, until Power's initial financing in completed, provide funds for Power. On December 31, 2000, PSEG had commercial paper of $617 million outstanding.
To provide liquidity for its commercial paper program, PSEG has a $570 million revolving credit facility expiring in March 2001 and a $280 million revolving credit facility expiring in March 2005. These agreements are with a group of banks and provide for borrowings with maturities of up to one year. As of December 31, 2000 there were no borrowings outstanding under these facilities.
On November 21, 2000, PSEG issued $275 million of Floating Rate Notes due May 21, 2002. The interest rate is at three-month LIBOR, plus 0.875%. The proceeds were used for the repayment of $100 million of Extendible Notes, Series A and $175 million of Extendible Notes, Series B, which were due November 22, 2000.
PSEG has registered with the SEC a shelf Registration Statement for an additional $300 million of debt securities.
In 1999, PSEG issued $300 million of Extendible Notes, Series C, due June 15, 2001. These Notes were automatically tendered and remarketed in September 2000. The interest rate through maturity is at the three-month LIBOR plus 0.375%, reset quarterly.
PSE&G
Under its Mortgage, PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements and/or retired Mortgage Bonds provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2:1. At December 31, 2000, PSE&G's Mortgage coverage ratio was 4.3:1. As of December 31, 2000, the Mortgage would permit up to $3.1 billion of new Mortgage Bonds to be issued against previous additions and improvements. Following the release from the lien of PSE&G's Mortgage on January 31, 2001 of the securitization transition property and the generation assets that were transferred to Power, the Mortgage would permit up to $1 billion aggregate principal amount of new Mortgage Bonds to be issued against previous additions and improvements. In addition to the refinancing of existing long-term debt authorized by the BPU in the Final Order, PSE&G will need to obtain BPU authorization to issue any incremental debt financing necessary for its capital program. The BPU has authorized PSE&G to issue up to $1 billion of long-term debt on the basis of previously matured, redeemed or purchased debt through December 31, 2001.
PSE&G expects to apply for and receive necessary BPU authorization for external financings to meet its requirements over the next five years, as needed. While PSE&G expects such authority to be granted, no assurances can be given. Failure to receive such authority on a timely basis could have a material adverse effect on the financial condition, results of operations and net cash flows of PSE&G and PSEG.
As discussed previously, on January 31, 2001, transition bonds in the amount of $2.525 billion were issued by PSE&G Transition Funding LLC, a bankruptcy-remote, wholly-owned subsidiary of PSE&G, in eight classes with maturities ranging from 1 year to 15 years.
On September 6, 2000, PSE&G issued $290 million of 7.19% secured Medium Term Notes, Series A, due September 6, 2002. The proceeds were used for general corporate purposes, including the repayment of short-term debt.
45 On December 7, 2000, PSE&G issued $300 million of 7.4275% Floating Rate Notes, due December 7, 2002. The proceeds were used for general corporate purposes, including the repayment of short-term debt.
PSE&G maintains a $1.5 billion commercial paper program. To provide liquidity for this program, PSE&G has a $450 million revolving credit agreement expiring in June 2001, a $450 million credit facility expiring in June 2002 and a $400 million credit facility and a $200 million credit facility expiring in June 2001. These agreements provide for borrowings with maturities of up to one year. As of December 31, 2000, there were no borrowings outstanding under these facilities.
The BPU has authorized PSE&G to issue and have outstanding at any one time through January 2, 2001, not more than $2.0 billion of short-term obligations, consisting of commercial paper and other unsecured borrowings from banks and other lenders. PSE&G has several uncommitted lines of credit with banks. On December 31, 2000, PSE&G had $1.546 billion of short-term debt outstanding, including $336 million borrowed against its uncommitted bank lines of credit and $1.2 billion of commercial paper.
PSE&G Fuel Corporation had a $125 million commercial paper program to finance a 42.49% share of Peach Bottom nuclear fuel. This commercial paper program was supported by a $125 million revolving credit facility with a group of banks. As a result of the transfer of generation assets from PSE&G to Power, the PSE&G Fuel Corporation commercial paper program has been discontinued. All commercial paper outstanding under this program was paid down on August 17, 2000. The credit facility supporting this program was terminated on September 11, 2000.
Enermy Holdings
On December 31, 2000 Energy Holdings had two separate senior revolving credit facilities, with a syndicate of banks, a $495 million, five-year revolving credit and letter of credit facility and a $165 million, 364-day revolving credit facility. The interest rate on these facilities is based on LIBOR and the average borrowing rate at Energy Holdings current rating level is 1.375% over the one, three or six month LIBOR rate. The revolving credit facilities also permit shorter term base rate borrowings at the prime rate. The five-year facility also permits up to $250 million of letters of credit to be issued. The five-year facility matures on May 12, 2004 and the 364-day facility matures on May 9, 2001. At December 31, 2000 and December 31, 1999, Energy Holdings had $392 million and $351 million, respectively, outstanding under existing revolving credit facilities.
In February 2001, Energy Holdings, in a private placement, issued $400 million of 8.625% Senior Notes due 2008. The net proceeds from the sale were used for repayment of short-term debt. Energy Holdings plans to file a registration statement with the SEC relating to an exchange offer for, or the resale of, these Senior Notes in 2001. Energy Holdings plans to refinance the current portion of existing long-term debt with new issuances.
In June 2000, Global repaid in full at maturity a $71 million loan which was incurred to partially finance its investment in two distribution companies in Argentina.
In May 2000, Global repaid in full a $94.5 million loan which financed a portion of its investment in a distribution company in Brazil. The debt was refinanced with funds from Energy Holdings and a $190 million U.S. Dollar denominated loan at the Brazilian distribution company, of which Global's share is $62 million.
In February 2000, Energy Holdings, in a private placement, issued $300 million of 9.125% Senior Notes due 2004. The net proceeds from the sale were used for repayment of short-term debt outstanding under Energy Holdings' revolving credit facilities. A registration statement filed with the SEC in connection with an exchange offer for these notes was effective on September 5, 2000. The exchange offer was completed on October 18, 2000, with substantially all notes being exchanged.
46 In October 1999, Energy Holdings, in a private placement, issued $400 million of its 10% senior notes due 2009. The net proceeds from the sale were used for the repayment of short-term debt outstanding under Energy Holdings' revolving credit facilities. A registration statement filed with the SEC in connection with an exchange with offer for these notes was effective on June 30, 2000. The exchange offer was completed on August 11, 2000, all notes being exchanged.
In September 1999 and February 2000, Energy Holdings entered into two standby letter of credit agreements with a group of banks in the aggregate principal amount of $340 million to support equity contribution obligations those in of Global with respect to two of its investments. These agreements contain identical financial covenants to and the our revolving credit facilities. The first letter of credit agreement ($150 million) expired in December 2000 as Global second letter of credit agreement will expire in November 2001. The principal amount reduces over time makes its equity investments. MTN PSEG Capital has a $750 million MTN program which provides for the private placement of MTNs. This which program is supported by a minimum net worth maintenance agreement between PSEG Capital and PSEG provides, among other things, that PSEG (1) maintain its ownership, directly or indirectly, of all outstanding of at least common stock of PSEG Capital, (2) cause PSEG Capital to have at all times a positive tangible net worth its debt $100,000 and (3) make sufficient contributions of liquid assets to PSEG Capital in order to permit it to pay the obligations. Energy Holdings believes it is capable of eliminating PSEG support of PSEG Capital debt within time period set forth in the Focused Audit. At December 31, 2000 and December 31, 1999, total debt outstanding under the MTN program was $650 million and $630 million, respectively maturing from 2001 to 2003.
QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
The market risk inherent in PSEG's market risk sensitive instruments and positions is the potential loss arising foreign from adverse changes in commodity prices, pollution credits, equity security prices, interest rates and with its currency exchange rates as discussed below. PSEG's policy is to use derivatives to manage risk consistent business plans and prudent practices. PSEG has a Risk Management Committee comprised of executive officers risk which utilizes an independent risk oversight function to ensure compliance with corporate policies and prudent management practices.
PSEG is exposed to credit losses in the event of non-performance or non-payment by counterparties. PSEG also and has a credit management process which is used to assess, monitor and mitigate counterparty exposure for PSEG a material its subsidiaries. In the event of non-performance or non-payment by a major counterparty, there may be For adverse impact on PSEG's and its subsidiaries' financial condition, results of operations or net cash flows. foreign discussion of interest rates and Energy Holdings' commodity-related instruments, equity securities and currency risks, see Note 8. Financial Instruments and Risk Management of Notes.
Commodity-Related Instruments
The availability and price of energy commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand and state and Federal regulatory policies. To reduce price risk caused by market fluctuations, Power enters into derivative contracts, including forwards, futures, swaps and options with approved counterparties, to hedge its anticipated demand. These contracts, in conjunction with owned electric generating capacity and physical gas supply contracts, are designed to cover estimated electric and gas customer commitments.
PSEG 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 and physical and financial contracts. Value-at for a risk represents the potential gains or losses for instruments or portfolios due to changes in market factors, a specified time period and confidence level. PSEG estimates value-at-risk across its commodity business using model with historical volatilities and correlations.
47 The measured value-at-risk using a variance/co-variance model with a 95% confidence level over a one-week time horizon at December 31, 2000 was approximately $19 million, compared to the December 31, 1999 level of $3 million. PSEG's calculated value-at-risk represents an estimate of the potential change in the value of its portfolio of physical and financial derivative instruments. These estimates, however, are not necessarily indicative of actual results, which may differ due to the fact that actual market rate fluctuations may differ from forecasted fluctuations and due to the fact that the portfolio of hedging instruments may change over the holding period.
Given the absence of a PJM price cap in situations involving emergency purchases and the potential for plant outages, extreme price movements can occur and could have a material impact on PSEG's, PSE&G's and Power's financial condition, results of operations and net cash flows.
FOREIGN OPERATIONS
As of December 31, 2000, Global and Resources had approximately $1.8 billion and $1.2 billion, respectively, of international assets. As of December 31, 2000, foreign assets represented 14% of PSEG's consolidated assets and the revenues related to those foreign assets contributed 3% to consolidated revenues for the year ended December 31, 2000. For discussion of foreign currency risk, see Note 8. Financial Instruments and Risk Management.
ACCOUNTING ISSUES
For a discussion of the impact of new accounting pronouncements including SFAS 133, "Accounting for Derivative Instruments and Hedging Activities", SFAS 137, "Accounting for Derivative Instruments and Hedging Activities - Deferral of the Effective Date of FASB Statement No. 133" and SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities", see Note 18. Accounting Matters of Notes.
PSE&G
The information required by this item is incorporated herein by reference to the following portions of PSEG's Management's Discussion and Analysis of Financial Condition and Results of Operations, insofar as they relate to PSE&G and its subsidiaries: Overview of 2000 and Future Outlook; Results of Operations; Liquidity and Capital Resources; External Financings; and Accounting Issues.
FORWARD LOOKING STATEMENTS
Except for the historical information contained herein, certain of the matters discussed in this report constitute "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are subject to risks and uncertainties which could cause actual results to differ materially from those anticipated. Such statements are based on management's beliefs as well as assumptions made by and information currently available to management. When used herein, the words "will", "anticipate", "intend", "estimate", "believe", "expect", "plan", "hypothetical", "potential", variations of such words and similar expressions are intended to identify forward-looking statements. PSEG and its subsidiaries undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The following review of factors should not be construed as exhaustive or as any admission regarding the adequacy of disclosures made by PSEG and its subsidiaries prior to the effective date of the Private Securities Litigation Reform Act of 1995.
48 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 of energy forward-looking statements include, among others, the following: deregulation and the unbundling services; supplies and services and the establishment of a competitive energy marketplace for products and managing rapidly changing wholesale energy trading operations in conjunction with electricity and gas production, transmission and distribution systems; managing foreign investments and electric generation and distribution an operations in locations outside of the traditional utility service territory; political and foreign currency risks; increasingly competitive energy marketplace; sales retention and growth potential in a mature PSE&G service territory; ability to complete development or acquisition of current and future investments; partner and counterparty risk; exposure to market price fluctuations and volatility of fuel and power supply, power output, marketable securities, among others; ability to obtain adequate and timely rate relief, cost recovery, and other necessary regulatory approvals; Federal, state and foreign regulatory actions; regulatory oversight with respect to utility and non-utility affiliate relations and activities; operating restrictions, increased cost and construction delays attributable to environmental regulations; nuclear decommissioning and the availability of storage facilities for spent nuclear fuel; licensing and regulatory approval necessary for nuclear and other operating stations; the ability to economically and safely operate nuclear facilities in accordance with regulatory requirements; environmental concerns; and market risk and debt and equity market concerns associated with these issues.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
Information relating to quantitative and qualitative disclosures about market risk is set forth under the caption of "Qualitative and Quantitative Disclosures About Market Risk" in Item 7. Management's Discussion and Analysis Financial Condition and Results of Operations and "Financial Instruments" in Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements. is Such information is incorporated herein by reference. For PSE&G, the information required by this item incorporated herein by reference insofar as it relates to PSE&G and its subsidiaries
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
49 [THIS PAGE INTENTIONALLY LEFT BLANK] PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CONSOLIDATED STATEMENTS OF INCOME (Millions of Dollars, except for Per Share Data)
For The Years Ended December 31, 2000 1999 1998 OPERATING REVENUES Electric Revenues * Bundled $ $ 2,480 $ 4,009 Generation 2,280 1,005 Transmission and Distribution 1,634 638 Total Electric Revenues 3,914 4,123 4,009 Gas Distribution 2,140 1,717 1,559 Other 794 618 442 Total Operating Revenues 6,848 6,458 6,010 OPERATING EXPENSES Electric Energy Costs 960 922 960 Gas Costs 1,471 1,107 1,034 Operation and Maintenance 1,984 1,903 1,547 Depreciation and Amortization 362 536 660 Taxes Other Than Income Taxes 182 196 205 Total Operating Expenses 4,959 4,664 4,406 OPERATING INCOME 1,889 1,794 1,604 Other Income and Deductions 33 76 18 Interest Expense-net (574) (490) (470) Preferred Securities Dividend Requirements (94) (94) (80) INCOME BEFORE INCOME TAXES AND EXTRAORDINARY ITEM 1,254 1,286 1,072 Income Taxes (490) (563) (428) INCOME BEFORE EXTRAORDINARY ITEM 764 723 644 Extraordinary Item (Net of Tax of $345) (804) NET INCOME (LOSS) $ 764 $ (81) $ 644
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (000's) 215,121 219,814 230,974
EARNINGS (LOSSES) PER SHARE (BASIC AND DILUTED): Income Before Extraordinary Item $ 3.55 $ 3.29 $ 2.79 Extraordinary Item (Net of Tax) _ (3.66) Net Income (Loss) $ 3.55 $ (0.37) $ 2.79
DIVIDENDS PAID PER SHARE OF COMMON STOCK $ 2.16 $ 2.16 $ 2.16
* Note: Bundled revenues were recorded based on the bundled rates in effect through July 31, 1999. Commencing with the unbundling of rates on August 1, 1999, revenues are disaggregated between Generation Revenue and Transmission and Distribution Revenue.
See Notes to Consolidated Financial Statements.
50 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CONSOLIDATED BALANCE SHEETS ASSETS (Millions of Dollars)
December 31, 2000 1999 CURRENT ASSETS Cash and Cash Equivalents $ 102 $ 259 Accounts Receivable: Customer Accounts Receivable 778 646 Other Accounts Receivable 431 371 Allowance for Doubtful Accounts (44) (40) Unbilled Revenues 357 241 Fuel 431 311 Materials and Supplies, net of valuation reserves - 2000 and 1999, $11 155 130 Prepayments 31 39 Other 168 86 Total Current Assets 2,409 2,043
PROPERTY, PLANT AND EQUIPMENT Electric - Generation 2,699 2,355 Electric - Transmission and Distribution 5,302 5,113 Gas - Distribution 3,177 3,019 Other 790 522 Total 11,968 11,009 Accumulated depreciation and amortization (4,266) (3,943) Net Property, Plant and Equipment 7,702 7,066
NONCURRENT ASSETS Regulatory Assets 4,995 5,053 Long-Term Investments, net of accumulated amortization and net of valuation allowances - 2000, $72; 1999, $65 4,545 3,848 Nuclear Decommissioning Fund 716 631 Other Special Funds 122 148 Other, net of accumulated amortization - 2000, $19; 1999, $12 307 226 Total Noncurrent Assets 10,685 9,906
TOTAL $ 20,796 $ 19,015
See Notes to Consolidated Financial Statements.
51 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CONSOLIDATED- BALANCE SHEETS LIABILITIES AND CAPITALIZATION (Millions of Dollars)
December 31, 2000 1999 CURRENT LIABILITIES Long-Term Debt Due Within One Year $ 667 $ 1,073 Commercial Paper and Loans 2,885 1,972 Accounts Payable 1,001 738 429 Other 394 Total Current Liabilities 4,982 4,177
NONCURRENT LIABILITIES Deferred Income Taxes and ITC 3,107 2,928 Regulatory Liabilities 470 604 Nuclear Decommissioning 716 631 OPEB Costs 448 390 Other 572 506 Total Noncurrent Liabilities 5,313 5,059
COMMITMENTS AND CONTINGENT LIABILITIES
CAPITALIZATION: LONG-TERM DEBT 5,297 4,575
SUBSIDIARIES' PREFERRED SECURITIES: Preferred Stock Without Mandatory Redemption 95 95 Preferred Stock With Mandatory Redemption 75 75 Guaranteed Preferred Beneficial Interest in Subordinated Debentures 1,038 1,038 Total Subsidiaries' Preferred Securities 1,208 1,208
COMMON STOCKHOLDERS' EQUITY: Common Stock, issued; 231,957,608 shares 3,604 3,604 Treasury Stock, at cost; 2000 - 23,986,290 shares, 1999 - 15,540,390 shares, (895) (597) Retained Earnings 1,493 1,193 Accumulated Other Comprehensive Income (Loss) (206) (204) Total Common Stockholders' Equity 3,996 3,996 Total Capitalization 10,501 9,779 TOTAL $ 20,796 $ 19,015
See Notes to Consolidated Financial Statements.
52 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions of Dollars)
For The Years Ended December 31, 2000 1999 1998 CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ 764 $ (81) $ 644 Adjustments to reconcile net income (loss) to net cash flows from operating activities: Extraordinary Loss - net of tax 804 Depreciation and Amortization 362 536 660 Amortization of Nuclear Fuel 130 92 93 Recovery of Electric Energy and Gas Costs - net 16 61 132 Excess Unsecuritized Stranded Costs 115 Provision for Deferred Income Taxes and ITC - net (11) (215) (55) Investment Distributions 56 134 73 Equity Income from Partnerships (28) (53) (39) Gains on Investments (39) (63) (40) Leasing Activities 74 6 (20) Net Changes in certain current assets and liabilities: Accounts Receivable and Unbilled Revenues (299) (236) 113 Inventory - Fuel and Materials and Supplies (145) 9 (46) Prepayments 8 8 (12) Accounts Payable 260 57 (34) Other Current Assets and Liabilities (47) 59 (63) Other (80) 114 93 Net Cash Provided By Operating Activities 1,136 1,232 1,499 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment, excluding Capitalized Interest and AFDC (959) (582) (531) Net Change in Long-Term Investments (603) (980) (92) Other (49) (70) (125) Net Cash Used In Investing Activities (1,611) (1,632) (748) CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Debt 913 916 (431) Issuance of Long-Term Debt 1,200 1,143 525 Redemption/Purchase of Long-Term Debt (1,033) (676) (557) Issuance of Preferred Securities 525 Purchase of Treasury Stock (298) (400) (207) Cash Dividends Paid on Common Stock (464) (474) (499) Other 11 (51) Net Cash Provided By (Used In) Financing Activities 318 520 (695) Net Change In Cash And Cash Equivalents (157) 120 56 Cash And Cash Equivalents At Beginning Of Period 259 139 83 Cash And Cash Equivalents At End Of Period $ 102 $ 259 $ 139
Income Taxes Paid $ 485 $ 534 $ 426 Interest Paid $ 550 $ 494 $ 469
See Notes to Consolidated Financial Statements.
53 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY (Millions) Accumulated Other Common Treasury Retained Comprehensive Stock Stock Earnings Income (Loss) Total Shs. Amount Shs. Amount Balance as of January 1, 1998 232 $3,603 $ 1,623 $ (15) $ 5,211 Net Income 644 - 644 Other Comprehensive Income (Loss), net of tax: Pension Plan Additional Minimum Liability, net of tax of $(2) (3) (3) Currency Translation Adjustment, net of tax of $(3) (28) (28) Other Comprehensive Income (Loss) - (31) Comprehensive Income - 613 Cash Dividends on Common Stock (499) - (499) - (207) Purchase of Treasury Stock - (5) (207) Restricted Stock Award (5) - (5) Preferred Securities Issuance Expenses (15) - (15) Balance as of December 31, 1998 232 3,603 (5) (207) 1,748 (46) 5,098 Net Income (Loss) (81) - (81) Other Comprehensive Income (Loss), net of tax: (158) Currency Translation Adjustment, net of tax of $(17) (158) (158) Other Comprehensive Income (Loss) - Comprehensive Income (Loss) - (239) Cash Dividends on Common Stock (474) - (474) Purchase of Treasury Stock (11) (400) - (400) Other 1 - 10 - 11 1,193 Balance as of December 31, 1999 232 3,604 (16) (597) (204) 3,996 Net Income (Loss) 764 - 764 Other Comprehensive Income (Loss), net of tax: Currency Translation Adjustment, net of tax of $(0) (2) (2) Other Comprehensive Income (Loss) - (2) Comprehensive Income (Loss) - 762 - (464) Cash Dividends on Common Stock (464) Purchase of Treasury Stock - - (8) (298) - (298) Balance as of December 31, 2000 232 $3,604 (24) $ (895) $ 1,493 $ (206) $ 3,996
See Notes to Consolidated Financial Statements.
54 [THIS PAGE INTENTIONALLY LEFT BLANK] PUBLIC SERVICE ELECTRIC AND GAS COMPANY CONSOLIDATED STATEMENTS OF INCOME (Millions of Dollars)
For The Years Ended December 31, 2000 1999 1998 OPERATING REVENUES Electric Revenues * $ $ 2,480 $ 4,009 Bundled 1,005 1,243 Generation 638 and Distribution 2,505 Transmission 4,123 4,009 Revenues 3,748 Total Electric 1,717 1,559 2,140 Gas Distribution 5,840 5,568 Total Operating Revenues 5,888 EXPENSES OPERATING 908 945 Costs 1,520 Electric Energy 1,038 970 1,429 Gas Costs 1,573 1,385 1,214 Operation and Maintenance 529 649 291 Depreciation and Amortization 194 208 Than Income Taxes 166 Taxes Other 4,242 4,157 Operating Expenses 4,620 Total 1,598 1,411 1,268 OPERATING INCOME (2) 17 26 Other Income and Deductions (387) (378) (254) Interest Expense-net (46) (44) Preferred Securities Dividend Requirements (46) INCOME TAXES AND INCOME BEFORE 1,163 1,006 994 EXTRAORDINARY ITEM (510) (404) (407) Income Taxes 653 602 ITEM 587 INCOME BEFORE EXTRAORDINARY (804) of Tax of $345) Extraordinary Item (Net (151) 602 INCOME (LOSS) 587 NET (9) (9) Preferred Stock Dividend Requirement (9) EARNINGS (LOSS) AVAILABLE TO $ (160) $ 593 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED $ 578
* Note: Bundled revenues were recorded based on the bundled rates in effect through July 31, 1999. Commencing with the unbundling of rates on August 1, 1999, revenues are disaggregated between Generation Revenue and Transmission and Distribution Revenue.
See Notes to Consolidated Financial Statements.
55 PUBLIC SERVICE ELECTRIC AND GAS COMPANY CONSOLIDATED BALANCE SHEETS ASSETS (Millions of Dollars)
December 31, 2000 1999 CURRENT ASSETS Cash and Cash Equivalents $ 39 $ 173 Accounts Receivable: Customer Accounts Receivable 614 529 Other Accounts Receivable 71 313 Allowance for Doubtful Accounts (39) (35) Unbilled Revenues 357 241 Fuel 372 308 Materials and Supplies, net of valuation reserves - 2000, $0; 1999, $11 48 130 Prepayments 5 34 Other 24 50 Total Current Assets 1,491 1,743
PROPERTY, PLANT AND EQUIPMENT Electric - Generation 2,284 Electric - Transmission and Distribution 5,302 5,113 Gas - Distribution 3,177 3,019 Other 420 445 Total 8,899 10,861 Accumulated depreciation and amortization (3,139) (3,911) Net Property, Plant and Equipment 5,760 6,950
NONCURRENT ASSETS Regulatory Assets 4,995 5,053 Notes Receivable - Affiliated Companies 2,786 Long-Term Investments 109 99 Nuclear Decommissioning Fund 631 Other Special Funds 70 148 Other 56 100 Total Noncurrent Assets 8,016 6,031
TOTAL $ 15,267 $ 14,724
See Notes to Consolidated Financial Statements.
56 PUBLIC SERVICE ELECTRIC AND GAS COMPANY CONSOLIDATED BALANCE SHEETS LIABILITIES AND CAPITALIZATION (Millions of Dollars)
December 31, 2000 1999 CURRENT LIABILITIES Long-Term Debt Due Within One Year $ 100 $ 623 1,475 Commercial Paper and Loans 1,543 676 Accounts Payable 748 253 281 Other 3,055 Total Current Liabilities 2,644
NONCURRENT LIABILITIES 2,032 Deferred Income Taxes and ITC 2,701 604 Regulatory Liabilities 470 631 Nuclear Decommissioning 390 OPEB Costs 441 479 Other 223 4,136 Total Noncurrent Liabilities 3,835
COMMITMENTS AND CONTINGENT LIABILITIES
CAPITALIZATION: LONG-TERM DEBT 3,590 3,099
PREFERRED SECURITIES: Preferred Stock Without Mandatory Redemption 95 95 75 75 Preferred Stock With Mandatory Redemption Subsidiaries' Preferred Securities: Guaranteed Preferred Beneficial Interest in Subordinated Debentures 513 513 683 Total Preferred Securities 683
COMMON STOCKHOLDER'S EQUITY: 2,563 2,563 Common Stock, issued; 132,450,344 shares 594 Contributed Capital 594 Basis Adjustment 986 597 Retained Earnings 375 Accumulated Other Comprehensive Income (Loss) (3) (3) 3,751 Total Common Stockholder's Equity 4,515 Total Capitalization 8,788 7,533 $ 14,724 TOTAL $ 15,267
See Notes to Consolidated Financial Statements.
57 PUBLIC SERVICE ELECTRIC AND GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (Millions of Dollars)
For The Years Ended December 31, 2000 1999 1998 CASH FLOWS FROM OPERATING ACTIVITIES Net income (loss) $ 587 $(151) $ 602 Adjustments to reconcile net income (loss) to net cash flows from operating activities: Extraordinary Loss - net of tax 804 Depreciation and Amortization 291 529 649 Amortization of Nuclear Fuel 36 92 93 Recovery of Electric Energy and Gas Costs - net 16 61 132 Excess Unsecuritized Stranded Costs 115 Provision for Deferred Income Taxes and ITC - net (12) (181) (41) Net Changes in certain current assets and liabilities: Accounts Receivable and Unbilled Revenues (298) (198) 77 Inventory - Fuel and Materials and Supplies (172) 10 (44) Prepayments 27 4 (8) Accounts Payable 294 68 15 Other Current Assets and Liabilities 39 25 26 Other (30) 87 80 Net Cash Provided By Operating Activities 893 1,150 1,581 CASH FLOWS FROM INVESTING ACTIVITIES Additions to Property, Plant and Equipment, excluding Capitalized Interest and AFDC (401) (479) (535) Contribution to Decommissioning Funds and Other Special Funds (70) (115) Other (15) (34) (35) Net Cash Used In Investing Activities (416) (583) (685) CASH FLOWS FROM FINANCING ACTIVITIES Net Change in Short-Term Debt 68 625 (256) Issuance of Long-Term Debt 590 250 Redemption/Purchase of Long-Term Debt (622) (423) (350) Cash Dividends Paid on Common Stock (638) (629) (503) Other (9) (9) (12) Net Cash Used In Financing Activities (611) (436) (871) Net Change In Cash And Cash Equivalents (134) 131 25 Cash And Cash Equivalents At Beginning Of Period 173 42 17 Cash And Cash Equivalents At End Of Period $ 39 $ 173 $ 42
Income Taxes Paid $ 593 $ 537 $ 410 Interest Paid $ 406 $ 409 $ 386
See Notes to Consolidated Financial Statements.
58 PUBLIC SERVICE ELECTRIC AND GAS COMPANY CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY (Millions of Dollars) Accumulated Contributed Other Common Capital from Retained Comprehensive Basis Stock PSEG Earnings Loss Adjustment Total
Balance as of January 1, 1998 $2,563 $ 594 $ 1,296 $ $ $ 4,453 602 Net Income - - 602 Other Comprehensive Income (Loss), net of tax: Pension Adjustment, net of tax of $(2) (3) (3) Other Comprehensive Income (Loss) (3) 599 Comprehensive Income (503) Cash Dividends on Common Stock (503) Cash Dividends on Preferred Stock (9) (9) 4,540 Balance as of December 31, 1998 2,563 594 1,386 (3) (151) Net Income (Loss) (151) Other Comprehensive Income (Loss) (151) Comprehensive Income (Loss) (629) Cash Dividends on Common Stock (629) Cash Dividends on Preferred Stock (9) (9) 3,751 Balance as of December 31, 1999 2,563 594 597 (3) 587 Net Income (Loss) 587 Other Comprehensive Income (Loss) 587 Comprehensive Income (Loss) (800) Cash Dividends on Common Stock (800) Cash Dividends on Preferred Stock (9) (9) 986 Basis Adjustment - 986 4,515 Balance as of December 31, 2000 $2,563 $ 594 $ 375 $ (3) $ 986 $
See Notes to Consolidated Financial Statements.
59 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies
Organization
PSEG has four principal direct wholly-owned subsidiaries: Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power), PSEG Energy Holdings Inc. (Energy Holdings) and PSEG Services Corporation (Services).
PSE&G is an operating public utility providing electric and gas service in certain areas within the State of New Jersey. Following the transfer of its generation-related assets to Power in August 2000, PSE&G continues to own and operate its transmission and distribution business.
Power and its subsidiaries were formed in 1999 to acquire, own and operate the electric generation-related assets of PSE&G pursuant to the Final Decision and Order (Final Order) issued by the New Jersey Board of Public Utilities (BPU) under the New Jersey Energy Master Plan Proceedings. Through its subsidiaries, Power provides the energy and capacity to PSE&G under certain contracts and markets electricity, natural gas, capacity and ancillary services throughout the Eastern United States. Power has three principal direct wholly-owned subsidiaries: PSEG Fossil LLC (Fossil), PSEG Nuclear LLC (Nuclear) and PSEG Energy Resources & Trade LLC (ER&T). Power also has a finance company subsidiary, PSEG Power Capital Investment Co. (Power Capital), which provides certain financing for Power's other subsidiaries.
Energy Holdings is the parent of three energy-related lines of business through its wholly-owned subsidiaries: PSEG Global Inc. (Global), PSEG Resources Inc. (Resources) and PSEG Energy Technologies Inc. (Energy Technologies). Energy Holdings also has a finance subsidiary, PSEG Capital Corporation (PSEG Capital) and is also the parent of Enterprise Group Development Corporation (EGDC).
Services provides management and administrative services to PSEG and its subsidiaries.
Basis of Presentation
Effective August 1, 2000, PSE&G's presentation of Electric Revenues and Electric Energy Costs in the Consolidated Statements of Income has changed due to PSE&G's transfer of its electric generating facilities to Power and wholesale power contracts to ER&T. Effective with the transfer, PSE&G pays a fixed price for energy and capacity provided by Power under a contract to meet PSE&G's basic generation service (BGS) obligation through July 3 1, 2002 and charges such costs to its BGS customers. As a result, PSE&G transferred its market risk related to its estimated electric commitments to Power.
Effective August 1, 1999, the presentation of revenues in the Consolidated Statements of Income had changed due to the deregulation of the electric generation business by the BPU in its Energy Master Plan Proceedings. Effective with that date, electric rates charged to customers have been unbundled and the generation, transmission, distribution and other components of the total rate have become separate charges. Revenues earned prior to August 1, 1999 continue to be presented as Bundled Electric Revenues on the Consolidated Statements of Income as they were earned based upon bundled electric rates effective for that period.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Summary of Significant Accounting Policies
Regulation
PSE&G maintains its accounts for its regulated operations in accordance with their prescribed Uniform Systems of Accounts. The application of Generally Accepted Accounting Principles (GAAP) by PSE&G differs in certain with respects from applications by non-regulated businesses. PSE&G prepares its financial statements in accordance of the provisions of Statement of Financial Accounting Standards (SFAS) No. 71 "Accounting for the Effects Certain Types of Regulation" (SFAS 71). In general, SFAS 71 recognizes that accounting for rate-regulated defer the enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to recognition of costs (a regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, the extent PSE&G has deferred certain costs and recoveries, which will be amortized over various future periods. To that collection of such costs or payment of liabilities is no longer probable as a result of changes in regulation and/or income. PSE&G's competitive position, the associated regulatory asset or liability is charged or credited to 71. PSE&G's transmission and distribution business continues to meet the requirements for application of SFAS
Consolidation
The consolidated financial statements include the accounts of PSEG and its subsidiaries. PSEG and its and subsidiaries consolidate those entities in which they have a controlling interest. Those entities in which PSEG For its subsidiaries do not have a controlling interest are being accounted for under the equity method of accounting. investments in which significant influence does not exist, the cost method of accounting is applied. All significant intercompany accounts and transactions are eliminated in consolidation.
Reclassifications
Certain reclassifications of prior period data have been made to conform with the current presentation.
Unamortized Loss on ReacquiredDebt and Debt Expense
Bond issuance costs and associated premiums and discounts are generally amortized over the life of the debt issuance. In accordance with Federal Energy Regulatory Commission (FERC) regulations, PSE&G's costs to the reacquire debt are amortized over the remaining original life of the retired debt. When refinancing debt, of unamortized portion of the original debt issuance costs of the debt being retired must be amortized over the life will the replacement debt. Gains and losses on reacquired debt associated with PSE&G's regulated operations For continue to be deferred and amortized to interest expense over the period approved for ratemaking purposes. PSEG's non-utility subsidiaries, gains and losses on reacquired debt are reflected in the statement of operations as incurred.
Plant,Property andEquipment
PSE&G's additions to plant, property and equipment and replacements of units of property that are either retirement units of property record units are capitalized at original cost. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts. At the time units of depreciable property are retired or otherwise disposed, the original cost less net salvage value is charged to accumulated depreciation.
PSEG's non-utility subsidiaries only capitalize costs which increase the capacity or extend the life of an existing asset, represent a newly acquired or constructed asset or represent the replacement of a retired asset.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Depreciation andAmortization
PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU. The depreciation rate stated in a percentage of original cost of depreciable property was 3.52% for 2000, 1999 and 1998. PSE&G has certain regulatory assets and liabilities resulting from the use of a level of depreciation expense in the ratemaking process that differs from the amount that is recorded under GAAP for non-regulated companies.
PSEG's non-utility subsidiaries calculate depreciation under the straight-line method using asset lives determined under GAAP.
Nuclear fuel burnup costs are charged to fuel expense on a units-of-production basis over the estimated life of the fuel. Rates for the recovery of fuel used at all nuclear units include a provision of one mil per kilowatt-hour (kWh) of nuclear generation for spent fuel disposal costs.
Use of Estimates
The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, upon settlement, actual results may differ from estimated amounts.
Allowancefor Funds Used During Construction (AFDC) andInterest CapitalizedDuring Construction (IDC)
AFDC represents the cost of debt and equity funds used to finance the construction of utility facilities. The amount of AFDC capitalized is reported in the Consolidated Statements of Income as a reduction of interest charges for the borrowed funds component and as other income for the equity funds component. The rates used for calculating AFDC in 2000, 1999 and 1998 were 6.45%, 5.29% and 6.06%, respectively.
IDC represents the cost of debt used to finance the construction of non-utility facilities. The amount of IDC capitalized is reported in the Consolidated Statements of Income as a reduction of interest charges. The weighted average rate used for calculating IDC in 2000 was 9.98%.
Revenues and Fuel Costs
Revenues are recorded based on services rendered to customers during each accounting period. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period.
Prior to August 1, 1999, fuel revenue and expense flowed through the Electric Levelized Energy Adjustment Clause (LEAC) mechanism. Variances in fuel revenues and expenses were subject to deferral accounting and had no direct effect on earnings. Under the LEAC and the Levelized Gas Adjustment Clause (LGAC), any LEAC and LGAC underrecoveries or overrecoveries, together with interest (in the case of net overrecoveries), are deferred and included in operations in the period in which they are reflected in rates. Pursuant to a BPU Order, the fuel component of the LEAC rate was frozen for 1997 and 1998 and PSE&G bore all risks associated with fuel prices. Following the transfer of generation-related assets and liabilities in August 2000, Power now bears the full risks and rewards of changes in nuclear and fossil generating fuel costs and replacement power costs.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Materialsand Supplies and Nuclear Fuel
PSE&G's materials and supplies are carried on the books at cost in accordance with rate based regulation. The at lower carrying value of the materials and supplies and nuclear fuel for PSEG's non-utility subsidiaries is valued of cost or market.
Commodity Contracts options PSE&G and Power engage in electricity and natural gas commodity forwards, futures, swaps and Certain purchases and sales with counterparties to manage exposure to electricity and natural gas price risk. electric contracts, in conjunction with owned electric generating capacity, are designed to provide for estimated customer commitments. Similarly, PSE&G uses natural gas futures and swaps to manage the price risk associated with gas supply to customers. for Power also enters into forwards, futures, swaps and options that are not used to manage price risk exposure for commitments to customers. Effective January 1, 1999, PSEG and PSE&G adopted EITF 98-10, "Accounting that Contracts Involved in Energy Trading and Risk Management Activities" (EITF 98-10). EITF 98-10 requires included in energy trading contracts not utilized to hedge price risk be marked to market with gains and losses current earnings.
FinancialInstruments
Gains and losses on hedges of existing assets or liabilities are included in the carrying amounts of those assets Gains and liabilities and are ultimately recognized in income when the related asset or liability is realized or settled. and and losses related to qualifying hedges of firm commitments or anticipated transactions are also deferred recognized in income when the hedged transaction occurs.
Equity Investments
Resources carries its investments in equity securities at their approximate fair market values as of the reporting date.
Foreign Currency Translation/Transactions
The assets and liabilities of foreign operations are translated into U.S. dollars at current exchange rates and revenues and expenses are translated at average exchange rates for the year. Resulting translation adjustments are reflected as a separate component of stockholders' equity.
Transaction gains and losses that arise from exchange rate fluctuations on normal operating transactions denominated in a currency other than the functional currency are included in the results of operations as incurred.
Income Taxes
to PSEG and its subsidiaries file a consolidated Federal income tax return and income taxes are allocated PSEG's subsidiaries based on the taxable income or loss of each subsidiary. Investment tax credits were deferred in For prior years and are being amortized over the useful lives of the related property, including nuclear fuel. discussion of state energy tax reform and its impact on New Jersey Gross Receipts and Franchise Taxes (NJGRT), see Note 12. Income Taxes.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
CapitalLeases as Lessee
The Consolidated Balance Sheets include assets and related obligations applicable to capital leases under which the entity is a lessee. The total amortization of the leased assets and interest on the lease obligations equals the net minimum lease payments included in rent expense for capital leases. Capital leases of PSE&G relate primarily to its corporate headquarters.
Impairment of Long-Lived Assets
PSEG and its unregulated subsidiaries review for possible impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Upon deregulation, PSE&G evaluated the recoverability of its assets and recorded an extraordinary, non-cash charge to earnings. For the impact of the application of SFAS 121, see Note 2. Regulatory Issues and Accounting Impacts of Deregulation.
Note 2. Regulatory Issues and Accounting Impacts of Deregulation
New Jersey Energy Master Plan Proceedings and Related Orders
Following the enactment of the Energy Competition Act, the BPU rendered a Final Order relating to PSE&G's rate unbundling, stranded costs and restructuring proceedings providing, among other things, for the transfer to an affiliate of all of PSE&G's electric generation facilities, plant and equipment for $2.443 billion and all other related property, including materials, supplies and fuel at the net book value thereof, together with associated rights and liabilities.
Also in the Final Order, the BPU concluded that PSE&G should recover up to $2.94 billion (net of tax) of its generation-related stranded costs through securitization of $2.4 billion and an opportunity to recover up to $540 million (net of tax) of its unsecuritized generation-related stranded costs on a net present value basis. The $540 million is subject to recovery through a market transition charge (MTC). Following the issuance of the Final Order, the BPU issued its order approving PSE&G's petition relating to the proposed securitization transaction (Finance Order) which authorized, among other things, the imposition of a non-bypassable transition bond charge (TBC) on PSE&G's customers; the sale of PSE&G's property right in such charge to a bankruptcy-remote financing entity; the issuance and sale of $2.525 billion of transition bonds by such entity as consideration for such property right, including an estimated $125 million of transaction costs; and the application by PSE&G of the transition bond proceeds to retire outstanding debt and/or equity.
The Energy Competition Act and the related BPU proceedings including the Final Order, referred to as the Energy Master Plan Proceedings, opened the New Jersey energy markets to competition by allowing all New Jersey retail electric customers to, among other things, select their electric supplier commencing August 1, 1999 and all New Jersey retail gas customers to select their gas supplier commencing January 1, 2000. In October and November 1999, two appeals of certain provisions of the Final Order and two appeals of certain provisions of the related Finance Order were filed in the Appellate Division of the New Jersey Superior Court (Appellate Division) on behalf of several customers and the New Jersey Office of the Ratepayer Advocate (Ratepayer Advocate). In a decision issued on April 13, 2000, a three-judge Appellate Division panel unanimously affirmed the Final Order and Finance Order. Thereafter, the appellants filed a Petition requesting Certification and a Notice of Appeal with the New Jersey Supreme Court seeking review of the Appellate Division decision. On July 14, 2000, the Court granted Certification with respect to both matters. On December 6, 2000, the New Jersey Supreme Court affirmed the Appellate Division's decision.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
As a result of this appellate review, PSE&G's securitization transaction was delayed until the first quarter of 2001, causing a delay in the implementation of the Securitization Transition Charge (STC) which would have reduced the MTC. In order to recognize the recovery of the allowed unsecuritized stranded costs over the transition period, PSEG has recorded a charge to net income of $88 million, pre-tax, or $52 million, after tax, in the third quarter of 2000 for the cumulative amount of estimated collections in excess of the allowed unsecuritized stranded costs from August 1, 1999 through September 30, 2000. Any such collections in excess of the allowed unsecuritized stranded costs at the end of the transition period will be credited to the Societal Benefits Clause (SBC) as required by the Final Order.
On January 31, 2001, $2.525 billion of transition bonds were issued by PSE&G Transition Funding LLC, a bankruptcy-remote, wholly-owned subsidiary of PSE&G, in eight classes with maturities ranging from 1 year to 15 years. PSE&G also received payment from Power on its $2.786 billion promissory note used to finance the transfer of its generation business to Power. The proceeds from these transactions were used to pay for certain debt issuance and related costs for securitization, retire a portion of PSE&G's outstanding short-term debt, reduce PSE&G common equity, loan funds to PSEG and make various short term investments. These funds will also be used for the further debt and/or equity reduction of PSE&G in 2001 including payment of maturing and certain redeemable securities.
Asset Transfer to Power
PSE&G, pursuant to the Final Order, transferred its electric generating facilities and wholesale power contracts to Power and its subsidiaries on August 21, 2000 in exchange for a promissory note in an amount equal to the purchase price.
The generating assets were transferred at the price specified in the BPU order - $2.443 billion plus $343 million for other generating related assets and liabilities. Because the transfer was between affiliates, PSE&G and Power recorded the sale at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities was recorded as an equity adjustment on PSE&G's and Power's Consolidated Balance Sheets. These amounts are eliminated on PSEG's consolidated financial statements. Power settled the promissory note on January 31, 2001, with funds provided from PSEG equity and loans.
Extraordinary Charge and Other Accounting Impacts of Deregulation
In April 1999, PSE&G determined that SFAS 71 was no longer applicable to the electric generation portion of its business in accordance with the requirements of Emerging Issues Task Force Issue 97-4, "Deregulation of the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71 and No. 101" (EITF 97-4). Accordingly, PSE&G recorded an extraordinary charge to earnings of $804 million (after tax), consisting primarily of the write-down of PSE&G's nuclear and fossil generating stations in accordance with SFAS 121. As a result of this impairment analysis, the net book value of the generating stations was reduced by approximately $5.0 billion (pre-tax) or $3.1 billion (net of tax). This amount was offset by the creation of a $4.057 billion (pre-tax), or $2.4 billion (net of tax) regulatory asset, as provided for in the Final Order and Finance Order.
In addition to the impairment of PSE&G's electric generating stations, the extraordinary charge consisted of various accounting adjustments to reflect the absence of cost of service regulation in the electric generation portion of its business. The adjustments primarily related to materials and supplies, general plant items and liabilities for certain contractual and environmental obligations.
In accordance with the Final Order, PSE&G also reclassified a $569 million excess depreciation reserve related to PSE&G's electric distribution assets from Accumulated Depreciation to a Regulatory Liability. Such amount is
65 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
being amortized in accordance with the terms of the Final Order over the period from January 1, 2000 to July 31, 2003.
Note 3. Regulatory Assets and Liabilities
At December 31, 2000 and December 31, 1999, respectively, PSEG and PSE&G had deferred the following regulatory assets and liabilities on the Consolidated Balance Sheets:
December 2000 1999 (Millions of Dollars) Regulatory Assets Regulatory Asset- Stranded Costs ...... $4,057 $4,057 SFAS 109 Income Taxes ...... 285 286 OPEB Costs ...... 232 237 Regulatory Asset-Societal Benefits Charges (SBC) ...... 135 130 Demand Side M anagement Costs ...... 7 Environmental Costs ...... 13 106 Unamortized Loss on Reacquired Debt and Debt Expense ...... 104 117 Regulatory Asset- NTC ...... 7 O th er ...... 162 113 Total Regulatory Assets ...... $4,995 $5,053
Regulatory Liabilities Regulatory Liability-Excess Depreciation Reserve ...... $444 $569 Regulatory Liability- NTC ...... 20 Overrecovered Gas Costs ...... 26 15 Total Regulatory Liabilities ...... $470 $604
Regulatory Asset - Stranded Costs: This regulatory asset reflects the securitization transition charge which was authorized by the Final Order.
SFAS 109 Income Taxes: This amount represents the regulatory asset related to the recognition of deferred income taxes arising from the implementation of SFAS 109, "Accounting for Income Taxes" (SFAS 109).
OPEB Costs: Includes costs associated with adoption of SFAS 106 which were deferred in accordance with EITF Issue 92-12. Beginning January 1, 1998, PSE&G commenced the amortization of the regulatory asset over 15 years. See Note 13. Pension, Other Postretirement Benefit and Savings Plans for additional information.
Regulatory Asset - SBC: The SBC includes costs related to PSE&G's electric transmission and distribution business as follows: 1) social programs which include the universal service fund; 2) nuclear plant decommissioning; 3) demand side management (DSM) programs; 4) manufactured gas plant remediation; 5) consumer education; and 6) MTC overrecovery.
Demand Side Management Costs: Relates to PSE&G's gas distribution costs and recoveries of DSM/conservation costs (related to BPU-approved programs) are determined by the BPU. As of December 31, 2000, these costs are included in the SBC balance. Environmental Costs: Represents environmental investigation and remediation costs which are probable of recovery in future rates.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Unamortized Loss on Reacquired Debt and Debt Expense: Represents bond issuance costs, premiums, discounts and losses on reacquired long-term debt.
Regulatory Asset/Liability - Non-utility Generation Market Transition Charge (NTC): This clause was established to account for above market costs related to non-utility generation contracts. The charge for the stranded NTC recovery was initially set at $183 million annually. Any Non-utility Generator (NUG) contract costs and/or buyouts are charged to the NTC. Proceeds from the sale of the energy and capacity purchased under these NUG contracts are also be credited to this account.
Other: Includes Decontamination and Decommissioning Costs, Plant and Regulatory Study Costs, Repair Allowance Tax Deficiencies and Interest, Property Abandonments and Oil and Gas Property Write-Down.
Regulatory Liability - Excess Depreciation Reserve: As required by the BPU, PSE&G reduced its depreciation reserve for its electric distribution assets by $569 million and recorded such amount as a regulatory liability to be amortized over the period from January 1, 2000 to July 31, 2003. In 2000, $125 million was amortized. In 2001, 2002 and 2003, $125 million, $135 million and $184 million will be amortized, respectively.
Note 4. Long-Term Investments
Long-Term Investments are primarily those of Energy Holdings.
December 31, 2000 1999 (Millions of Dollars) Leveraged Leases ...... $2,253 $1,759 Partnerships: General Partnerships ...... 46 60 Lim ited Partnerships ...... 479 437 Total ...... 525 497
Corporate Joint Ventures ...... 1,584 1,427 Securities ...... 6 14 Other Investm ents ...... 177 151 Total Long-Term Investm ents ...... $4,545 $3,848
Resources' leveraged leases are reported net of principal and interest on non-recourse loans, unearned income and deferred tax credits. Income and deferred tax credits are recognized at a level rate of return from each lease during the periods in which the net investment is positive.
Partnership investments and corporate joint ventures are those of Resources, Global and EGDC.
Other Investments relate primarily to Energy Technologies' investment in DSM projects and had balances of approximately $56 million and $65 million at December 31, 2000 and 1999, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note 5. Leasing Activities
As Lessor
Resources' net investment in leveraged leases is comprised of the following elements:
December 31, 2000 1999 (Millions of Dollars) Lease rents receivable...... $3,175 $2,643 Estimated residual value ...... 1,046 660 4,221 3,303 Unearned and deferred income ...... (1,962) (1,538) Valuation Allowances ...... (6) (6) Total investm ents in leveraged leases ...... 2,253 1,759 Deferred taxes ...... (1,031) (844) Net investm ents ...... $1,222 $915
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note 6. Schedule of Consolidated Capital Stock and Other Securities
Current Redemption Price Outstanding December 31, December 31, Shares Per Share 2000 1999 (Millions of Dollars)
PSEG Common Stock (no par) (A) Authorized 500,000,000 shares; issued and outstanding at December 31, 1999, 216,417,218 31, 2000, 207,971,318 shares and at December $2,709 $3,007 shares
PSEG Preferred Securities (B) PSEG Quarterly Guaranteed Preferred Beneficial Interest in PSEG's Subordinated Debentures (D) (E) (G) 9,000,000 $225 $225150 7.44% ...... 150,000 150 150 150 Floating Rate ...... 6,000,000 7 .2 5% ...... $525 Total Quarterly Guaranteed Preferred Beneficial Interest in $525 PSEG's Subordinated Debentures ...... PSE&G Preferred Securities PSE&G Cumulative Preferred Stock (C) without Mandatory $15 Redemption (D) (E) $100 par value series $15 103.00 12 4 .08% ...... 146,221 103.00 12 116,958 15 4 .18% ...... 149,478 102.75 15 10 10 4 .30% ...... 104,002 103.00 5 .05% ...... 103.00 12 12 117,864 16 5.2 8% ...... 160,711 16 6.92% ...... 15 15 $25 par value series 600,000 25.00 6 .75% ...... $95 $95 Total Preferred Stock without Mandatory Redemption ...... With Mandatory Redemption (D) (E) $100 $75 par value series 750,000 101.80 $75 5.97% ...... $75 $75 Total Preferred Stock with Mandatory Redemption ...... PSE&G Monthly Guaranteed Preferred Beneficial Interest in $150 $150 PSE&G's Subordinated Debentures (D) (E) (F) 6,000,000 25.00 60 60 9.375% ...... 2,400,000 25.00 8.00% ...... Total Monthly Guaranteed Preferred Beneficial Interest in $210 $210 PSE&G's Subordinated Debentures ...... PSE&G Quarterly Guaranteed Preferred Beneficial Interest in $208 $208 PSE&G's Subordinated Debentures (D) (E) (F) 8,320,000 95 95 8.625% ...... 3,800,000 8.125% ...... Preferred Beneficial Interest in Total Quarterly Guaranteed $303 $303 PSE&G's Subordinated Debentures ......
stock in (A) The Board of Directors of PSEG authorized the repurchase of up to 30 million shares of its common the open market. At December 31, 2000, PSEG had repurchased approximately 24.2 million shares of common stock at a cost of approximately $905 million. The repurchased shares have been held as treasury stock or used for other corporate purposes. issuance Total authorized and unissued shares include 7,302,488 shares of common stock reserved for plans. In through PSEG's Dividend Reinvestment and Stock Purchase Plan and various employee benefit 2000 and 1999, no shares of common stock were issued or sold through these plans.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
(B) PSEG has authorized a class of 50,000,000 shares of Preferred Stock without par value, none of which is outstanding.
(C) At December 31, 2000, there were aggregates of 5,954,766 shares of $100 par value and 9,400,000 shares of $25 par value Cumulative Preferred Stock which were authorized and unissued and which, upon issuance, may or may not provide for mandatory sinking fund redemption. If dividends upon any shares of Preferred Stock are in arrears in an amount equal to the annual dividend thereon, voting rights for the election of a majority of PSE&G's Board of Directors become operative and continue until all accumulated and unpaid dividends thereon have been paid, whereupon all such voting rights cease, subject to being revived from time to time.
(D) At December 31, 2000 and 1999, the annual dividend requirement of PSEG's Trust Preferred Securities (Guaranteed Preferred Beneficial Interest in PSEG's Subordinated Debentures) and their embedded costs were $38,433,000 and 4.91%, respectively.
At December 31, 2000 and 1999, the annual dividend requirement and embedded dividend rate for PSE&G's Preferred Stock without mandatory redemption was $10,886,758 and 5.18%, respectively, and for PSE&G's Preferred Stock with mandatory redemption was $4,477,500 and 6.02%, respectively.
At December 31, 2000 and 1999, the annual dividend requirement and embedded cost of the Monthly Income Preferred Securities (Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures) were $18,862,500 and 5.50%, respectively.
At December 31, 2000 and 1999, the annual dividend requirement of the Quarterly Income Preferred Securities (Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures) and their embedded costs were $25,658,750 and 5.18%, respectively.
(E) For information concerning fair value of financial instruments, see Note 8. Financial Instruments and Risk Management.
(F) PSE&G Capital L.P., PSE&G Capital Trust I and PSE&G Capital Trust II were formed and are controlled by PSE&G for the purpose of issuing Monthly and Quarterly Income Preferred Securities (Monthly and Quarterly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures). The proceeds were loaned to PSE&G and are evidenced by PSE&G's Deferrable Interest Subordinated Debentures. If and for as long as payments on PSE&G's Deferrable Interest Subordinated Debentures have been deferred, or PSE&G has defaulted on the indentures related thereto or its guarantees thereof, PSE&G may not pay any dividends on its common and preferred stock. The Subordinated Debentures and the indentures constitute a full and unconditional guarantee by PSE&G of the Preferred Securities issued by the partnership and the trusts.
(G) Enterprise Capital Trust I, Enterprise Capital Trust II and Enterprise Capital Trust III were formed and are controlled by PSEG for the purpose of issuing Quarterly Trust Preferred Securities (Quarterly Guaranteed Preferred Beneficial Interest in PSEG's Subordinated Debentures). The proceeds were loaned to PSEG and are evidenced by PSEG's Deferrable Interest Subordinated Debentures. If and for as long as payments on PSEG's Deferrable Interest Subordinated Debentures have been deferred, or PSEG has defaulted on the indentures related thereto or its guarantees thereof, PSEG may not pay any dividends on its common and preferred stock. The Subordinated Debentures and the indentures constitute a full and unconditional guarantee by PSEG of the Preferred Securities issued by the trusts.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note 7. Schedule of Consolidated Debt
LONG-TERM December 31, 2000 1999 Interest Rates Maturity (Millions of Dollars) PSEG Extendible Notes (A): 2000 ...... $275 LIBOR plus 0.22% - 0.60% 300 300 2001 ...... LIBOR plus 0.40% 275 plus 0.875% 2002 ...... Floating Rate Notes-LIBOR 575 575 Principal Am ount Outstanding (C) ...... (300) (275) Amounts Due Within One Year (D) ...... $275 $300 Total Long-Term Debt of PSEG (H) ......
PSE&G First and Refunding Mortgage Bonds (B): 623 2000 ...... 6.00%--7.625% 100 100 2001 ...... 7.19%-7.875% 258 257 2002 ...... 6.125%-7.19% 300 300 2003 ...... 6.875%-8.875% 286 286 2004 ...... 6.50% 125 125 2005 ...... 9.125% 260 260 2006-2007 ...... 6.25/"6.50% 66 66 2008-2012 ...... Variable 330 330 2013-2017 ...... 6.75%47.375% 139 139 2018-2022 ...... 6.450/6-9.25% 14 14 2018-2022 ...... Variable 434 434 2023-2027 ...... 5.200/6-7.50% 499 499 5.450/".55% 2028-2032 ...... 25 25 2028-2032 ...... Variable 160 160 5.000108.00% 2033-2037 ...... Medium-Term Notes: 290 2002 ...... 7.19% 60 60 2008-2012 ...... 8.10%/0-8.16% 9 9 2018-2022 ...... 7.04% 39 39 7.150/-47.18% 2023-2027 ...... 3,394 3,726 Refunding Mortgage Bonds ...... Total First and 300 2002 ...... Unsecured Bonds-7.43% 19 19 2027 ...... Unsecured Bonds-Variable 319 19 Total U nsecured Bonds ...... 3,713 3,745 ...... Principal Amount Outstanding (C) ...... (100) (623) ...... Amounts Due Within One Year (D) (23) (23) ...... Net Unamortized Discount $3,590 $3,099 Total Long-Term Debt of PSE&G (E) ......
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
December 31, Interest Rates Maturity 2000 1999 Energy Holdings (Millions of Dollars) Senior Notes: 9.125% 2004 ...... $ 300 10.00% 2009 ...... 400 400 Principal A m ount O utstanding (C) ...... 700 400 N et U nam ortized D iscount ...... (5) (4) 695 396
PSEG Capital Medium-Term Notes: 6.54% 2000 ...... 78 6.73% - 6.74% 2001 ...... 170 170 6.80% - 7.72% 2002 ...... 228 130 6.25% 2003 ...... 252 252 Principal A m ount O utstanding (C) ...... 650 630 Amounts Due Within One Year (D) ...... (170) (78) N et U nam ortized D iscount ...... (1) (2) Total Long-Term Debt of PEG Capital ...... 479 550
Global Non-recourse Debt (G): 11.08% - Bank Loan 2000 ...... 67 13.73% - Bank Loan 2000-2002 ...... 90 10.0 10% and 9.04% respectively - Bank Loan 2001 ...... 85 85 10.385% and 9.42% respectively - Bank Loan 2001-2003 ...... 28 28 10.385% and 9.42% respectively - Bank Loan 2001-2004 ...... 47 47 Variable 2004-2010 ...... 34 Variable 2002-2019 ...... 126 14.00% -- Minority Shareholder Loan 2027 ...... 10 10 Principal A m ount Outstanding (C) ...... 330 327 Amounts Due Within One Year (D) ...... (96) (97) Total Long-Term Debt of Global ...... 234 230
Resources 8.6% - Bank Loan 2000-2019 ...... 24 Principal A m ount Outstanding (C) ...... 24 Amounts Due Within One Year (D) ...... (1) Total Long-Term Debt of Resources ...... 23
Energy Technologies 2.90% - 11.65% Other Loans 2001-2005 ...... I Total Long-Term Debt of Energy Technologies ...... 1 Total Long-Term Debt of Energy Holdings ...... 1,432 1,176 . Consolidated Long-Term Debt ...... $5,297 $4,575
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
(A) In June 1999, PSEG issued $300 million of Extendible Notes, Series C, due June 15, 2001. At December 31, 2000, the interest rate on Series C was 6.955%. In November 2000, PSEG issued $275 million of Floating Rate Notes due May 21, 2002 with an interest rate is at three-month LIBOR, plus 0.875%.
(B) PSE&G's First and Refunding Mortgage (Mortgage), securing the Bonds, constitutes a direct first mortgage lien on substantially all of PSE&G's property and franchises.
(C) For information concerning fair value of financial instruments, see Note 8. Financial Instruments and Risk Management.
(D) The aggregate principal amounts of mandatory requirements for sinking funds and maturities for each of the five years following December 31, 2000 are as follows:
Energy PSEG Year PSEG PSE&G Holdings Capital Global Resources Total 2001 ...... 300 100 - 170 96 1 667 2002 ...... 275 848 - 228 28 1 1,380 2003 ...... - 300 - 252 42 1 595 2004 ...... - 286 300 - 35 1 622 2005 ...... - 125 - - 18 1 144 575 1,659 300 650 219 5 3,408
(E) At December 31, 2000 and 1999, PSE&G's annual interest requirement on long-term debt was $256 million and $254 million, of which $233 million and $246 million, respectively, was the requirement for Mortgage Bonds. The embedded interest cost on long-term debt on such dates was 7.30% and 7.34%, respectively. The embedded interest cost on long-term debt due within one year at December 31, 2000 was 8.37%.
(F) PSEG Capital has provided up to $750 million debt financing for Energy Holdings' businesses, except Energy Technologies, on the basis of a net worth maintenance agreement with PSEG. Since 1995, PSEG Capital has limited its borrowings to no more than $650 million.
(G) Global's projects are generally financed with non-recourse debt at the project level, with the balance in the form of equity investments by the sponsors in the project. The non-recourse debt shown in the above table is that of consolidated subsidiaries which have equity investments in distribution facilities in Argentina, Chile and Peru and generation facilities under construction in Poland and Tunisia. Global's capital at risk on the projects is limited to its original equity investment.
(H) At December 31, 2000 and 1999, PSEG's annual interest requirement on long-term debt was $440 million and $409 million, of which $233 million and $246 million, respectively, was the requirement for Mortgage Bonds. The embedded interest cost on long-term debt on such dates was 7.66% and 7.59%, respectively.
SHORT-TERM (Commercial Paper and Bank Loans)
PSEG
At December 31, 2000, PSEG had a committed $150 million revolving credit facility which will expire in December 2002. At December 31, 2000, there was a $150 million loan outstanding under this revolving credit facility. On September 8, 1999, PSEG entered into an uncommitted line of credit with a bank with no stated limit. At December 31, 2000, PSEG had $95 million outstanding under this line of credit. The weighted-average, short term debt rate of PSEG was 7.3%, 6.7% and 5.6% for the years ended December 31,2000, 1999 and 1998, respectively.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
PSEG has an $850 million commercial paper program to provide funds for general corporate purposes and to provide funds for Power. On December 31, 2000, PSEG had commercial paper of $617 million outstanding.
To provide liquidity for its commercial paper program, PSEG has a $570 million revolving credit facility expiring in March 2001 and a $280 million revolving credit facility expiring in March 2005. These agreements are with a group of banks and provide for borrowings with maturities of up to one year. As of December 31, 2000 there were no borrowings outstanding under these facilities.
PSE&G
2000 1999 1998 (Millions of Dollars) Principal amount outstanding at year end, primarily commercial paper .... $1,543 $1,475 $850 Weighted average interest rate for short-term debt at year end ...... 7.29% 6.56% 5.91%
On December 7, 2000, PSE&G issued $300 million of Floating Rate Notes at 7.4275%, due December 7, 2002. The proceeds were used for general corporate purposes including the repayment of short-term debt.
PSE&G has a $1.5 billion commercial paper program (Program). To provide liquidity for this Program, PSE&G has a $450 million revolving credit agreement expiring in June 2001, a $450 million credit facility expiring in June 2002 and a $400 million credit facility and a $200 million credit facility expiring in June 2001. These agreements provide for borrowings with maturities of up to one year. As of December 31, 2000 and 1999, PSE&G had $1.2 billion and $1.407 billion, respectively, outstanding under the Program, which amounts are included in the table above. As of December 31, 2000, there were no borrowings outstanding under the credit facilities.
PSE&G has several uncommitted lines of credit with banks. On December 31, 2000, PSE&G had $1.543 billion of short-term debt outstanding, including $336 million borrowed against its uncommitted bank lines of credit and $1.2 billion of commercial paper.
PSE&G Fuel Corporation had a $125 million commercial paper program to finance a 42.49% share of Peach Bottom nuclear fuel. As a result of the transfer of generation assets from PSE&G to Power, the PSE&G Fuel Corporation commercial paper program was discontinued and all commercial paper outstanding under this program was paid down on August 17, 2000. Power
Power has various lines of credit extended by banks to support the issuance of letters of credit. As of December 31, 2000, letters of credit were issued in the amount of approximately $58 million.
Energy Holdings
2000 1999 1998 (Millions of Dollars) Principal amount outstanding at year end ...... $392 $351 $206 Weighted average interest rate for short-term debt at year end ...... 7.76% 7.60% 6.46%
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Energy Holdings has two separate senior revolving credit facilities. These facilities are a $495 million, five year revolving credit and letter of credit facility and a $165 million, 364 day revolving credit facility. As of December 31, 2000, there was $392 million outstanding under these facilities.
Note 8. Financial Instruments and Risk Management
PSEG's operations result in exposure to market risks from changes in commodity prices, interest rates, foreign currency exchange rates and securities prices. PSEG's policy is to use derivative financial instruments for the purpose of managing market risk consistent with its business plans and prudent business practices.
Fair Value of Financial Instruments
The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions at December 31, 2000 and December 31, 1999, respectively. December 31, 2000 December 31, 1999 Carrying Fair Carrying Fair Amount Value Amount Value (Millions of Dollars) Long-Term Debt (A): PSEG ...... $ 575 $ 575 $ 575 $ 574 Energy Holdings ...... 1,699 1,725 1,351 1,346 PSE& G ...... 3,690 3,453 3,722 3,658 Preferred Securities Subject to Mandatory Redemption: PSE&G Cumulative Preferred Securities ...... 75 60 75 67 Monthly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures ...... 210 212 210 200 Quarterly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures ...... 303 304 303 277 Quarterly Guaranteed Preferred Beneficial Interest in PSEG's Subordinated Debentures ...... 525 474 525 420
(A) Includes current maturities. At December 31, 2000 Energy Holdings and PSEG had interest rate swap agreements outstanding with notional amounts of $139 million and $150 million, respectively. At December 31, 1999 Energy Holdings and PSEG had interest rate swap agreements outstanding with notional amounts of $34 million and $150 million, respectively.
Global has $160 million of project debt that is non-recourse to PSEG, Global and Energy Holdings associated with investments in Poland and Tunisia. Interest rate swaps were entered into which effectively converts $139 million of this $160 million floating rate obligation into a fixed rate obligation.
Commodity-Related Instruments - PSE&G and Power
At December 31, 2000 and December 31, 1999, PSE&G and Power held or issued commodity and financial instruments that reduce exposure to price fluctuations from factors such as weather, environmental policies, changes in demand, changes in supply, state and Federal regulatory policies and other events. These instruments, in conjunction with owned electric generating capacity and physical gas supply contracts, are designed to cover estimated electric and gas customer commitments. Power uses futures, forwards, swaps and options to manage and hedge price risk related to these market exposures.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
At December 31, 2000, Power had outstanding commodity financial instruments with a notional contract quantity of 54.0 million mWh of electricity and PSE&G had outstanding commodity financial instruments with a notional contract quantity of 67.2 million MMBTU of natural gas. At December 31, 1999, PSE&G had outstanding commodity financial instruments with a notional contract quantity of 36.1 million mWh of electricity and 25.5 million MMBTU of natural gas. Notional amounts are indicative only of the volume of activity and are not a measure of market risk.
PSE&G's and Power's energy trading and related contracts have been marked to market and gains and losses from such contracts were included in earnings. PSE&G recorded $7 million of unrealized gains for the year ended December 31, 1999 and $42 million of unrealized gains in 2000 prior to the transfer of assets. Following the asset transfer, Power recorded $13 million of unrealized gains through December 31, 2000 related to these contracts.
Commodity-Related Instruments - Energy Holdings
In June 2000, Energy Technologies outsourced certain supply services under its retail gas service agreements. With this transaction, Energy Technologies has changed the manner in which it operates its energy and gas commodity business and at December 31, 2000 there were no electric or gas commodity financial instruments outstanding. Energy Holdings had recorded $1.7 million of gains in the year ended December 31, 2000 related to these instruments.
Credit Risk
Credit risk relates to the risk of loss that PSEG would incur as a result of nonperformance by counterparties, pursuant to the terms of their contractual obligations. PSEG has established credit policies that it believes significantly minimize PSEG's exposure to credit risk. These policies include an evaluation of potential counterparties' financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which may allow for the netting of positive and negative exposures associated with a single counterparty.
Equity Securities - Energy Holdings
Resources has direct and indirect investments in equity securities. Resources carries its investments in equity securities at their approximate fair value. Consequently, the carrying value of these investments is affected by changes in the fair value of the underlying securities. Fair value is determined by adjusting the market value of the securities for liquidity and market volatility factors, where appropriate. The aggregate fair values of such investments which had available market prices at December 31, 2000 and 1999 were $115 million and $131 million, respectively. The decrease in fair value was primarily due to the lower valuation of various securities within Resources' portfolio. The potential change in fair value resulting from a hypothetical 10% change in quoted market prices of these investments amounted to $9 million at December 31, 2000 and $11 million at December 31, 1999.
Foreign Currencies - Energy Holdings
As of December 31, 2000, Global and Resources had international assets of approximately $1.8 billion and $1.2 billion, respectively.
Resources' international investments are primarily leveraged leases of assets located in the Netherlands, Australia, the United Kingdom, Germany, China and New Zealand with associated revenues denominated in U.S. dollars, and therefore, not subject to foreign currency risk.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Global's international investments are primarily in projects that generate or distribute electricity in Argentina, Brazil, Chile, China, India, Italy, Peru, Poland, Tunisia and Venezuela. Investing in foreign countries involves certain additional risks. Economic conditions that result in higher comparative rates of inflation in foreign countries are likely to result in declining values in such countries' currencies. As currencies fluctuate against the U.S. dollar, there is a corresponding change in Global's investment value in terms of the U.S. dollar. Such change is reflected as an iricrease or decrease in the investment value and other comprehensive income, a separate component of stockholders' equity. Cumulatively through December 31, 2000, net foreign currency devaluations have reduced the reported amount of PSEG's total stockholders' equity and Energy Holdings' total stockholder's equity by $203 million, $150 million of which was caused by the devaluation of the Brazilian Real as of December 31, 2000.
Previously, Global had consolidated project debt totaling approximately $94.5 million associated with Global's 32% investment in a Brazilian distribution company that was non-recourse to Global, Energy Holdings and PSEG. The debt was denominated in the Brazilian Real and was indexed to a basket of currencies, including the U.S. dollar. The debt was refinanced in May 2000 with funds from Energy Holdings and a $190 million United States dollar denominated loan at the Brazilian distribution company, of which Global's share is $62 million. The functional currency of the distribution company is the Brazilian Real. Therefore, its debt is subject to exchange rate risk as the Brazilian Real fluctuates with the United States dollar. Changes in the exchange rate cause the loan amount, as reported in the functional currency, to be marked upward or downward, with an offset to the income statement. Global entered into a $60 million currency collar which expired on December 29, 2000 to mitigate the potential loss caused by a significant devaluation of the functional currency against the U.S. dollar. Interest Rates
PSEG, PSE&G and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. Their policy is to manage interest rate risk through the use of fixed rate debt, floating rate debt and interest rate swaps. As of December 31, 2000, a hypothetical 10% change in market interest rates would result in a $31 million, $13 million and $6 million change in annual interest costs related to short-term and floating rate debt at PSEG, PSE&G and Energy Holdings, respectively.
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 issued in June 1998. The Floating Rate Capital Securities were issued at an annual rate equal to three-month LIBOR plus 1.22%, reset quarterly. 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 LIBOR. This interest rate swap hedges the underlying debt for 10 years at an effective rate of 7.2%. The fair value of the swap at December 31, 2000 was approximately $1 million.
Global invested in development projects, to construct electric generation facilities in Tunisia and Poland. Such entities have entered into interest rate swaps to hedge up to $422 million of its construction loan agreements. The interest rate swaps effectively convert the existing floating rate debt into fixed rate borrowings. The notional amounts, interest rates and fair values as of December 31, 2000 are as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Poland Tunisia US $ PLN US $ Euro Tranche Tranche Tranche Tranche (Millions, where applicable) Notional Amount ...... $18 $8 $52 $61 Pay R ate ...... 8.4% 13.2% 6.9% 5.2% Receive Rate ...... LIBOR WIBOR** LIBOR EURIBOR* Fair V alue ...... ($26) ($11) ($3) ($1) * EURIBOR-Euro Area Inter-Bank Offered Rate ** WIBOR- Warsaw Inter-Bank Offered Rate
Nuclear Decommissioning Trust Funds
Contributions made into the Nuclear Decommissioning Trust Funds are invested in debt and equity securities. These marketable debt and equity securities are recorded at $716 million which approximates their fair market value. Those securities have exposure to market price risk. The potential change in fair value resulting from a hypothetical 10% change in quoted market prices of these securities amounts to $72 million. The ownership of the Nuclear Decommissioning Trust Funds were transferred to Nuclear with the transfer of the generation-related assets from PSE&G to Power.
Note 9. Cash and Cash Equivalents
The December 31, 2000 and 1999 balances consist primarily of working funds and highly liquid marketable securities (commercial paper and money market funds) with a maturity of three months or less.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note 10. Commitments and Contingent Liabilities
Nuclear Insurance Coverages and Assessments
Power's insurance coverages and maximum retrospective assessments for its nuclear operations are as follows:
Total Site Power Type and Source of Coverages Coverage Assessments (Millions of Dollars) Public and Nuclear Worker Liability (Primary Layer): American Nuclear Insurers ...... $200.0 (A) $9.1 Nuclear Liability (Excess Layer): Price-Anderson Act ...... 9,338.1 (B) 253.3 Nuclear Liability Total ...... $9,538.1 (C) $262.4 PropertyDamage (PrimaryLayer): Nuclear Electric Insurance Limited (NEIL) Primary (Salem/Hope Creek/Peach Bottom) ...... $500.0 $7.4
PropertyDamage (Excess Layers): NEIL II (Salem/Hope Creek/Peach Bottom) .... 1,250.0 5.5 NEIL Blanket Excess (Salem/Hope Creek/Peach Bottom) ...... 1,000.0 (D) 0.9 Property Damage Total (Per Site) ...... $2,750.0 $13.8
Accidental Outage: NEIL I (Salem and Peach Bottom) ...... $210.0 (E) $4.3 NEIL I (Hope Creek) ...... 465.5 $2.3 Replacement Power Total ...... $675.5 $6.6
(A) The primary limit for Public Liability is a per site aggregate limit with no potential for assessment. The Nuclear Worker Liability represents the potential liability from workers claiming exposure to the hazard of nuclear radiation. This coverage is subject to an industry aggregate limit, includes annual automatic reinstatement if the Industry Credit Rating Plan (ICRP) Reserve Fund exceeds $400 million, and has an assessment potential under former canceled policies.
(B) Retrospective premium program under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. Nuclear is subject to retrospective assessment with respect to loss from an incident at any licensed nuclear reactor in the United States. This retrospective assessment can be adjusted for inflation every five years. The last adjustment was effective as of August 20, 1998. This retrospective program is in excess over the Public and Nuclear Worker Liability primary layers.
(C) Limit of liability under the Price-Anderson Act for each nuclear incident.
(D) For property limits excess of $1.75 billion, Power participates in a Blanket Limit policy where the $1 billion limit is shared by Amergen, Exelon, and Power among the Clinton, Oyster Creek, TMI-I, Limerick, Peach Bottom, Salem and Hope Creek sites. This limit is not subject to reinstatement in the event of a loss. Participation in this program significantly reduces Power's premium and the associated potential assessment.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
(E) Salem and Peach Bottom have an aggregate indemnity limit based on a weekly indemnity of $1.5 million for 52 weeks followed by 80% of the weekly indemnity for 110 weeks. Hope Creek has an aggregate indemnity limit based on a weekly indemnity of $3.3 million for 52 weeks followed by 80% of the weekly indemnity for 110 weeks.
The Price-Anderson Act sets the "limit of liability" for claims that could arise from an incident involving any licensed nuclear facility in the nation. The "limit of liability" is based on the number of licensed nuclear reactors and is adjusted at least every five years based on the Consumer Price Index. The current "limit of liability" is $9.5 billion. All utilities owning a nuclear reactor, including Nuclear, have provided for this exposure through a combination of private insurance and mandatory participation in a financial protection pool as established by the Price-Anderson Act. Under the Price-Anderson Act, each party with an ownership interest in a nuclear reactor can be assessed its share of $88.1 million per reactor per incident, payable at $10 million per reactor per incident per year. If the damages exceed the "limit of liability," the President is to submit to Congress a plan for providing additional compensation to the injured parties. Congress could impose further revenue raising measures on the nuclear industry to pay claims. Nuclear's maximum aggregate assessment per incident is $253.3 million (based on Nuclear's ownership interests in Hope Creek, Peach Bottom and Salem) and its maximum aggregate annual assessment per incident is $28.8 million. This does not include the $9.1 million that could be assessed under the nuclear worker policies.
Further, a decision by the U.S. Supreme Court, not involving Nuclear, has held that the Price-Anderson Act did not preclude awards based on state law claims for punitive damages.
Power is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL). NEIL provides the primary property and decontamination liability insurance at Salem/Hope Creek and Peach Bottom. NEIL also provides excess property insurance through its decontamination liability, decommissioning liability, and excess property policy and replacement power coverage through its accidental outage policy. NEIL policies may make retrospective premium assessments in case of adverse loss experience. Power's maximum potential liabilities under these assessments are included in the table and notes above. Certain provisions in the NEIL policies provide that the insurer may suspend coverage with respect to all nuclear units on a site without notice if the NRC suspends or revokes the operating license for any unit on a site, issues a shutdown order with respect to such unit or issues a confirmatory order keeping such unit down.
Pending Asset Purchases
In September 1999, Power signed an agreement to acquire all of Conectiv's interests in the Salem Nuclear Generating Station (Salem) and the Hope Creek Nuclear Generating Station (Hope Creek) and half of Conectiv's interest in the Peach Bottom Atomic Power Station (Peach Bottom), totaling 544 MW for an aggregate purchase price of $15.4 million plus the net book value of nuclear fuel at closing. In December 2000, the sale to Power of the Delmarva Power & Light Company (DP&L) portion of Conectiv's interests in Salem (7.41%) and Peach Bottom (7.51%, split equally between Power and Exelon) was completed. On October 6, 2000, Power entered into Wholesale Transaction Confirmation letter agreements with Atlantic City Electric Company (ACE) under which Power obtains 298MW of generation capacity and output representing the portion of ACE's interest in Salem, Hope Creek and Peach Bottom to be acquired. Under this agreement, Power receives all revenue and pays all expenses associated with this 298MW of generating capacity and output through the date that the purchase transaction closes. Power has been advised by Conectiv that the Ratepayer Advocate, by letter to the BPU dated October 26, 2000, has objected to and challenged this financial transaction.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Hazardous Waste
The New Jersey Department of Environmental Protection (NJDEP) regulations concerning site investigation and remediation 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 industry to develop procedures for implementing these regulations. These regulations may substantially increase the costs of remedial investigations and remediations, where necessary, particularly at sites situated on surface water bodies. PSE&G and predecessor companies owned and/or operated certain facilities situated 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. PSEG does not anticipate that the compliance with these regulations will have a material adverse effect on its financial position, results of operations or net cash flows.
PSE&G Manufactured Gas Plant Remediation Program
PSE&G is currently working with NJDEP under a program (Remediation Program) to assess, investigate and, if necessary, remediate environmental conditions at PSE&G's former manufactured gas plant sites. To date, 38 sites have been identified. 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 long-term costs of the Remediation Program cannot be reasonably estimated, but experience to date indicates that at least $20 million per year could be incurred over a period of about 30 years and that the overall cost could be material. The costs for this remediation effort are recovered through the SBC.
Net of recoveries, costs incurred through December 31, 2000 for the Remediation Program amounted to $125 million. In addition, at December 31, 2000, PSE&G's estimated liability for remediation costs through 2003 aggregated $74 million. Expenditures beyond 2003 cannot be reasonably estimated. Passaic River Site
The EPA has determined that a six mile stretch of the Passaic River in Newark, New Jersey is a "facility" within the meaning of that term under the Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA) and that, to date, at least thirteen corporations, including PSE&G, may be potentially liable for performing required remedial actions to address potential environmental pollution at the Passaic River "facility." PSE&G and certain of its predecessors operated industrial facilities at properties within the Passaic River "facility," comprised of four former manufactured gas plants (MGP), one operating electric generating station and one former generating station. Costs to clean up former MGPs are recoverable from utility customers under the SBC. The operating station has been transferred to Power, which is responsible for its clean up. PSE&G and Power cannot predict what action, if any, the EPA or any third party may take against PSE&G and Power with respect to these matters, or in such event, what costs PSE&G and Power may incur to address any such claims. However, such costs may be material.
Prevention of Significant Deterioration (PSD)/New Source Review
The EPA and NJDEP issued a demand to PSE&G in March 2000 under section 114 of the Federal Clean Air Act (CAA) requiring information to assess whether projects completed since 1978 at the Hudson and Mercer coal burning units were implemented in accordance with applicable PSD/New Source Review regulations. As a result of the transfer of the generating assets by PSE&G to Power, and the related Assignment and Assumption Agreement, the responsibility for these environmental requirements rests with Power. Power completed its response to the section 114 information request in November 2000. Based upon the information provided to the EPA it is likely that the EPA will seek to enforce the requirements of the New Source Review program at Hudson 2 and Mercer I
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
and 2. Power is currently in discussions with the EPA and NJDEP to resolve the matter. However, it is uncertain whether these discussions will be successful and capital costs of compliance could approximate $300 million. These costs are not currently included in Power's business plans.
Subsequent to December 31, 2000, the EPA indicated that it is considering enforcement action against Power under its PSD rules relating to the construction that is currently in progress for Bergen 2, scheduled for operations in 2002. The EPA maintains that PSD requirements are applicable to Bergen 2, thereby requiring Power to obtain a permit prior to the commencement of construction. To obtain such a permit, an applicant must demonstrate that addition of the additional emission source will not cause significant deterioration of the air shed in the vicinity of the plant. The time required to obtain such a permit is estimated at 12-18 months. Power vigorously disputes that PSD requirements are applicable to Bergen 2 and is continuing construction. NJDEP has informally indicated it agrees with Power's position. Settlement discussions are underway with the EPA. At January 31, 2001, Power had expended approximately $83.1 million in the construction of Bergen 2.
Note 11. Nuclear Decommissioning Trust
Power has an external master nuclear decommissioning trust previously established by PSE&G. This trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a "qualified" fund. Contributions made into a qualified fund are tax deductible. Power estimates the total cost of decommissioning its share of its five nuclear units at $986 million in year-end 1995 dollars, excluding contingencies.
Pursuant to the Final Order, PSE&G will collect $29.6 million annually through the SBC and will give Power an equivalent amount solely to fund the trust. The fair market value of these funds as of December 31, 2000 and 1999 was $716 million and $631 million, respectively.
Note 12. Income Taxes
PSE&G is currently assessed with 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). The TEFA, which is collected from customers, is being phased-out through 2003. The corresponding phase out and reduction in rates will cause no material impact on PSEG and PSE&G as such reductions are passed through to the transmission and distribution customers. Effective January 1, 1999, revised rates became effective which reflect one year's phase out of the TEFA. Effective January 1, 2000, revised rates became effective which reflect two year's phase out of the TEFA.
A reconciliation of reported Net Income with pretax income and of income tax expense with the amount computed by multiplying pretax income by the statutory Federal income tax rate of 35% is as follows:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
2000 1999 1998 (Millions of Dollars) Net Income (Loss) ...... $764 $(81) $644 Extraordinary Item (Net of Tax of $345) ...... 804 Net Income before Extraordinary Item ...... 764 723 644 Preferred securities (net) ...... 9 9 9 Subtotal ...... 773 732 653 Income taxes: Operating income: Federal - Current ...... 150 398 336 Deferred (A) ...... 228 63 4 ITC ...... (2) (12) (21) Total Federal ...... 376 449 319 121 State - Current ...... 160 132 Deferred (A) ...... (50) (13) (9) Total State ...... 110 119 112 Foreign - Current ...... Deferred (A) ...... 4 (5) (3) Total Foreign ...... 4 (5) (3) Total included in operating income ...... 490 563 428 Pretax income ...... $1,263 $1,295 $1,081
Reconciliation between total income tax provisions and tax computed at the statutory tax rate on pretax income: 2000 1999 1998 (Millions of Dollars) Tax com puted at the statutory rate ...... $442 $453 $378 Increase (decrease) attributable to flow through of certain tax adjustments: Depreciation ...... (15) 35 23 Am ortization of investm ent tax credits ...... (2) (12) (21) N ew Jersey Corporate Business Tax ...... 74 84 63 Other ...... (9) 3 (15) Subtotal ...... 48 110 50 Total incom e tax provisions ...... $490 $563 $428 39.6% Effective incom e tax rate ...... 38.8% 43.5%
(A) The provision for deferred income taxes represents the tax effects of the following items: 2000 1999 1998 (Millions of Dollars) Deferred Credits: Additional tax depreciation and amortization ...... $26 $(17) $(33) Leasing A ctivities ...... 190 94 39 Conservation Costs ...... 29 29 36 Deferred Fuel Costs- net ...... (19) (60) Pension Cost ...... (19) (34) 26 N ew Jersey Corporate Business Tax ...... (33) (13) (5) 5 Environm ental Cleanup Costs ...... 11 2 M arket Transition Charge ...... (38) Other ...... 16 (13) Total ...... $182 $45 $(8)
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
PSEG provides deferred taxes at the enacted statutory tax rate for all temporary differences between the financial statement carrying amounts and the tax bases of existing assets and liabilities irrespective of the treatment for rate-making purposes. Management believes that it is probable that the accumulated tax benefits that previously have been treated as a flow-through item to PSE&G customers will be recovered from utility customers in the future. Accordingly, an offsetting regulatory asset was established. As of December 31, 2000, PSE&G had a deferred tax liability and an offsetting regulatory asset of $285 million representing the future revenue expected to be recovered through rates based upon established regulatory practices which permit recovery of current taxes payable. This amount was determined using the enacted Federal income tax rate of 35% and State income tax rate of 9%. During 1999, PSE&G's accumulated deferred income tax liability was reduced, reflecting the impact of the impairment writedown of the book basis of PSE&G's generating facilities. This was offset by the establishment of a deferred tax liability representing the future taxes payable applicable to the recovery of the stranded costs pursuant to the Final Order.
The following is an analysis of deferred income taxes:
December 31, 2000 1999 Deferred Income Taxes (Millions of Dollars) Assets: Current (net) ...... $23 $33 Non-current: Unrecovered Investment Tax Credits ...... 20 23 Deferred Electric Energy and Gas Costs ...... 17 18 Performance Incentive Plan ...... 7 7 New Jersey Corporate Business Tax ...... 396 493 Vacation Pay ...... 6 6 Development Fees ...... 17 16 Foreign Currency Translation ...... 23 22 M arket Transition Charge ...... 38 Total N on-current ...... 524 585 Total Assets ...... 547 618 Liabilities: Non-current: Plant Related Items ...... 543 628 Securitization-EM P ...... 1,657 1,657 Leasing Activities ...... 987 797 Partnership Activities ...... 101 118 Conservation Costs ...... 124 95 Unamortized Debt Expense ...... 35 39 Taxes Recoverable Through Future Rates (net) ...... 90 87 O th e r ...... 20 17 Total Non-current ...... 3,557 3,438 Total Liabilities ...... 3,557 3,438 Summary - Accumulated Deferred Income Taxes Net Current Assets ...... 23 33 Net Non-current Liability ...... 3,033 2,853 Total $3,010 $2,820
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note 13. Pension, Other Postretirement Benefit and Savings Plans
Pension and Other Postretirement Benefit Plans
Pension Benefits Other Benefits $ in Millions 2000 1999 2000 1999 Change in Benefit Obligation Benefit Obligation at Beginning of Year $ 2,383.6 $ 2,487.7 $ 691.2 $ 781.7 Service Cost 60.5 68.0 12.0 13.1 Interest Cost 172.6 163.3 53.9 51.3 Actuarial (Gain)/Loss (6.2) (195.2) (20.1) (120.2) Benefits Paid (145.3) (140.2) (36.6) (34.7) Plan Amendments 22.2 0.0 0.0 0.0 Business Combinations 7.0 0.0 2.3 0.0 Benefit Obligation at End of Year 2,494.4 2,383.6 702.7 691.2
Change in PlanAssets Fair Value of Assets at Beginning of Year 2,525.6 2,222.6 28.5 13.0 Actual Return on Plan Assets (11.8) 368.3 (0.1) 3.5 Employer Contributions 2.8 74.9 36.6 46.7 Benefits Paid (145.3) (140.2) (36.6) (34.7) Business Combinations 4.8 0.0 0.0 0.0 Fair Value of Assets at End of Year 2,376.1 2,525.6 28.4 28.5
Reconciliation of Funded Status Funded Status (118.3) 142.0 (674.3) (662.7) Unrecognized Net Transition Obligation 20.8 28.9 337.9 368.3 Prior Service Cost 129.4 119.6 25.1 27.3 (Gain)/Loss 70.3 (154.6) (139.0) (128.2) Net Amount Recognized 102.2 $ 135.9 (450.3) $ (395.3)
Amounts Recognized In Statement OfFinancial Position Prepaid Benefit Cost $ 125.4 $ 152.1 $ 0.0 $ 0.0 Accrued Cost (49.5) (44.3) (450.3) (395.3) Intangible Asset 22.6 23.5 N/A N/A Accumulated Other Comprehensive Income 3.7 4.6 N/A N/A Net Amount Recognized $ 102.2 $ 135.9 $ (450.3) $ (395.3)
SeparateDisclosure for Pension Plans With Accumulated Benefit Obligation In Excess of PlanAssets: Projected Benefit Obligation at End of Year $ 66.7 $ 52.4 Accumulated Benefit Obligation at End of Year $ 52.7 $ 44.2 Fair Value of Assets at End of Year $ 4.5 $ 0.0
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Pension Benefits Other Benefits $ in Millions 2000 1999 1998 2000 1999 1998 Components of Net PeriodicBenefit Cost Service Cost $ 60.5 $ $ 68.0 59.6 $ 12.0 $ 13.1 $ 14.8 Interest Cost 172.6 163.3 157.7 53.9 51.3 55.6 Expected Return on Plan Assets (221.0) (197.3) (176.2) (2.6) (1.7) (0.5) Amortization of Net Transition Obligation 8.1 8.1 8.1 30.4 30.4 30.4 Prior Service Cost 14.3 14.1 14.1 2.2 2.2 2.2 (Gain)/Loss 0.5 0.8 0.2 (3.4) (3.0) (1.0) Net Periodic Benefit Cost $ 35.0 $ 57.0 $ 63.5 $ 92.5 $ 92.3 $ 101.5
Components of Total Benefit Expense Net Periodic Benefit Cost 35.0 57.0 63.5 $ 92.5 $ 92.3 $ 101.5 Effect of Regulatory Asset 0.0 0.0 0.0 19.3 19.3 19.3 Total Benefit Expense Including Effect of Regulatory Asset S 35.0 $ 57.0 $ 63.5 $ 111.8 $ 111.6 $ 120.8
Components of Other Comprehensive Income Decrease in Intangible Asset $ 0.9 $ 2.6 $ (1.0) Increase in Additional Minimum Liability (1.8) (3.4) (4.0) Other Comprehensive Income $ (0.9) $ (0.8) $ (5.0) N/A N/A N/A
Weighted-Average Assumptions as of December31 Discount Rate 7.50% 7.50% 6.75% 7.50% 7.50% 6.75% Expected Return on Plan Assets 9.00% 9.00% 9.00% 9.00% 9.00% 9.00% Rate of Compensation Increase 4.69% 4.69% 4.69% 4.69% 4.69% 4.69% Rate of Increase in Health Benefit Costs Administrative Expense 5.00% 5.00% 5.00% Dental Costs 6.00% 5.00% 5.00% Pre-65 Medical Costs Immediate Rate 10.00% 11.00% 11.50% Ultimate Rate 6.00% 5.00% 5.00% Year Ultimate Rate Reached 2008 2011 2011 Post-65 Medical Costs Immediate Rate 8.00% 7.00% 7.50% Ultimate Rate 6.00% 5.00% 5.00% Year Ultimate Rate Reached 2004 2003 2003 Effect of a Change in the Assumed Rate of Increasein Health Benefit Costs Effect of a 1% Increase On Total of Service Cost and Interest Cost 4.5 4.5 5.1 Postretirement Benefit Obligation 48.5 45.7 59.7 Effect of a 1% Decrease On Total of Service Cost and Interest Cost (3.8) (4.7) (4.3) Postretirement Benefit Obligation (41.4) (39.3) (50.8)
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. In 1999, $12 million was funded, as allowed. Remaining OPEB costs will not be funded in an external trust, as mandated by the BPU.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
In October 1999, PSE&G recorded deferred assets and liabilities associated with the payment and collection of co-owner related OPEB costs. Such costs will be amortized over the remainder of the twenty-year period through 2013, in accordance with SFAS 106. No assurances for recovery of such assets and liabilities can be given.
401K Plans
PSEG sponsors two defined contribution plans. Represented employees of PSE&G, Power and Services are eligible for participation in the PSEG Employee Savings Plan (Savings Plan), while non-represented employees of PSE&G, Power, Energy Holdings and Services are eligible for participation in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). These plans are 401(k) plans to which eligible employees may contribute up to 25% of their compensation. Employee contributions up to 7% for Savings Plan participants and up to 8% for Thrift Plan participants are matched with employer contributions of cash or PSEG common stock equal to 50% of such employee contributions related to employee contributions. Employer contributions, related to participant contributions in excess of 5% and up to 7%, are made in shares of PSEG common stock for Savings Plan participants. Employer contributions, related to participant contributions in excess of 6% and up to 8%, are made in shares of PSEG common stock for Thrift Plan participants. The amount expensed for the matching provision of the plans was approximately $22 million, $21 million and $14 million in 2000, 1999 and 1998, respectively. Note 14. Stock Options, Stock Purchase Plan and Stock Repurchase Program
Stock Options
PSEG and PSE&G apply APB Opinion No. 25, "Accounting for Stock Issued to Employees," and related Interpretations in accounting for stock-based compensation plans, which are described below. Accordingly, compensation expense has been recognized for performance units and dividend equivalent rights issued in tandem with an equal number of options under its fixed stock option grants under the 1989 Long-Term Incentive Plan (1989 LTIP). Performance units and dividend equivalents provide cash payments, dependent upon future financial performance of PSEG in comparison to other companies and dividend payments by PSEG, to assist recipients in exercising options granted. Prior to 1997, all options were granted in tandem with performance units and dividend equivalent rights. In 2000 and 1999, there were no options granted in tandem with performance units and dividend equivalent rights and in 1998, there were 4,600 options granted in tandem with performance units and dividend equivalent rights. No compensation cost has been recognized for fixed stock option grants since the exercise price of the stock options equaled the market price of the underlying stock on the date of grant. Had compensation costs for its stock option grants been determined based on the fair value at the grant dates for awards under these plans in accordance with SFAS No. 123 "Accounting for Stock-Based Compensation," there would have been a charge to PSEG's net income of approximately $3.6 million, $1.8 million and $0.4 million in 2000, 1999 and 1998, respectively, with a $(0.02) and $(0.01) impact on earnings per share in 2000 and 1999, respectively and no impact on earnings per share in 1998.
Under PSEG's 1989 LTIP and 2001 Long-Term Incentive Plan (2001 LTIP), non-qualified options to acquire shares of common stock may be granted to officers and other key employees selected by the Organization and Compensation Committee of PSEG's Board of Directors, the plan's administrative committee (the "Committee"). Payment by option holders upon exercise of an option may be made in cash or, with the consent of the Committee, by delivering previously acquired shares of PSEG common stock. In instances where an optionee tenders shares acquired from a grant previously exercised that were held for a period of less than six months, an expense will be recorded for the difference between the fair market value at exercise date and the option price. Options are exercisable over a period of time designated by the Committee (but not prior to one year from the date of grant) and are subject to such other terms and conditions as the Committee determines. Vesting schedules may be accelerated
87 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued upon the occurrence of certain events, such as a change in control. Options may not be transferred during the lifetime of a holder. The 1989 LTIP currently provides for the issuance of up to 15,000,000 options to purchase shares of common stock. At December 31, 2000, there were 11,259,350 options available for future grants under the 1989 LTIP.
The 2001 LTIP currently provides for the issuance of up to 15,000,000 options to purchase shares of common stock. At December 31, 2000, there were 13,254,500 options available for future grants under the 2001 LTIP.
Since the 1989 LTIP's inception, PSEG has purchased shares on the open market to meet the exercise of stock options. The difference between the cost of the shares (generally purchased on the date of exercise) and the exercise price of the options has been reflected in Stockholders' Equity except where otherwise discussed.
Changes in common shares under option for the three fiscal years in the period ended December 31, 2000 are summarized as follows:
2000 1999 1998 Weighted Weighted Weighted Average Average Average Options Exercise Price Options Exercise Price Options Exercise Price Beginning of year 2,561,883 $34.60 1,243,800 $36.01 430,300 1998 $29.26 Granted 2,745,500 45.33 1,367,000 33.13 841,600 39.16 Exercised (110,684) 29.87 (44,167) 30.37 (28,100) 26.76 Canceled (10,600) 31.23 (4,750) 28.01 End of year 5,186,099 40.38 2,561,883 34.60 1,243,800 36.01 Exercisable at end of year 1,170,278 $34.91 412,738 $35.07 100,963 $29.47
Weighted average fair value of options granted during the year $8.73 $4.20 $4.83
For this purpose, the fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions used for grants in 2000, 1999 and 1998, respectively: expected volatility of 26.63%, 21.45% and 21.41%, risk free interest rates of 6.06%, 6.16% and 4.48%, expected lives of 4.4 years, 4 years and 4 years, respectively. There was a dividend yield of 4.77% in 2000, 6.52% in 1999 and 5.5 1% in 1998 on the non-tandem grants.
The following table provides information about options outstanding at December 31, 2000:
Options Outstanding Options Exercisable Weighted Weighted Weighted Average Average Average Range of Outstanding at Remaining Exercise Exercisable at Exercise Exercise Prices December 31, 2000 Contractual Life Price December 31, 2000 Price $24.00-$30.00 267,833 5.25 years $29.58 259,333 $29.56 $30.01-$35.00 1,351,100 7.94 years 33.13 422,625 33.11 $35.01-$40.00 821,666 8.96 years 39.31 488,320 39.31 $40.01-$47.00 2,745,500 9.92 years 45.33 $24.00-$47.00 5,186,099 9.01 years $40.38 1,170,278 $34.91
88 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
In June 1998, the Committee granted 150,000 shares of restricted common stock to a key executive. These shares are subject to restrictions on transfer and subject to risk of forfeiture until earned by continued employment. The shares vest on a staggered schedule beginning on March 31, 2002 and become fully vested on March 31, 2005. The unearned compensation related to this restricted stock grant as of December 31, 2000 is approximately $3 million and is included in retained earnings on the consolidated balance sheets.
PSEG's Stock Plan for Outside Directors provides non-employee directors, as part of their annual retainer, 600 shares of common stock, increased from 300 shares per year beginning in 1999. With certain exceptions, the restrictions on the stock provide that the shares are subject to forfeiture if the individual ceases to be a director at any time prior to the Annual Meeting of Stockholders following his or her 7 0 "hbirthday. The fair value of these shares is recorded as compensation expense in the consolidated statements of income. Stock Purchase Plan
PSEG has an employee stock purchase plan for all eligible employees. Under the plan, shares of the common stock may be purchased at 95% of the fair market value. Employees may purchase shares having a value not exceeding 10% of their base pay. During 2000, 1999 and 1998, employees purchased 101,986, 98,099 and 102,387 shares at an average price of $37.06, $38.21 and $36.36 per share, respectively. At December 31, 2000, 1,289,780 shares were available for future issuance under this plan.
Stock Repurchase Program
The PSEG Board of Directors has authorized the repurchase of up to 30 million shares of its common stock from time to time, subject to market conditions and other relevant factors affecting PSEG. Share repurchases are planned when market and business conditions are deemed favorable. The repurchased shares have been held as treasury stock or used for corporate purposes. As of December 31, 2000, PSEG had repurchased 24.2 million shares at a cost of approximately $905 million.
Note 15. Financial Information by Business Segments
Basis of Organization
The reportable segments were determined by Management in accordance with SFAS 131, "Disclosures About Segments of an Enterprise and Related Information" (SFAS 131). The separation of the electric segment data prior to August 1, 1999 into the Generation, Energy Resources and Trade and Transmission and Distribution segments of PSE&G's business was based on estimates and allocations.
Generation
This segment earns revenue through the sale of its energy and capacity. This segment consists of PSE&G's and Power's generation operations. Effective with the transfer of PSE&G's generation-related assets in August 2000, PSE&G has no further operations in this segment.
Trading
This segment markets electricity, capacity, ancillary services and natural gas products on a wholesale basis throughout the Eastern and Midwestern United States.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Transmission and Distribution (T&D)
This segment represents regulated utility services provided by PSE&G. The electric transmission and electric and gas distribution segment of PSE&G's business generates revenue from its tariffs under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from a variety of other activities such as sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services.
Resources
Resources earns revenues from its passive investments in leveraged leases, limited partnerships, leveraged buyout funds and marketable securities.
Global
Global earns revenues from its investment in and operation of projects in the generation and distribution of energy, both domestically and internationally.
Energy Technologies
Energy Technologies is an energy management company that constructs, operates and maintains HVAC systems for, and provides energy-related engineering, consulting and mechanical contracting services to, industrial and commercial customers in the Northeastern and Middle Atlantic United States.
Other
PSEG's other activities include amounts applicable to PSEG (parent corporation), Energy Holdings (parent corporation), EGDC and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. The net losses primarily relate to financing and certain administrative and general costs at the parent corporations.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Information related to the segments of PSEG's business is detailed below:
Energy Consolidated Generation Trading T&D Resources Global Technologies Other Total (Millions of Dollars) For the Year Ended December 31, 2000: Total Operating Revenues ...... $2,176 $104 $4,645 $207 $169 $417 $(870) $6,848 Depreciation and Amortization ...... 136 - 213 5 1 7 - 362 Interest Income ...... 1 - 21 2 1 4 3 32 Net Interest Charges ...... 196 - 205 79 53 3 38 574 Operating Income Before Income Taxes ...... 413 108 643 111 69 (14) (76) 1,254 Income Taxes ...... 164 44 265 40 13 (4) (32) 490 Equity in earnings of unconsolidated Subsidiaries ...... - - - 13 157 - - 170 Segment Net Income (Loss) ...... 249 64 378 71 58 (10) (46) 764 Gross Additions to Long-Lived Assets ...... 479 - 401 - 56 7 16 959
As of December 31, 2000: Total Assets ...... $3,280 $361 $15,267 $2,564 $2,271 $312 $(3,259) $20,796 Investments in equity method subsidiaries... - - - 239 1,846 - 24 2,109
For the Year Ended December 31, 1999: Total Operating Revenues ...... $2,618 $76 $3,146 $179 $142 $297 $-- $6,458 Depreciation and Amortization ...... 224 - 305 1 1 5 - 536 Interest Income ...... - - 12 1 - 2 - 15 Net Interest Charges ...... 112 - 275 46 48 - 9 490 Operating Income Before Income Taxes ...... 751 56 356 123 69 (9) (60) 1,286 Income Taxes ...... 268 23 219 50 24 (2) (19) 563 Equity in earnings of unconsolidated subsidiaries ...... - - - 78 129 - - 207 Segment Income before Extraordinary Item. 483 33 137 66 28 (7) (17) 723 Extraordinary Item (A) ...... (3,204) - 2,400 - - - - (804) Segment Net Income (Loss) ...... (2,721) 33 2,537 66 28 (7) (17) (81) Gross Additions to Long-Lived Assets ...... 92 - 387 - 1 8 91 579
As of December 31, 1999: Total Assets (A) ...... $3,055 $246 $11,171 $2,096 $1,715 $252 $480 $19,015 Investments in equity method subsidiaries... - - - 279 1,635 - 10 1,924
For the Year Ended December 31, 1998: Total Operating Revenues ...... $2,524 $50 $2,994 $ 145 $124 $171 $2 $6,010 Depreciation and Amortization ...... 381 - 268 2 1 2 6 660 Interest Income ...... - - 20 9 1 1 1 32 Net Interest Charges ...... 216 - 162 49 41 - 2 470 Operating Income Before Income Taxes ...... 352 41 613 86 31 (16) (35) 1,072 Income Taxes ...... 140 16 248 27 12 (5) (10) 428 Equity in earnings of unconsolidated subsidiaries ...... - - - 35 114 - - 149 Segment Net Income (Loss) ...... 212 25 365 56 7 (9) (12) 644 Gross Additions to Long-Lived Assets ...... 265 - 270 - 2 7 1 545
(A) See Note 2. Regulatory Issues and Accounting Impacts of Deregulation for discussion of the extraordinary charge recorded by the generation segment in 1999 and the related regulatory asset for securitization recorded by the T&D segment.
91 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Geographic information for PSEG is disclosed below. The foreign assets and operations noted below were made through Energy Holdings. PSE&G does not have foreign investments or operations.
Revenues (1) Identifiable Assets December 31, December 31, 2000 1999 1998 2000 1999 (Millions of Dollars) (Millions of Dollars) United States ...... $6,660 $6,309 $5,901 $17,816 $16,612 Foreign Countries (2) ...... 188 149 109 2,980 2,403 Total ...... $6,848 $6,458 $6,010 $20,796 $19,015
Identifiable assets in foreign countries include: Argentina $470 $356 Brazil (3) $295 $330 Chile and Peru $520 $520 Netherlands $815 $623 Other $880 $574
(1) Revenues are attributed to countries based on the locations of the investments. Global's revenue includes its share of the net income from joint ventures recorded under the equity method of accounting. (2) Total assets are net of foreign currency translation adjustment of $(225) million (pre-tax) as of December 31, 2000 and $(222) million (pre-tax) as of December 31, 1999. (3) Amount is net of foreign currency translation adjustment of $(167) million (pre-tax) as of December 31, 2000 and $(189) million (pre-tax) as of December 31, 1999.
Information related to Property, Plant and Equipment of PSE&G, Power and Services is detailed below:
December 31, 2000 1999 1998 (Millions of Dollars) Property, Plant and Equipment Electric Plant in Service: Fossil Production (A) ...... $1,840 $1,628 $2,802 Nuclear Production (A) ...... 130 110 6,246 Transm ission ...... 1,183 1,169 1,200 Distribution ...... 4,056 3,862 3,545 Other ...... 276 Total Electric Plant in Service ...... 7,209 6,769 14,069 Gas Plant in Service: Transmission ...... 69 69 69 Distribution ...... 2,978 2,819 2,608 Other ...... 130 131 170 Total Gas Plant in Service ...... 3,177 3,019 2,847 Common Plant in Service: Capital Leases ...... 55 59 59 General ...... 420 363 519 Total Common Plant in Service ...... 475 422 578 Total ...... $10,861 $10,210 $17,494
(A) See Note 2. Regulatory Issues and Accounting Impacts of Deregulation for discussion of the extraordinary charge recorded by the Generation segment and the related regulatory asset for securitization recorded by the T&D segment.
92 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note 16. Jointly Owned Facilities - Property, Plant and Equipment
PSE&G and Power have ownership interests in and are responsible for providing their share of the necessary financing for the following jointly owned facilities. All amounts reflect the share of PSE&G's and Power's jointly owned projects and the corresponding direct expenses are included in Consolidated Statements of Income as operating expenses.
Plant-December 31, 2000 Ownership Accumulated Interest Plant Depreciation (Millions of Dollars) Coal Generating 63 22.50% 198 Conemaugh ...... 122 47 Keystone ...... 22.84% Nuclear Generating 88 10 Peach Bottom ...... 50.00% 95.00% 606 508 Hope Creek ...... 645 544 Salem ...... 50.00% Various 5 Nuclear Support Facilities ...... 1 Pumped Storage Facilities 28 11 Yards Creek ...... 50.00% Various 97 33 Transmission Facilities ...... 13.91% 2 Merrill Creek Reservoir ...... 90.00% 16 15 Linden SNG Plant ...... Note 17. Selected Quarterly Data (Unaudited)
The information shown below, in the opinion of PSEG, includes all adjustments, consisting only of normal recurring accruals, necessary to a fair presentation of such amounts. Due to the seasonal nature of the utility business, quarterly amounts vary significantly during the year. Calendar Quarter Ended 31, March 31, June 30, September 30, December 31, 1999 2000 1999 2000 1999 2000 1999 2000 (Millions where Applicable) $1,482 $1,436 $1,481 $1,582 $1,991 $1,645 Operating Revenues ...... $1,894 $1,795 501 393 603 461 393 437 392 503 Operating Income ...... 210 133 188 142 181 142 221 Income before Extraordinary Item 270 - (790) - (14) Extraordinary Item ...... 209 134 188 (609) 143 206 N et Incom e ...... 270 142 Earnings per Share 0.98 0.61 (Basic and Diluted) ...... 1.25 0.85 0.66 (2.77) 0.66 0.95 Weighted Average Common Shares and Potential Dilutive Effect of Stock 215 219 215 218 Options Outstanding ...... 216 223 215 220
93 PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Concluded
Note 18. Accounting Matters
Effective January 1, 2001, PSEG and its subsidiaries have adopted Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS 133). Under the provisions of SFAS 133, PSEG and its subsidiaries records the fair values of derivatives held, as derivative assets or liabilities. The changes in the market value of the effective portion of derivatives qualifying as cash flow hedges are recorded, net of tax, in Other Comprehensive Income. The changes in the market value of the ineffective portion will be recorded in Net Income. The fair value of derivatives utilized by PSEG's regulated subsidiary, PSE&G, are recoverable through regulated rates and will be recorded as a regulatory asset or liability. Changes in the fair value of derivatives not qualifying for hedge accounting are recorded in Net Income. PSEG and its subsidiaries have not utilized any derivatives for fair value hedging purposes.
The fair value of the derivative instruments is determined by reference to quoted market prices, listed contracts, published quotations or quotations from counterparties. In the absence thereof, the company utilizes mathematical models based on current and historical data.
The adoption of SFAS 133 will not have a material adverse impact on net income or other comprehensive income for the financial statements of PSEG and its subsidiaries.
Note 19. Subsequent Events
On January 31, 2001, PSE&G Transition Funding LLC issued $2.525 billion of securitization bonds and remitted such proceeds to PSE&G in consideration for PSE&G's property right to the STC charged to PSE&G's customers. PSE&G used the proceeds from the sale of the property right to repay short-term debt, return capital to PSEG, make short term investments and make several loans to PSEG pending further PSE&G debt reduction. PSEG, in turn, repaid a portion of its short-term debt and contributed capital and made short-term loans to Power. Power repaid the $2.786 billion promissory note to PSE&G issued in payment for the generation assets transferred from PSE&G in 2000.
Under the servicing agreement entered into by the PSE&G Transition Funding LLC and PSE&G on January 31, 2001, PSE&G, as servicer, is required to manage and administer the BTP of PSE&G Transition Funding LLC and to collect the TBC on behalf of PSE&G Transition Funding LLC. PSE&G Transition Funding LLC will pay an annual servicing fee to PSE&G equal to 0.05% of the initial balance of securitization bonds outstanding. The servicing fee will also be recovered through the TBC.
94 PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSE&G
Except as modified below, the Notes to Consolidated Financial Statements of PSEG are incorporated herein by reference insofar as they relate to PSE&G and its subsidiaries:
Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies Note 2. Regulatory Issues Note 3. Regulatory Assets and Liabilities Note 4. Long-Term Investments Note 5. Leasing Activities-As Lessee Note 6. Schedule of Consolidated Capital Stock and Other Securities Note 7. Schedule of Consolidated Debt Note 8. Financial Instruments and Risk Management Note 9. Cash and Cash Equivalents Note 10. Commitments and Contingent Liabilities Note 11. PSE&G Nuclear Decommissioning Note 12. Income Taxes Note 13. Pension, Other Postretirement Benefit and Savings Plans Note 14. Stock Options, Stock Purchase Plan and Stock Repurchase Program Note 15. Financial Information by Business Segments Note 16. Jointly Owned Facilities-Property, Plant and Equipment Note 18. Accounting Matters Note 19. Subsequent Events
Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies
PSEG owns all of PSE&G's common stock (without nominal or par value). Of the 150,000,000 authorized shares of common stock at December 31, 2000 and 1999, there were 132,450,344 shares outstanding, with an aggregate book value of $2.6 billion. The Consolidated Financial Statements include the accounts of PSE&G and its subsidiaries. PSE&G and its subsidiaries consolidate those entities in which they have a controlling interest.
95 PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note 12. Income Taxes
A reconciliation of reported Net Income with pretax income and of income tax expense with the amount computed by multiplying pretax income by the statutory Federal income tax rate of 35% is as follows:
2000 1999 1998 (Millions of Dollars) Net Income (Loss) ...... $587 $(151) $602 Extraordinary Item (Net of Tax of $345) ...... -- 804 Net Income before Extraordinary Item ...... 587 653 602 Income taxes: Operating income: Federal - Current ...... 261 425 342 Deferred (A) ...... 50 (1) (24) (11) IT C ...... (i) (20) Total Federal ...... 310 413 298 State - Current ...... 150 109 118 Deferred (A) ...... (53) (12) (12) Total State ...... 97 97 106 Total included in operating income ...... 407 510 404
Pretax income ...... $994 $1,163 $1,006
Reconciliation between total income tax provisions and tax computed at the statutory tax rate on pretax income:
2000 1999 1998 (Millions of Dollars) Tax com puted at the statutory rate ...... $348 $407 $352 Increase (decrease) attributable to flow through of certain tax adjustments: Depreciation ...... (15) 35 23 Am ortization of investm ent tax credits ...... (1) (I1) (20) N ew Jersey Corporate Business Tax ...... 58 68 59 O th er ...... 17 11 (10) Subtotal ...... 59 103 52 Total incom e tax provisions ...... $407 $510 $404 Effective incom e tax rate ...... 40.9% 43.9% 40.2%
(A) The provision for deferred income taxes represents the tax effects of the following items:
2000 1999 1998 (Millions of Dollars) Deferred Credits: A dditional tax depreciation and am ortization ...... $42 $18 $(28) Conservation Costs ...... 29 29 36 Deferred Fuel Costs- net ...... (19) (60) Pension Cost ...... (19) (34) 26 New Jersey Corporate Business Tax ...... (34) (8) (8) Environm ental Cleanup Costs ...... 11 5 2 M arket Transition Charge ...... (38) Other ...... 6 (4) (4) T o ta l ...... $(3) $(13) $(36)
96 PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
SFAS 109
The following is an analysis of deferred income taxes:
December 31, 2000 1999 Deferred Income Taxes (Millions of Dollars) Assets: Current (net) ...... $23 $33 Non-current: Unrecovered Investment Tax Credits ...... 20 23 Deferred Electric Energy & Gas Costs ...... 17 18 Perform ance Incentive Plan ...... 7 7 N ew Jersey Corporate Business Tax ...... 396 493 Vacation Pay ...... 6 6 M arket Transition Charge ...... 38 Total Non-current ...... 484 547 Total Assets ...... 507 580 Liabilities: Non-current: Plant Related Item s ...... 1,219 628 Future Stranded Cost Recovery ...... 1,657 1,657 Conservation Costs ...... 124 95 Unam ortized Debt Expense ...... 35 39 Taxes Recoverable Through Future Rates (Net) ...... 90 87 Other ...... 1 7 Total Non-current ...... 3,126 2,513 Total Liabilities ...... 3,126 2,513 Summary-Deferred Income Taxes N et Current A ssets ...... 23 33 N et Non-current Liability ...... 2,642 1,966 Total ...... $2,619 $1,933
The balance of Federal income tax payable by (receivable from) PSE&G to PSEG was $(12) million and $19 million as of December 31, 2000 and December 31, 1999, respectively.
97 PUBLIC SERVICE ELECTRIC AND GAS COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - Concluded
Note 17. Selected Quarterly Data (Unaudited)
The information shown below, in the opinion of PSE&G, includes all adjustments, consisting only of normal recurring accruals, necessary to a fair presentation of such amounts. Due to the seasonal nature of the utility business, quarterly amounts vary significantly during the year.
Calendar Quarter Ended March 31, June 30, September 30, December 31, 2000 1999 2000 1999 2000 1999 2000 1999 (Millions of Dollars) Operating Revenues ...... $1,679 $1,666 $1,318 $1,297 $1,255 $1,433 $1,636 $1,444 Operating Income ...... 522 406 361 369 214 463 171 360 Income before Extraordinary Item 250 172 152 157 99 205 86 119 Extraordinary Item ...... - - - (790) - (14) - Net Income ...... 250 172 152 (633) 99 191 86 119 Earnings Available to PSEG ...... 248 169 150 (635) 97 189 83 117
Note 20. Related-Party Transactions
PSE&G and Power
PSE&G's transfer of its electric generating assets was in exchange for a promissory note from Power in an amount equal to the total purchase price of $2.786 billion. Interest on the note is payable at an annual rate of 14.23%, which represents PSE&G's weighted average cost of capital. For the period from August 21, 2000 to December 31, 2000, Power recorded interest expense of approximately $143 million relating to the promissory note.
Effective with the transfer, Power charges PSE&G for MTC and the energy and capacity provided to meet PSE&G's BGS requirements. Through December 31, 2000, Power has charged PSE&G approximately $804 million for MTC and BGS. As of December 31, 2000, PSE&G's payable to Power relating to these costs was approximately $159 million. Also through December 31, 2000, PSE&G sold energy and capacity to Power at the market price of approximately $67 million, which PSE&G purchased under various non-utility generation (NUG) contracts at a costs above market prices. As of December 31, 2000, Power's payable to PSE&G relating to these purchases was approximately $17 million. PSE&G, as a result of the Final Order, has established an NTC to recover the above market costs related to these NUG contracts. The difference between PSE&G's cost and their recovery of costs through the NTC and sales to Power, which are at the locational marginal price (LMP) for energy and at wholesale market prices for capacity, is deferred as a regulatory asset (see Note 3. Regulatory Assets and Liabilities). Energy Holdings and PSE&G
Approximately 90% of the electricity generated by the Eagle Point Power Plant, a 50% owned equity investment of Global, is sold to PSE&G under a 25-year power purchase contract terminating in May 2016. Global's share of partnership revenues received from PSE&G represented approximately $68 million, $55 million and $54 million for the years ended December 31, 2000, 1999 and 1998, respectively. Subsequent to December 31, 2000, Global retired from its interest in the Eagle Point Cogeneration Partnership in exchange for a series of payments expected to total up to $290 million, to be received over the next five years, subject to certain contingencies.
98 FINANCIAL STATEMENT RESPONSIBILITY - PSEG
Management of PSEG is responsible for the preparation, integrity and objectivity of the consolidated financial statements and related notes of PSEG. The consolidated financial statements and related notes are prepared in accordance with generally accepted accounting principles. The financial statements reflect estimates based upon the judgment of management where appropriate. Management believes that the consolidated financial statements and related notes present fairly PSEG's financial position and results of operations. Information in other parts of this Annual Report is also the responsibility of management and is consistent with these consolidated financial statements and related notes.
The firm of Deloitte & Touche LLP, independent auditors, is engaged to audit PSEG's consolidated financial statements and related notes and issue a report thereon. Deloitte & Touche's audit is conducted in accordance with generally accepted auditing standards. Management has made available to Deloitte & Touche all the corporation's financial records and related data, as well as the minutes of directors' meetings. Furthermore, management believes that all representations made to Deloitte & Touche during its audit were valid and appropriate.
Management has established and maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded, and that transactions are executed in accordance with management's authorization and recorded properly for the prevention and detection of fraudulent financial reporting, so as to maintain the integrity and reliability of the financial statements. The system is designed to permit preparation of consolidated financial statements and related notes in accordance with generally accepted accounting principles. The concept of reasonable assurance recognizes that the costs of a system of internal accounting controls should not exceed the related benefits. Management believes the effectiveness of this system is enhanced by an ongoing program of continuous and selective training of employees. In addition, management has communicated to all employees its policies on business conduct, safeguarding assets and internal controls.
The Internal Auditing Department of Services conducts audits and appraisals of accounting and other operations of PSEG and its subsidiaries and evaluates the effectiveness of cost and other controls and, where appropriate, recommends to management improvements thereto. Management has considered the internal auditors' and Deloitte & Touche's recommendations concerning the corporation's system of internal accounting controls and has taken actions that, in its opinion, are cost-effective in the circumstances to respond appropriately to these recommendations. Management believes that, as of December 31, 2000, the corporation's system of internal accounting controls was adequate to accomplish the objectives discussed herein.
The Board of Directors of PSEG carries out its responsibility of financial overview through its Audit Committee, which presently consists of six directors who are not employees of PSEG or any of its affiliates. The Audit Committee meets periodically with management as well as with representatives of the internal auditors and Deloitte & Touche. The Audit Committee reviews the work of each to ensure that its respective responsibilities are being carried out and discusses related matters. Both the internal auditors and Deloitte & Touche periodically meet alone with the Audit Committee and have free access to the Audit Committee and its individual members at all times.
E. JAMES FERLAND ROBERT C. MURRAY Chairman of the Board, Vice President and President and Chief Executive Officer Chief Financial Officer
PATRICIA A. RADO Vice President and Controller (Principal Accounting Officer)
February 16, 2001
99 FINANCIAL STATEMENT RESPONSIBILITY - PSE&G
Management of PSE&G is responsible for the preparation, integrity and objectivity of the consolidated financial statements and related notes of PSE&G. The consolidated financial statements and related notes are prepared in accordance with generally accepted accounting principles. The financial statements reflect estimates based upon the judgment of management where appropriate. Management believes that the consolidated financial statements and related notes present fairly PSE&G's financial position and results of operations. Information in other parts of this Annual Report is also the responsibility of management and is consistent with these consolidated financial statements and related notes.
The firm of Deloitte & Touche LLP, independent auditors, is engaged to audit PSE&G's consolidated financial statements and related notes and issue a report thereon. Deloitte & Touche's audit is conducted in accordance with generally accepted auditing standards. Management has made available to Deloitte & Touche all the corporation's financial records and related data, as well as the minutes of directors' meetings. Furthermore, management believes that all representations made to Deloitte & Touche during its audit were valid and appropriate.
Management has established and maintains a system of internal accounting controls to provide reasonable assurance that assets are safeguarded, and that transactions are executed in accordance with management's authorization and recorded properly for the prevention and detection of fraudulent financial reporting, so as to maintain the integrity and reliability of the financial statements. The system is designed to permit preparation of consolidated financial statements and related notes in accordance with generally accepted accounting principles. The concept of reasonable assurance recognizes that the costs of a system of internal accounting controls should not exceed the related benefits. Management believes the effectiveness of this system is enhanced by an ongoing program of continuous and selective training of employees. In addition, management has communicated to all employees its policies on business conduct, safeguarding assets and internal controls.
The Internal Auditing Department of Services conducts audits and appraisals of accounting and other operations and evaluates the effectiveness of cost and other controls and, where appropriate, recommends to management improvements thereto. Management has considered the internal auditors' and Deloitte & Touche's recommendations concerning the corporation's system of internal accounting controls and has taken actions that are cost-effective in the circumstances to respond appropriately to these recommendations. Management believes that, as of December 31, 2000, the corporation's system of internal accounting controls was adequate to accomplish the objectives discussed herein.
The Board of Directors carries out its responsibility of financial overview through the Audit Committee of PSEG, which presently consists of six directors who are not employees of PSE&G or any of its affiliates. The PSEG Audit Committee meets periodically with management as well as with representatives of the internal auditors and Deloitte & Touche. The Audit Committee reviews the work of each to ensure that their respective responsibilities are being carried out and discusses related matters. Both the internal auditors and Deloitte & Touche, periodically meet alone with the Audit Committee and have free access to the Audit Committee and its individual members at all times.
E. JAMES FERLAND ROBERT E. BUSCH Chairman of the Board and Senior Vice President Chief Executive Officer and Chief Financial Officer
PATRICIA A. RADO Vice President and Controller (Principal Accounting Officer)
February 16, 2001
100 INDEPENDENT AUDITORS' REPORT
To the Stockholders and Board of Directors of Public Service Enterprise Group Incorporated:
We have audited the consolidated balance sheets of Public Service Enterprise Group Incorporated and its subsidiaries (the "Company") as of December 31, 2000 and 1999, and the related consolidated statements of income, common stockholders' equity and cash flows for each of the three years in the period ended December 31, 2000. Our audits also included the consolidated financial statement schedule listed in the Index in Item 14(B)(a). These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and consolidated financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.
We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheets of the Company as of December 31, 1998, 1997, and 1996, and the related consolidated statements of income, common stockholders' equity and cash flows for the years ended December 31, 1997 and 1996 (none of which are presented herein) and we expressed unqualified opinions on those consolidated financial statements.
In our opinion, the information set forth in the Selected Financial Data for each of the five years in the period ended December 31, 2000, presented in Item 6, is fairly stated in all material respects, in relation to the consolidated financial statements from which it has been derived.
DELOITTE & TOUCHE LLP
Parsippany, New Jersey February 16, 2001
101 INDEPENDENT AUDITORS' REPORT
To the Board of Directors of Public Service Electric and Gas Company:
We have audited the consolidated balance sheets of Public Service Electric and Gas Company and its subsidiaries (the "Company") as of December 31, 2000 and 1999, and the related consolidated statements of income, common stockholder's equity and cash flows for each of the three years in the period ended December 31, 2000. Our audits also included the consolidated financial statement schedule listed in the Index in Item 14(B)(b). These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements and consolidated financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2000 and 1999, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2000 in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.
We have previously audited, in accordance with auditing standards generally accepted in the United States of America, the consolidated balance sheets of the Company as of December 31, 1998, 1997, and 1996, and the related consolidated statements of income, common stockholder's equity and cash flows for the years ended December 31, 1997 and 1996 (none of which are presented herein) and we expressed unqualified opinions on those consolidated financial statements.
In our opinion, the information set forth in the Selected Financial Data for each of the five years in the period ended December 31, 2000, presented in Item 6, is fairly stated in all material respects, in relation to the consolidated financial statements from which it has been derived.
DELOITTE & TOUCHE LLP
Parsippany, New Jersey February 16, 2001
102 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
PSEG and PSE&G: None.
103 PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
Directors of the Registrants
PSEG
The information required by Item 10 of Form 10-K with respect to present directors who are nominees for election as directors at PSEG's Annual Meeting of Stockholders to be held on April 17, 2001, and directors whose terms will continue beyond the meeting, is set forth under the heading "Election of Directors" in PSEG's definitive Proxy Statement for such Annual Meeting of Stockholders, which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 12, 2001 and which information set forth under said heading is incorporated herein by this reference thereto. PSE&G
There is shown as to each present director information as to the period of service as a director of PSE&G, age as of April 17, 2001, present committee memberships, business experience during the last five years and other present directorships. For discussion of certain litigation involving the directors of PSE&G, except Forrest J. Remick and Conrad K. Harper, see Part I-Business, Item 3-Legal Proceedings.
E. JAMES FERLAND has been a director since 1986. Age 59. Chairman of the Board, President and Chief Executive Officer of PSEG since July 1986, Chairman of the Board and Chief Executive Officer of PSE&G since September 1991 and Chairman of the Board and Chief Executive Officer of Energy Holdings since June 1989. Chairman of the Board and Chief Executive Officer of Power since June 1999. Director of Foster Wheeler Corporation and The HSB Group, Inc.
ALBERT R. GAMPER, JR. has been a director since December 2000. Age 58. Director of PSEG. Has been Chairman of the Board, President and Chief Executive Officer of The CIT Group, Inc., Livingston, New Jersey (commercial finance company), since January 2000. Was President and Chief Executive Officer of The CIT Group, Inc. from December 1989 to December 2000. Director of The CIT Group, Inc.
CONRAD K. HARPER has been a director since May 1997. Age 60. Director of PSEG. Has been a partner in the law firm of Simpson Thacher & Bartlett, New York, New York since October 1996 and from 1974 to May 1993. Was Legal Adviser, U.S. Department of State from May 1993 to June 1996. Director of New York Life Insurance Company.
IRWIN LERNER has been a director since 1993. Age 70. Was previously a director from 1981 to February 1988. Director of PSEG. Until retirement was Chairman, Board of Directors of Hofflnann-La Roche Inc., Nutley, New Jersey (prescription pharmaceuticals, vitamins and fine chemicals, and diagnostic products and services) from January 1993 to September 1993 and President and Chief Executive Officer from 1980 to December 1992. Director of Humana Inc., AXYS Pharmaceuticals, Inc., Medarex, Inc., VI Technologies, Inc. and Covance Inc.
MARILYN M. PFALTZ has been a director since 1998 and was a Director of Energy Holdings from 1989 to 1998. Age 68. Director of PSEG. Has been a partner of P and R Associates, Summit, New Jersey (communication specialists), since 1968. Director of AAA National Association, AAA Investment Company, AAA Life Re Ltd. and Beacon Trust Company.
FORREST J. REMICK has been a director since 1995. Age 70. Director of PSEG. Has been an engineering consultant since 1994. Was Commissioner, U.S. Nuclear Regulatory Commission, from December 1989 to June 1994. Was Associate Vice President-Research and Professor of Nuclear Engineering at Pennsylvania State University, from 1985 to 1989.
104 Executive Officers of the Registrants
The following table sets forth certain information concerning the executive officers of PSEG and PSE&G.
AGE EFFECTIVE DATE FIRST ELECTED NAME DECEMBER 31,2000 OFFICE TO PRESENT POSITION E. James Ferland 58 Chairman of the Board, President and July 1986 to present Chief Executive Officer (PSEG) Chairman of the Board and Chief July 1986 to present Executive Officer (PSE&G) Chairman of the Board and Chief June 1989 to present Executive Officer (Energy Holdings) Chairman of the Board and Chief June 1999 to present Executive Officer (Power) Chairman of the Board, President and November 1999 to present Chief Executive Officer (Services) Robert C. Murray 55 Vice President and Chief Financial January 1992 to present Officer (PSEG) Executive Vice President-Finance November 1999 to present (Services) Executive Vice President-Finance June 1997 to June 2000 (PSE&G) Senior Vice President and Chief January 1992 to June 1997 Financial Officer (PSE&G) Robert J. Dougherty, Jr. 49 President and Chief Operating Officer January 1997 to present (Energy Holdings) President (Enterprise Ventures and February 1995 to December 1996 Services Corporation) Alfred C. Koeppe 54 President and Chief Operating February 2000 to present Officer (PSE&G) Senior Vice President-Corporate October 1996 to February 2000 Services and External Affairs (PSE&G) Senior Vice President-External October 1995 to October 1996 Affairs (PSE&G) R. Edwin Selover 55 Vice President and General Counsel April 1988 to present (PSEG) Senior Vice President and General January 1988 to present Counsel (PSE&G)
Senior Vice President and General November 1999 to present Counsel (Services) Robert E. Busch 54 Senior Vice President and March 1998 to present Chief Financial Officer (PSE&G)
Senior Vice President-Finance November 1999 to present (Services) Frank Cassidy 54 President (Power) July 1999 to present President (Energy Technologies) November 1996 to June 1999 Senior Vice President-Fossil February 1995 to November 1996 Generation (PSE&G)
105 AGE EFFECTIVE DATE FIRST ELECTED NAME DECEMBER 31,2000 OFFICE TO PRESENT POSITION Patricia A. Rado 58 Vice President and Controller April 1993 to present (PSEG) Vice President and Controller April 1993 to present (PSE&G)
Vice President and Controller June 1999 to present (Power) Vice President and Controller November 1999 to present (Services)
ITEM 11. EXECUTIVE COMPENSATION
PSEG
The information required by Item 11 of Form 10-K is set forth under the heading "Executive Compensation" in PSEG's definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 17, 2001 which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 5, 2000 and such information set forth under such heading is incorporated herein by this reference thereto. PSE&G
Information regarding the compensation of the Chief Executive Officer and the four most highly compensated executive officers of PSE&G as of December 31, 2000 is set forth below. Amounts shown were paid or awarded for all services rendered to PSEG and its subsidiaries and affiliates including PSE&G.
Long Term Compensation Annual Compensation Awards Payouts Bonus/Annual LTIP All Other Incentive Restricted Options Payouts Compensation Name and Principal Position Year Salary $ Award ($)(1) Stock ($) (#) (2) ($) (3) ($) (4) E. James Ferland 2000 890,000 1,001,300 0 300,000 361,440 59,037 Chairman of the Board and Chief 1999 815,000 733,500 0 215,000 304,720 29,292 Executive Officer of PSE&G 1998 762,070 621,400 5,184,375 (5) 150,000 92,684 28,647 Alfred C. Koeppe 2000 340,000 255,000 0 310,000 90,360 6,805 President and Chief Operating 1999 290,000 152,300 0 75,000 75,008 6,404 Officer of PSE&G 1998 268,967 141,800 0 25,000 15,980 6,403 R. Edwin Selover 2000 325,000 170,600 0 40,000 81,324 17,280 Senior Vice President and General 1999 310,000 162,800 0 35,000 65,632 12,828 Counsel of PSE&G 1998 293,871 154,900 0 25,000 22,372 19,210 Robert E. Busch 2000 300,000 157,500 0 40,000 0 6,805 Senior Vice President and 1999 275,000 144,400 0 26,500 0 6,402 Chief Financial Officer of PSE&G 1998 197,319 84,400 0 16,500 0 3,228 Patricia A. Rado 2000 200,000 90,000 0 15,000 0 7,289 Vice President and Controller 1999 192,000 72,000 0 15,000 0 6,609 of PSE&G 1998 184,292 69,400 0 8,000 0 6,552
(1) Amount awarded in given year was earned under Management Incentive Compensation Plan (MICP) and determined in following year based on individual performance and financial and operating performance of PSEG and PSE&G, including comparison to other companies.
(2) All grants of options to purchase shares of PSEG Common Stock were non-qualified options made under the 1989 Long-Term Incentive Plan (1989 LTIP) or the 2001 Long-Term Incentive Plan (2001 LTIP). All
106 options granted were non-tandem. Non-tandem grants are made without performance units and dividend equivalents.
(3) Amount paid in proportion to options exercised, if any, based on value of previously granted performance units and dividend equivalents under the 1989 LTIP, each as measured during three-year period ending the year prior to the year in which payment is made. Under the 1989 LTIP, tandem grants are made with an equal number of performance units and dividend equivalents which may provide cash payments, dependent upon future financial performance of PSEG in comparison to other companies which may provide cash payments, dependent upon future financial performance of PSEG in comparison to other companies and dividend payments by PSEG, to assist recipients in exercising options granted. The tandem grant is made at the beginning of a three-year performance period and cash payment of the value of such performance units and dividend equivalents is made following such period in proportion to the options, if any, exercised at such time.
(4) Includes employer contribution to Thrift and Tax-Deferred Savings Plan and value of 5% discount on phantom stock dividend reinvestment under MICP:
Ferland Koeppe Selover Busch Rado Thrift MICP Thrift MICP Thrift MICP Thrift MICP Thrift MICP Year (S) ($) ($) (S) ($) ($) ($) (S) (S) ($) 2000 5,102 0 6,805 0 4,747 0 6,805 0 6,422 0 1999 4,801 0 6,404 0 4,802 0 6,402 0 6,390 0 1998 4,801 383 6.403 125 4,806 112 3,228 0 6,360 59
In addition, 2000, 1999 and 1998 amounts include for Mr. Ferland, $53,935, $24,491 and $23,463; for Mr. Selover $12,533, $8,026, and $14,292; and for Mrs. Rado $867, $219 and $133, respectively, representing earnings credited on compensation deferred under PSE&G's Deferred Compensation Plan in excess of 120% of the applicable Federal long-term interest rate as prescribed under Section 1274(d) of the Internal Revenue Code. Prior to January 1, 2000, under PSE&G's Deferred Compensation Plan, interest is paid at prime rate plus 1/2%, adjusted quarterly. Effective January 1, 2000, the Plan was amended to permit participants to select from among four additional investment options for compensation that is deferred.
(5) Value as of original grant date, based on the closing price on the New York Stock Exchange on June 16, 1998, with respect to an award to Mr. Ferland of 150,000 shares of restricted stock, of which 60,000 shares vest in 2002; 20,000 shares vest in 2003; 30,000 shares vest in 2004 and 40,000 shares vest in 2005. Dividends on the entire grant are paid in cash from the date of grant.
OPTION GRANTS IN LAST FISCAL YEAR (2000) Number of % of Total Secu rities Options Underlying Granted to Exercise or Grant Date Options Employees in Base Price Expiration Present Value Name Granted Fiscal Year ($/Sh) Date ($) (2) E. James Ferland 300,000(l) 10.9 46.0625 12/19/10 2,418,000 Alfred C. Koeppe 60,000 (1) 2.2 46.0625 12/19/10 483,600 250,000(2) 9.1 44.0625 10/17/10 1,700,000 R. Edwin Selover 40,000(1) 1.5 46.0625 12/19/10 322,400 Robert E. Busch 40,000(1) 1.5 46.0625 12/19/10 322,400 Patricia A. Rado 15,000 (1) 0.5 46.0625 12/19/10 120,900
107 (1) Granted under LTIP not in tandem with performance units and dividend equivalents, with exercisability commencing December 19, 2001, December 19, 2002 and December 19, 2003, respectively, with respect to one-third of the options at each such date.
(2) Granted under 1989 LTIP not in tandem with performance units and dividend equivalents, with exercisability commencing October 17, 2001, October 17, 2002, October 17, 2003, October 17, 2004 and October 17, 2005, respectively with respect to one-fifth of the options at each such date.
(3) Determined using the Black-Scholes model, incorporating the following material assumptions and adjustments: (a) exercise prices of $46.0625 and $44.0625, equal to the fair market value of the underlying PSEG Common Stock on the respective dates of grant; (b) an option term of ten years on all grants; (c) interest rates of 6.03% and 5.74% that represent the interest rates on U.S. Treasury securities on the respective dates of grant with a maturity date corresponding to that of the option terms; (d) volatility of 23.18% and 22.72% calculated using daily PSEG Common Stock prices for the one-year period prior to the grant dates; (e) dividend yields of 4.69% and 4.90% and (f) reductions of approximately 7.79% and 11.38% to reflect the probability of forfeiture due to termination prior to vesting, and approximately 9.25% and 8.21% to reflect the probability of a shortened option term due to termination of employment prior to the option expiration dates. Actual values which may be realized, if any, upon any exercise of such options, will be based on the market price of PSEG Common Stock at the time of any such exercise and thus are dependent upon future performance of PSEG Common Stock. There is no assurance that any such value realized will be at or near the value estimated by the Black-Scholes model utilized.
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR (2000) 1r AND FISCAL YEAR END OPTION VALUES (12/31/00) Value of Unexercised Number of Unexercised In-the-Money Options Options at FY-End (#) (1) At FY-End ($) (3) Shares Acquired Value on Exercise Realized Exercisable Unexercisable Exercisable Unexercisable Name (#)(1) ($)(2) (#) (#) ($) ($) E. James Ferland 8,000 58,000 271,667 503,333 3,948,339 3,646,662 Alfred C. Koeppe 2,000 14,125 51,667 370,833 733,336 2,194,632 R. Edwin Selover 1,800 8,325 38,334 74,166 526,675 589,419 Robert E. Busch 0 0 18,334 63,166 222,302 431,198 Patricia A. Rado 400 2,675 10,333 28,267 127,164 229,711
(1) Does not reflect any options granted and/or exercised after year-end (12/31/00). The net effect of any such grants and exercises is reflected in the table appearing under Security Ownership of Certain Beneficial Owners and Management.
(2) Represents difference between exercise price and market price of PSEG Common Stock on date of exercise.
(3) Represents difference between market price of PSEG Common Stock and the respective exercise prices of the options at fiscal year end (12/31/00). Such amounts may not necessarily be realized. Actual values which may be realized, if any, upon any exercise of such options will be based on the market price of PSEG Common Stock at the time of any such exercise and thus are dependent upon future performance of PSEG Common Stock.
Employment Contracts and Arrangements
PSEG has entered into an employment agreement dated as of June 16, 1998 with Mr. Ferland covering his employment as Chief Executive Officer through March 31, 2005. Under the Agreement, Mr. Ferland has agreed not to retire prior to March 31, 2002, but may retire thereafter. The Agreement provides that Mr. Ferland will be re nominated for election as a Director during his employment under the Agreement. The Agreement provides that Mr. Ferland's base salary, target annual incentive bonus and long term incentive bonus will be determined based on compensation practices for CEO's of similar companies and that his annual salary will not be reduced during the 108 term of the Agreement. The Agreement also provided for an award to him of 150,000 shares of restricted PSEG Stock, of which 60,000 shares vest in 2002; 20,000 shares vest in 2003; 30,000 shares vest in 2004 and 40,000 shares vest in 2005. Any non-vested shares are forfeited upon his retirement unless the Board of Directors, in its discretion, determines to waive the forfeiture. The Agreement provides for the granting of 22 years of pension credit for Mr. Ferland's prior service, which was awarded at the time of his initial employment. The Agreement further provides that if Mr. Ferland is terminated without "Cause" or resigns for "Good Reason" (as those terms are defined in the Agreement) during the term of the Agreement, the entire restricted stock award immediately vests, he will be paid a benefit of two times base salary and target bonus and his welfare benefits will be continued for two years unless he is sooner employed. In the event such a termination occurs after a "Change in Control" (also as defined in the Agreement), the payment to Mr. Ferland becomes three times the sum of salary and target bonus, continuation of welfare benefits for three years unless sooner reemployed, payment of the net present value providing three years additional service under PSEG's retirement plans, and a gross-up for excise taxes on any termination payments due under the Internal Revenue Code. The Agreement provides that Mr. Ferland is prohibited from competing with or recruiting employees from PSEG or its subsidiaries of affiliates for two years after termination of employment. Violation of these provisions requires a forfeiture of a portion of the restricted stock grant and certain other benefits.
PSE&G has entered into an employment agreement with Mr. Koeppe dated as of October 17, 2000, covering his employment through October 16, 2005. The Agreement provides that his base salary, target annual incentive bonus and long-term incentive bonus will be determined based on compensation practices of similar companies and that his annual salary will not be reduced during the term of the Agreement, and annually awards to him 50,000 options on PSEG Common Stock from 2001 through 2005 which vest each October 17 and expire on October 17, 2010. The Agreement further provides that if he is terminated without "Cause" or resigns for "Good Reason" (as those terms are defined in each Agreement) during the term of the Agreement, the entire option award becomes vested. He will be paid a benefit of two times base salary and target bonus, and his welfare benefits will be continued for two years unless he is sooner employed. In the event such a termination occurs after a "Charge in Control" (also as defined in the Agreement), the payment becomes three times the sum of salary and target bonus, continuation of welfare benefits for three years unless sooner reemployed, payment of the net present value of providing three years additional service under PSE&G's retirement plans, and a gross-up for exercise taxes on any termination payments due under the Internal Revenue Code. The Agreement provides that he is prohibited for one year from competing with and for two years from recruiting employees from, PSEG or its subsidiaries or affiliates, after termination of employment. Violation of these provisions requires a forfeiture of certain benefits. Mr. Koeppe's Agreement also provides for the grant of additional years of credited service for retirement purposes in light of allied work experience of twenty-five years.
Compensation Committee Interlocks and InsiderParticipation
PSE&G does not have a compensation committee. Decisions regarding compensation of PSE&G's executive officers are made by the Organization and Compensation Committee of PSEG. Hence, during 2000 the PSE&G Board of Directors did not have, and no officer, employee or former officer of PSE&G participated in any deliberations of such Board, concerning executive officer compensation.
Compensation of Directorsand Certain Business Relationships
A director who is not an officer of PSEG or its subsidiaries and affiliates, including PSE&G, is paid an annual retainer of $22,000 and a fee of $1,200 for attendance at any Board or committee meeting, inspection trip, conference or other similar activity relating to PSEG or PSE&G. Each committee Chair receives an additional annual retainer of $3,000. Effective January 1, 2001, the annual retainer was increased to $30,000 and the Board of Committee meeting fees were increased to $1,500. Each of the directors of PSE&G is also a director of PSEG. No additional retainer is paid for service as a director of PSE&G. Fifty percent of the annual retainer is paid in PSEG Common Stock.
PSEG also maintains a Stock Plan for Outside Directors pursuant to which directors who are not employees of PSEG or its subsidiaries receive 600 shares of restricted stock for each year of service as a director. Such shares held by each non-employee director are included in the table in Item 12 below under the heading Security Ownership of Certain Beneficial Owners and Management.
109 The restrictions on the stock granted under the Stock Plan for Outside Directors provide that the shares are subject to forfeiture if the director leaves service at any time prior to the Annual Meeting of Stockholders following his or her 70th birthday. This restriction would be deemed to have been satisfied if the director's service were terminated after a "Change in Control" as defined in the Plan or if the director were to die in office. PSEG also has the ability to waive this restriction for good cause shown. Restricted stock may not be sold or otherwise transferred prior to the lapse of the restrictions. Dividends on shares held subject to restrictions are paid directly to the director, and the director has the right to vote the shares.
Compensation Pursuant to Pension Plans
The table below illustrates annual retirement benefits expressed in terms of single life annuities based on the average final compensation and service shown and retirement at age 65. A person's annual retirement benefit is based upon a percentage that is equal to years of credited service plus 30, but not more than 75%, times average final compensation at the earlier of retirement, attainment of age 65 or death. These amounts are reduced by Social Security benefits and certain retirement benefits from other employers. Pensions in the form of joint and survivor annuities are also available.
PENSION PLAN TABLE
Average Final Length of Service Compensation 30 Years 35 Years 40 Years 45 Year, $400,000 $240,000 $260,000 $280,000 $300,00C 500,000 300,000 325,000 350,000 375,00C 600,000 360,000 390,000 420,000 450,00C 700,000 420,000 455,000 490,000 525,00C 800,000 480,000 520,000 560,000 600,00C 900,000 540,000 585,000 630,000 675,00C 1,000,000 600,000 650,000 700,000 750,00C 1,100,000 660,000 715,000 770,000 825,00C 1,200,000 720,000 780,000 840,000 900,00C 1,300,000 780,000 845,000 910,000 975,00C 1,400,000 840,000 1,050,00C 900,000 910,000 980,000 1,500,000 975,000 1,050,000 1, 125,00C 1,500,000 1,125,000 Average final compensation, for purposes of retirement benefits of executive officers, is generally equivalent to the average of the aggregate of the salary and bonus amounts reported in the Summary Compensation Table above under 'Annual Compensation' for the five years preceding retirement, not to exceed 150% of the average annual salary for such five year period. Messrs. Ferland, Koeppe, Selover, Busch and Mrs. Rado will have accrued approximately 48, 46, 43, 34 and 29 years of credited service, respectively, as of age 65. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL
OWNERS AND MANAGEMENT PSEG
The information required by Item 12 of Form 10-K with respect to directors, executive officers and certain beneficial owners is set forth under the heading 'Security Ownership of Directors, Management and Certain Beneficial Owners' in PSEG's definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 17, 2001 which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 12, 2001 and such information set forth under such heading is incorporated herein by this reference thereto.
110 PSE&G
All of PSE&G's 132,450,344 outstanding shares of Common Stock are owned beneficially and of record by PSE&G's parent, PSEG, 80 Park Plaza, P.O. Box 1171, Newark, New Jersey.
The following table sets forth beneficial ownership of PSEG Common Stock, including options, by the directors and executive officers named below as of January 31, 2001. None of these amounts exceed 1% of the PSEG Common Stock outstanding at such date. No director or executive officer owns any PSE&G Preferred Stock of any class.
Amount and Nature of Name Beneficial Ownership Robert E. Busch ...... 81,617 (1) E. Jam es Ferland ...... 999,837 (2) C nbert R. Gamper, Jr...... 21,000 Aonrad K. Harper ...... 4302,776 430,37813,686 (3) IlfredwR. Koeppe ...... rwin Lemer ...... Marilyn M . Pfaltz ...... 10,621 Patricia A . Rado ...... 45,953 (4) Forrest J. R em ick ...... 4,627 R. Edw in Selover ...... 124,591 (5) A11 directors and executive officers as a group (10 persons) ...... 1,715,086 (6)
(1) Includes the equivalent of 117 shares held under PSEG Thrift and Tax-Deferred Savings Plan. Includes options to purchase 81,500 shares, 18,334 of which are currently exercisable.
(2) Includes the equivalent of 12,790 shares held under PSEG Thrift and Tax-Deferred Savings Plan. Includes options to purchase 775,000 shares, 271,667 of which are currently exercisable. Includes 150,000 shares of restricted stock, which vest as described in the Summary Compensation Table Note 5.
(3) Includes the equivalent of 2,278 shares held under PSEG Thrift and Tax-Deferred Savings Plan. Includes options to purchase 422,500 shares, 51,667 of which are currently exercisable.
(4) Includes the equivalent of 5,511 shares held under PSEG Thrift and Tax-Deferred Savings Plan. Includes options to purchase 38,600 shares, 10,333 of which are currently exercisable.
(5) Includes options to purchase 112,500 shares, 38,334 of which are currently exercisable.
(6) Includes the equivalent of 20,696 shares held under PSEG Thrift and Tax-Deferred Savings Plan. Includes options to purchase 1,430,100 shares, of which 390,335 are currently exercisable.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
PSEG
The information required by Item 13 of Form 10-K is set forth under the heading "Executive Compensation" in PSEG's definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 17, 2001, which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 12, 2001. Such information set forth under such heading is incorporated herein by this reference thereto. PSE&G
None.
III PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(A) Financial Statements:
a. PSEG Consolidated Statements of Income for the years ended December 31, 2000, 1999 and 1998 on page 50.
PSEG Consolidated Balance Sheets for the years ended December 31, 2000 and 1999 on pages 51 and 52.
PSEG Consolidated Statements of Cash Flows for the years ended December 31, 2000, 1999 and 1998 on page 53. PSEG Statements of Common Stockholders' Equity for the years ended December 31, 2000, 1999 and 1998 on page 54.
PSEG Notes to Consolidated Financial Statements on pages 60 through 94.
b. PSE&G Consolidated Statements of Income for the years ended December 31, 2000, 1999 and 1998 on page 55.
PSE&G Consolidated Balance Sheets for the years ended December 31, 2000 and 1999 on pages 56 and 57.
PSE&G Consolidated Statements of Cash Flows for the years ended December 31, 2000, 1999 and 1998 on page 58.
PSE&G Statements of Common Stockholder's Equity for the years ended December 31, 2000, 1999 and 1998 on page 59.
PSE&G Notes to Consolidated Financial Statements on pages 95 through 98.
(B) The following documents are filed as a part of this report:
a. PSEG Financial Statement Schedules:
Schedule II-Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2000 (page 114).
b. PSE&G Financial Statement Schedules:
Schedule II-Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2000 (page 114).
Schedules other than those listed above are omitted for the reason that they are not required or are not applicable, or the required information is shown in the consolidated financial statements or notes thereto.
112 The following exhibits are filed herewith:
(1) PSEG: Exhibit 10a(7): 2001 Long-Term Incentive Plan Exhibit 10a(8): Restated and Amended Management Incentive Compensation Plan Exhibit 12: Computation of Ratios of Earnings to Fixed Charges Exhibit 21: Subsidiaries of Registrant Exhibit 23: Independent Auditors' Consent
(See Exhibit Index on pages 116 through 124.)
(2) PSE&G: Exhibit 10a(7): 2001 Long-Term Incentive Plan Exhibit 10a(8): Restated and Amended Management Incentive Compensation Plan Exhibit 12(a): Computation of Ratios of Earnings to Fixed Charges Exhibit 12(b): Computation of Ratios of Earnings to Fixed Charges Plus Preferred Stock Dividend Requirements Exhibit 23(a): Independent Auditors' Consent
(See Exhibit Index on pages 124 through 130.)
(C) The following reports on Form 8-K were filed by the registrant(s) named below during the last quarter of 2000 and the 2001 period covered by this report under Item 5:
Registrant Date of Report Items Reported PSEG and PSE&G October 18, 2000 Items 5 and 7 PSEG and PSE&G October 27, 2000 Item 9 PSEG and PSE&G November 1, 2000 Item 7 PSEG November 25, 2000 Item 5
113 SCHEDULE II
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED Schedule II - Valuation and Qualifying Accounts Years Ended December 31, 2000 - December 31, 1998
Column B Column C Column D Column E Additions Balance at Charged to Charged to Balance at beginning cost and other accounts Deductions- end of Description of period expenses Describe describe Period (Millions of Dollars) 2000: Allowance for Doubtful Accounts ...... $40 $45 - $41(A) $44 Materials and Supplies Valuation Reserve ...... 11 11 Other Valuation Allowances ...... 22 22
1999: Allowance for Doubtful Accounts ...... $38 $40 $38(A) $40 Discount on Property Abandonments ...... 1 I (B) 11 Materials and Supplies Valuation Reserve ...... 12 41 42(C) Other Valuation Allowances ...... 11 11 22
1998: Allowance for Doubtful Accounts ...... $41 $40 $43(A) $38 Discount on Property Abandonments ...... 2 1(B) 1 Materials and Supplies Valuation Reserve ...... 12 12 Other Valuation Allowances ...... 15 I 5 11 (A) Accounts Receivable/Investments written off. (B) Amortization of discount to income. (C) Inventory written off
PUBLIC SERVICE ELECTRIC AND GAS COMPANY Schedule II - Valuation and Qualifying Accounts Years Ended December 31, 2000- December 31, 1998
Column B Column C Column D Column E Additions Balance at Charged to Charged to Balance at beginning of cost and other accounts- Deductions end of Description Period expenses describe describe Period (Millions of Dollars) 2000: Allowance for Doubtful Accounts ...... $35 $45 $41 (A) $39 Materials and Supplies Valuation Reserve ...... 11 11(D)
1999: Allowance for Doubtful Accounts ...... $34 $40 $39(A) $35 Discount on Property Abandonments ...... 1 I (B) Materials and Supplies Valuation Reserve ...... 12 41 42(C) 11
1998: Allowance for Doubtful Accounts ...... $33 $39 $38(A) $34 Discount on Property Abandonments ...... 2 1(B) 1 Materials and Supplies Valuation Reserve ...... 12 12 (A) Accounts Receivable/Investments written off. (B) Amortization of discount to income. (C) Inventory written off. (D) Transferred to Power.
114 SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Public Service Enterprise Group Incorporated
By E. JAMES FERLAND E. James Ferland Chairman of the Board, President and Chief Executive Officer
Date: March 5, 2001
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature Title Date
E. JAMES FERLAND Chairman of the Board, March 5, 2001 E. James Ferland President and Chief Executive Officer and Director (Principal Executive Officer)
March 5, 2001 ROBERT C. MURRAY Vice President and Chief Financial Robert C. Murray Officer (Principal Financial Officer) March 5, 2001 PATRICIA A. RADO Vice President and Controller Patricia A. Rado (Principal Accounting Officer)
ERNEST H. DREW Director March 5, 2001 Ernest H. Drew March 5, 2001 T. J. DERMOT DUNPHY Director T. J. Dermot Dunphy March 5, 2001 ALBERT R. GAMPER, JR. Director Albert R. Gamper, Jr. March 5, 2001 RAYMOND V. GILMARTIN Director Raymond V. Gilmartin March 5, 2001 CONRAD K. HARPER Director Conrad K. Harper March 5, 2001 IRWIN LERNER Director Irwin Lerner March 5, 2001 MARILYN M. PFALTZ Director Marilyn M. Pfaltz March 5, 2001 FORREST J. REMICK Director Forrest J. Remick March 5, 2001 RICHARD J. SWIFT Director Richard J. Swift
115 SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Public Service Electric and Gas Company
By E. JAMES FERLAND E. James Ferland Chairman of the Board and Chief Executive Officer
Date: March 5, 2001
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature Title Date
E. JAMES FERLAND Chairman of the Board and Chief March 5, 2001 E. James Ferland Executive Officer and Director (Principal Executive Officer)
ROBERT E. BUSCH Senior Vice President and Chief March 5, 2001 Robert E. Busch Financial Officer (Principal Financial Officer)
PATRICIA A. RADO Vice President and Controller March 5, 2001 Patricia A. Rado (Principal Accounting Officer)
ALBERT R. GAMPER, JR. Director March 5, 2001 Albert R. Gamper, Jr.
CONRAD K. HARPER Director March 5, 2001 Conrad K. Harper
IRWIN LERNER Director March 5, 2001 Irwin Lerner
MARILYN M. PFALTZ Director March 5, 2001 Marilyn M. Pfaltz
FORREST J. REMICK Director March 5, 2001 Forrest J. Remick
116 EXHIBIT INDEX
Certain Exhibits previously filed with the Commission and the appropriate securities exchanges are indicated as set forth below. Such Exhibits are not being refiled, but are included because inclusion is desirable for convenient reference.
(a) Filed by PSE&G with Form 8-A under the Securities Exchange Act of 1934, on the respective dates indicated, File No. 00 1-00973.
(b) Filed by PSE&G with Form 8-K under the Securities Exchange Act of 1934, on the respective dates indicated, File No. 00 1-00973.
(c) Filed by PSE&G with Form 10-K under the Securities Exchange Act of 1934, on the respective dates indicated, File No. 001-00973.
(d) Filed by PSE&G with Form 10-Q under the Securities Exchange Act of 1934, on the respective dates indicated, File No. 001-00973.
(e) Filed by PSEG with Form 10-K under the Securities Exchange Act of 1934, on the respective dates indicated, File No. 001-09120.
(f) Filed with registration statement of PSE&G under the Securities Exchange Act of 1934, File No. 1-973, effective July 1, 1935, relating to the registration of various issues of securities.
(g) Filed with registration statement of PSE&G under the Securities Act of 1933, No. 2-4995, effective May 20, 1942, relating to the issuance of $15,000,000 First and Refunding Mortgage Bonds, 3% Series due 1972.
(h) Filed with registration statement of PSE&G under the Securities Act of 1933, No. 2-7568, effective July 1, 1948, relating to the proposed issuance of 200,000 shares of Cumulative Preferred Stock.
(i) Filed with registration statement of PSE&G under the Securities Act of 1933, No. 2-8381, effective April 18, 1950, relating to the issuance of $26,000,000 First and Refunding Mortgage Bonds, 2 3/4% Series due 1980.
() Filed with registration statement of PSE&G under the Securities Act of 1933, No. 2-12906, effective December 4, 1956, relating to the issuance of 1,000,000 shares of Common Stock.
(k) Filed with registration statement of PSE&G under the Securities Act of 1933, No. 2-59675, effective September 1, 1977, relating to the issuance of $60,000,000 First and Refunding Mortgage Bonds, 8 1/8% Series I due 2007.
(1) Filed with registration statement of PSE&G under the Securities Act of 1933, No. 2-60925, effective March 30, 1978, relating to the issuance of 750,000 shares of Common Stock through an Employee Stock Purchase Plan.
(in) Filed with registration statement of PSE&G under the Securities Act of 1933, No. 2-65521, effective October 10, 1979, relating to the issuance of 3,000,000 shares of Common Stock.
(n) Filed with registration statement of PSE&G under the Securities Act of 1933, No. 2-74018, filed on June 16, 1982, relating to the Thrift Plan of PSE&G.
(o) Filed with registration statement of Public Service Enterprise Group Incorporated under the Securities Act of 1933, No. 33-2935 filed January 28, 1986, relating to PSE&G's plan to form a holding company as part of a corporate restructuring. (p) Filed with registration statement of PSE&G under the Securities Act of 1933, No. 33-13209 filed April 9, 1987, relating to the registration of $575,000,000 First and Refunding Mortgage Bonds pursuant to Rule 415. 117 PSEG Exhibit Number This Previous Filing Filing Commission Exchanges 3a (o) 3a (q) 3a Certificate of Incorporation Public Service Enterprise Group Incorporated
3b (e) 3b (e) 3b By-Laws of Public Service Enterprise 4/11/88 Group Incorporated
3c (e) 3c (e) 3c Certificate of Amendment of Certificate of 4/11/88 Incorporation of Public Service Enterprise Group Incorporated, effective April 23, 1987
3d 69 Trust Agreements for Enterprise Capital Trust I and Ill 12/24/97
3e 3 (d) 3 Amended and Restated Trust Agreement for Enterprise Capital 8/14/98 8/14/98 Trust II
4a(l) B-I (c) 4b(1) 2/18/81 Indenture between PSE&G and Fidelity Union Trust Company, (now First Union National Bank) as Trustee, dated August 1, 1924, securing First and Refunding Mortgage Bonds
Indentures between PSE&G and First Union National Bank as Trustee, supplemental to Exhibit 4a(1), dated as follows:
4a(2) 7(1a) (c) 4b(2) April 1, 1927 2/18/81
4a(3) 2b(3) (c) 4b(3) June 1, 1937 2/18/81
4a(4) 2b(4) (c) 4b(4) July 1, 1937 2/18/81
4a(5) 2b(5) (q) 4b(5) December 19, 1939 2/18/81
4a(6) B-1O (c) 4b(6) March 1, 1942 2/18/81
4a(7) 2b(7) (c) 4b(7) June 1, 1949 2/18/81
4a(8) 2b(8) (c) 4b(8) May 1, 1950 2/18/81
4a(9) 2b(9) (q) 4b(9) October 1, 1953 2/18/81
4a(l0) 2bh(o) (c) 4b(10) May 1, 1954 2/18/81
4a(11) 4b(16) (c) 4b(1l) November 1, 1956 2/18/81
4a(1 2) (k) 2b(12) (q) 4b(12) September 1, 1957 2/18/81
4a(13) MIC 2b(13) (c) 4b(13) August 1, 1958 2/18/81
4a(14) (kc) 2b(14) (c) 4b(14) June 1, 1959 2/18/81
118 PSEG Exhibit Number This Previous Filing Filing Commission Exchange 4a(15) (k) 2b(15) (c) 4b(15) September 1, 1960 2/18/81
4a(16) (k) 2b(16) (c) 4b(16) August 1, 1962 2/18/81
4a(17) (k) 2b(1 7) (c) 4b(1 7) June 1, 1963 2/1 8/81
4a(18) (k) 2b(18) (c) 4b(18) September 1, 1964 2/18/81
4a(19) (k) 2b(19) (c) 4b(19) September 1, 1965 2/18/81
4a(20) (k) 2b(20) (c) 4b(20) June 1, 1967 2/18/81
4a(2 1) (k) 2b(21) (c) 4b(21) June 1, 1968 2/18/81
4a(22) (k) 2b(22) (c) 4b(22) April 1, 1969 2/18/81
4a(23) (k) 2b(23) (c) 4b(23) March 1, 1970 2/18/81
4a(24) (k) 2b(24) (c) 4b(24) May 15, 1971 2/18/81
4a(25) (k) 2b(25) (c) 4b(25) November 15, 1971 2/18/81
4a(26) (k) 2b(26) (c) 4b(26) April 1, 1972 2/18/81
4a(27) (a) 2 (c) 4b(27) March 1, 1974 3/29/74 2/18/81
4a(28) (a) 2 (c) 4b(28) October 1, 1974 10/11/74 2/18/81
4a(29) (a) 2 (c) 4b(29) April 1, 1976 4/6/76 2/18/81
4a(30) (a) 2 (c) 4b(30) September 1, 1976 9/16/76 2/18/81
4a(31) (k) 2b(31) (c) 4b(31) October 1, 1976 2/18/81
4a(32) (a) 2 (c) 4b(32) June 1, 1977 6/29/77 2/18/81
4a(33) (7) 2b(33) (c) 4b(33) September 1, 1977 2/18/81
119 PSEG Exhibit Number This Previous Filing Filing Commission Exchanges 4a(35) (a) 2 (c) 4b(35) July 1, 1979 7/25/79 2/18/81
4a(36) (m) 2d(36) (c) 4b(36) September 1, 1979 (No. 1) 2/18/81
4a(37) (m) 2d(37) (c) 4b(37) September I, 1979 (No. 2) 2/18/81
4a(38) (a) 2 (c) 4b(38) November 1, 1979 12/3/79 2/18/81
4a(39) (a) 2 (c) 4b(39) June 1, 1980 6/10/80 2/18/81
4a(40) (a) 2 (a) 2 August 1, 1981 8/19/81 8/19/81
4a(41) (b) 4e (b) 4e April 1, 1982 4/29/82 5/5/82
4a(42) (a) 2 (a) 2 September 1, 1982 9/17/82 9/20/82
4a(43) (a) 2 (a) 2 December 1, 1982 12/21/82 12/21/82
4a(44) (d) 4(ii) (d) 4(ii) June 1, 1983 7/26/83 7/27/83
4a(45) (a) 4 (a) 4 August 1, 1983 8/19/83 8/19/83
4a(46) (d) 4(ii) (d) 4(ii) July 1, 1984 8/14/84 8/17/84
4a(47) (d) 4(ii) (d) 4(ii) September 1, 1984 11/2/84 11/9/84
4a(48) (b) 4(h) (b) 4(ii) November 1, 1984 (No. 1) 1/4/85 1/9/85
4a(49) (b) 4(ii) (b) 4(ii) November I, 1984 (No. 2) 1/4/85 1/9/85
4a(50) (a) 2 (a) 2 July 1, 1985 8/2/85 8/2/85
4a(51) (c) 4a(51) (c) 4a(51) January 1, 1986 2/11/86 2/11/86
4a(52) (a) 2 (a) 2 March 1, 1986 3/28/86 3/28/86
120 PSEG Exhibit Number This Previous Filing Filn Commission Exchanges 4a(53) (a) 2(a) (a) 2(a) April 1, 1986 (No. 1) 5/1/86 5/1/86
4a(54) (a) 2(b) (a) 2(b) April 1, 1986 (No. 2) 5/1/86 5/1/86
4a(55) (p) 4a(55) (p) 4a(55) March 1, 1987 4/9/87 4/9/87
4a(56) (a) 4 (a) 4 July 1, 1987 (No. 1) 8/17/87 8/17/87
4a(57) (d) 4 (d) 4 July 1, 1987 (No. 2) 11/13/87 11/20/87
4a(58) (a) 4 (a) 4 May 1, 1988 5/17/88 5/18/88
4a(59) (a) 4 (a) 4 September 1, 1988 9/27/88 9/28/88
4a(60) (a) 4 (a) 4 July 1, 1989 7/25/89 7/26/89
4a(61) (a) 4 (a) 4 July 1, 1990 (No. 1) 7/25/90 7/26/90
4a(62) (a) 4 (a) 4 July 1, 1990 (No. 2) 7/25/90 7/26/90
4a(63) (a) 4 (a) 4 June i, 1991 (No. 1) 7/1/91 7/2/91
4a(64) (a) 4 (a) 4 June 1, 1991 (No. 2) 7/1/91 7/2/91
4a(65) (a) 4 (a) 4 November 1, 1991 (No. 1) 12/2/91 12/3/91
4a(66) (a) 4 (a) 4 November 1, 1991 (No. 2) 12/2/91 12/3/91
4a(67) (a) 4 (a) 4 November 1, 1991 (No. 3) 12/2/91 12/3/91
4a(68) (a) 4 (a) 4 February 1, 1992 (No. 1) 2/27/92 2/28/92
4a(69) (a) 4 (a) 4 February 1, 1992 (No. 2) 2/27/92 2/28/92
4a(70) (a) 4 (a) 4 June 1, 1992 (No. 1) 6/17/92 6/11/92
4a(71) (a) 4 (a) 4 June 1, 1992 (No. 2) 6/17/92 6/11/92
121 PSEG Exhibit Number This Previous Filing fi~iN Commission Exchanges 4a(72) (a) 4 (a) 4 June 1, 1992 (No. 3) 6/17/92 6/11/92
4a(73) (a) 4 (a) 4 January 1, 1993 (No.1) 2/2/93 2/2/93
4a(74) (a) 4 (a) 4 January 1, 1993 (No. 2) 2/2/93 2/2/93
4a(75) (a) 4 (a) 4 March 1, 1993 3/17/93 3/18/93
4a(76) (b) 4 (a) 4 May 1, 1993 5/27/93 5/28/93
4a(77) (a) 4 (a) 4 May 1, 1993 (No. 2) 5/25/93 5/25/93
4a(78) (a) 4 (a) 4 May 1, 1993 (No. 3) 5/25/93 5/25/93
4a(79) (h) 4 (b) 4 July 1, 1993 12/1193 12/1/93
4a(80) (a) 4 (a) 4 August 1, 1993 8/3/93 8/3/93
4a(81) (b) 4 (b) 4 September 1, 1993 12/1/93 12/1/93
4a(82) (b) 4 (b) 4 September 1, 1993 (No. 2) 12/1/93 12/1/93
4a(83) (b) 4 (b) 4 November 1, 1993 12/1/93 12/1/93
4a(84) (a) 4 (a) 4 February 1, 1994 2/3/94 2/14/94
4a(85) (a) 4 (a) 4 March 1, 1994 (No. 1) 3/15/94 3/16/94
4a(86) (a) 4 (a) 4 March 1, 1994 (No. 2) 3/15/94 3/16/94
4a(87) (d) 4 (d) 4 May 1, 1994 11/8/94 12/2/94
4a(88) (d) 4 (d) 4 June 1, 1994 11/8/94 12/2/94
4a(89) (d) 4 (d) 4 August 1, 1994 11/8/94 12/2/94
4a(90) (d) 4 (d) 4 October 1, 1994 (No. 1) 11/8/94 12/2/94
4a(91) (d) 4 (d) 4 October 1, 1994 (No. 2) 11/8/94 12/2/94
122 PSEG Exhibit Number This Previous Filing Filing Commission Exchanges 4a(92) (a) 4 (a) 4 January 1, 1996 (No. 1) 1/26/96 1/26/96
4a(93) (a) 4 (a) 4 January 1, 1996 (No. 2) 1/26/96 1/26/96
4a(94) (e) 4 December 1, 1996 2/26/97
4a(95) (a) 4 (a) 4 June 1, 1997 6/17/97 6/17/97
4a(96) (a) 4 (a) 4 May 1, 1998 5/15/98 5/15/98
4b (b) 4 (b) 4 Indenture of Trust between PSE&G and The Chase Manhattan 12/1/93 12/1/93 Bank (National Association), as Trustee, providing for Secured Medium-Term Notes dated July 1, 1993
4c(1) (c) (N) Indenture between PSE&G and First Union National Bank, 2/23/95 2/23/95 National Association (now known as First Union National Bank), as Trustee, dated November 1, 1994, providing for Deferrable Interest Subordinated Debentures in Series
4c(2) (a) (a) Supplemental Indenture between PSE&Gand First Fidelity Bank, 9/11/95 9/11/95 National Association (now known as First Union National Bank), (d) 4d (2) (d) 4d (2) as Trustee, dated September 1, 1995 providing for Deferrable 5/13/98 5/13/98 Interest Subordinated Debentures, Series B (relating to Monthly Preferred Securities)
4d(1) (d) 4e (1) (d) 4e(l) Indenture between PSE&G and First Union National Bank, as 5/13/98 5/13/98 Trustee, dated June 1, 1996 providing for Deferrable Interest Subordinated Debentures in Series (relating to Quarterly Preferred Securities)
4d(2) (d) 4e(2) (d) 4e(2) Supplemental Indenture between PSE&G and First Union 5/13/98 5/13/98 National Bank, as Trustee, dated February 1, 1997 providing for Deferrable Interest Subordinated Debentures, Series B (relating to Quarterly Preferred Securities)
4e(l) (d) 4f (d) 4f Indenture between Public Service Enterprise Group Incorporated 5/13/98 5/13/98 and First Union National Bank, as Trustee, dated January 1, 1998 providing for Deferrable Interest Subordinated Debentures in Series (relating to Quarterly Preferred Securities)
4e(2) (d) 4a (d) 4a First Supplemental Indenture to Indenture dated as of January 1, 8/14/98 8/14/98 1998 between Public Service Enterprise Group Incorporated and First Union National Bank, as Trustee, dated June 1, 1998 providing for the issuance of Floating Rate Deferrable Interest Subordinated Debentures, Series B (relating to Trust Preferred Securities)
4e(3) (d) 4b (d) 4b Second Supplemental Indenture to Indenture dated as of January I, 8/14/98 8/14/98 1998 between Public Service Enterprise Group Incorporated and First Union National Bank, as Trustee, dated July 1, 1998 providing for the issuance of Deferrable Interest Subordinated Debentures, Series C (relating to Trust Preferred Securities)
4f (c) 4f (c) 4f Indenture dated as of November 1, 1998 between Public Service 11/1/00 11/1/00 Enterprise Group Incorporated and First Union National Bank providing for the issuance of Senior Debt Securities
9 Inapplicable
123 PSEG Exhibit Number This Previous Filing Filing Commission Exchanges 10a(l) (e) IOa(l) (e) 1Oa(1) Directors' Deferred Compensation Plan 2/25/00 2/25/00
I Oa(2) (e) 10a(2) (e) IOa(2) Deferred Compensation Plan for Certain Employees 2/25100 2/25/00
1Oa(3) (e) IOa(3) (e) 1Oa(3) Limited Supplemental Benefits Plan for Certain Employees 2/25/00 2/25/00
10a(4) (e) IOa(4) (e) I Oa(4) Mid Career Hire Supplemental Retirement Plan 2/25/00 2/25/00
1Oa(5) (e) 10a(5) (e) 10a(5) Retirement Income Reinstatement Plan 2/25/00 2/25/00
1Oa(6) (e) IOa(6) (e) 1Oa(6) 1989 Long-Term Incentive Plan 2/22/99 2/22/99 lOa(7) 2001 Long-Term Incentive Plan lOa(8) Restated and Amended Management Incentive Compensation Plan
IOa(9) 10 (d) 10 Employment Agreement with E. James Ferland dated 8/14/98 8/14/98 June 16, 1998 lOa(i0) 10a(22) (d) 1Oa(22) Employment Agreement with Robert C. Murray dated 11/13/00 11/13/00 October 17, 2000 lOa(l 1) lOa(14) (c) 10a(14) Letter Agreement with Patricia A. Rado dated 2/26/94 3/9/94 March 24, 1993
1Oa(12) 10a(21) (d) 1Oa(21) Employment Agreement with Alfred C. Koeppe dated 11/13/00 11/13/00 October 17, 2000 lOa(13) 1Oa(19) (d) 10a(19) Employment Agreement with Frank Cassidy dated 11/13/00 11/13/00 October 17, 2000 lOa(14) 10a(20) (d) 1Oa(20) Employment Agreement with Robert J. Dougherty, Jr. dated 11/13/00 11/13/00 October 17,2000
1Oa(15) 10a(14) (e) lOa(14) Directors' Stock Plan 2/22/99 2/22/99 lOa(16) 10a(16) (c) 10a(16) Letter Agreement with Harold W. Keiser dated January 5, 1998 2/23/98 2/23/98 lOa(17) lOa(16) (e) lOa(16) Global Deferred Compensation Plan 2/22/99 2/22/99
1Oa(18) lOa(17) (e) I0a(17) Global 2001 Executive Long-Term Incentive Compensation Plan 2/22/99 2/22/99 lOa(19) lOa(20) (e) lOa(20) Energy Technologies Executive Incentive Compensation Plan 2/22/99 2/22/99 lOa(20) 1Oa(22) (e) !Oa(22) Resources Annual Incentive Compensation Plan 2/22/99 2/22/99
11 Inapplicable
12 Computation of Ratios of Earnings to Fixed Charges
13 Inapplicable
16 Inapplicable 124 I ?SEG Exhil it Number This Previous Filing Filing Commission Exchanges
18 Inapplicable
21 Subsidiaries of the Registrant
22 Inapplicable
23 Independent Auditors' Consent
24 Inapplicable
28 Inapplicable
99 Inapplicable
PSE&G Exhibit Number This Previous Filing Filing Commission Exchanges 3a(1) (b) 3a (b) 3a Restated Certificate of Incorporation of PSE&G 8/28/86 8/29/86
3a(2) (c) 3a(2) (c) 3a(2) Certificate of Amendment of Certificate of Restated Certificate of 4/10/87 Incorporation of PSE&G filed February 18, 1987 with the State of New Jersey adopting limitations of liability provisions in accordance with an amendment to New Jersey Business Corporation Act
3a(3) (a) 3(a)3 (a) 3(a)3 Certificate of Amendment of Restated Certificate of Incorporation 2/3/94 2/14/94 of PSE&G filed June 17, 1992 with the State of New Jersey, establishing the 7.44% Cumulative Preferred Stock ($100 Par) as a series of the Preferred Stock
3a(4) (a) 3(a)4 (a) 3(a)4 Certificate of Amendment of Restated Certificate of Incorporation 2/3/94 2/14/94 of PSE&G filed March 11, 1993 with the State of New Jersey, establishing the 5.97% Cumulative Preferred Stock ($100 Par) as a series of Preferred Stock
3a(5) (a) 3(a)5 (a) 3(a)5 Certificate of Amendment of Restated Certificate of Incorporation 2/3/94 2/14/94 of PSE&G filed January 27, 1995 with the State of New Jersey, establishing the 6.92% Cumulative Preferred Stock ($100 Par) and the 6.75% Cumulative Preferred Stock - $25 Par as series of Preferred Stock
3b(l) (d) (d) Copy of By-Laws of PSE&G 8/8/00 8/8/00
4a(l) 69 B-I (c) 4b(l) Indenture between PSE&G and Fidelity Union Trust Company, 2/18/81 (now First Union National Bank, National Association), as Trustee, dated August 1, 1924, securing First and Refunding Mortgage Bond
Indentures between PSE&G and First Fidelity Bank, National Association, as Trustee, supplemental to Exhibit 4a(l), dated as follows:
4a(2) (i) 7(la) (c) 4b(2) April 1, 1927 2/18/81
4a(3) (7c) 2b(3) (c) 4b(3) June 1, 1937 2/18/81
125 PSE&G Exhibit Number This Previous Filing Filing Commission Exchanges 4a(4) (k) 2b(4) (c) 4b(4) July 1, 1937 2/18/81
4a(5) (k) 2b(5) (c) 4b(5) December 19, 1939 2/18/81
4a(6) (g) B-10 (c) 4b(6) March 1, 1942 2/18/81
4a(7) (k) 2b(7) (c) 4b(7) June 1, 1949 2/18/81
4a(8) (k) 2b(8) (c) 4b(8) May 1, 1950 2/18/81
4a(9) (k) 2b(9) (c) 4b(9) October 1, 1953 2/18/81
4a(10) (k) 2b(10) (c) 4b(10) May 1, 1954 2/18/81
4a(11) 0) 4b(16) (c) 4b(11) November 1, 1956 2/18/81
4a(12) (k) 2b(12) (c) 4b(12) September 1, 1957 2/18/81
4a(13) (k) 2b(13) (c) 4b(13) August 1, 1958 2/18/81
4a(14) (k) 2b(14) (c) 4b(14) June 1, 1959 2/18/81
4a(15) (k) 2b(15) (c) 4b(15) September 1, 1960 2/18/81
4a(16) (k) 2b(16) (c) 4b(16) August 1, 1962 2/18/81
4a(17) (k) 2b(17) (c) 4b(17) June 1, 1963 2/18/81
4a(18) (k) 2b(18) (c) 4b(18) September 1, 1964 2/18/81
4a(19) (k) 2b(19) (c) 4b(19) September 1, 1965 2/18/8 1
4a(20) (k) 2b(20) (c) 4b(20) June 1, 1967 2/18/81
4a(21) (k) 2b(21) (c) 4b(21) June 1, 1968 2/18/81
4a(22) (k) 2b(22) (c) 4b(22) April 1, 1969 2/18/81
4a(23) (k) 2b(23) (c) 4b(23) March 1, 1970 2/18/81
126 PSE&G Exhibit Number This Previous Filing FumE Commission Exchanges 4a(24) (k) 2b(24) (c) 4b(24) May 15, 1971 2/18/81
4a(25) (k) 2b(25) (c) 4b(25) November 15, 1971 2/18/81
4a(26) (k) 2b(26) (c) 4b(26) April 1, 1972 2/18/81
4a(27) (a) 2 (c) 4b(27) March 1, 1974 3/29/74 2/18/81
4a(28) (a) 2 (c) 4b(28) October 1, 1974 10/11/74 2/18/81
4a(29) (a) 2 (c) 4b(29) April 1, 1976 4/6/76 2/18/81
4a(30) (a) 2 (c) 4b(30) September 1, 1976 9/16/76 2/18/81
4a(31) (k) 2b(31) (c) 4b(31) October 1, 1976 2/18/81
4a(32) (a) 2 (c) 4b(32) June 1, 1977 6/29/77 2/18/81
4a(33) (1) 2b(33) (c) 4b(33) September 1, 1977 2/18/81
4a(34) (a) 2 (c) 4b(34) November 1, 1978 I 1/21/78 2/18/81
4a(35) (a) 2 (c) 4b(35) July 1, 1979 7/25/79 2/18/81
4a(36) (m) 2d(36) (c) 4b(36) September 1, 1979 (No. 1) 2/18/81
4a(37) (m) 2d(37) (c) 4b(37) September I, 1979 (No. 2) 2/18/81
4a(38) (a) 2 (c) 4b(38) November 1, 1979 12/3/79 2/18/81
4a(39) (a) 2 (c) 4b(39) June 1, 1980 6/10/80 2/18/81
4a(40) (a) 2 (a) 2 August 1, 1981 8/19/81 8/19/81
4a(41) (b) 4e (b) 4e April 1, 1982 4/29/82 5/5/82
4a(42) (a) 2 (a) 2 September 1, 1982 9/17/82 9/20/82
4a(43) (a) 2 (a) 2 December 1, 1982 12/21/82 12/21/82
4a(44) (d) 4(ii) (d) 4(ii) June 1, 1983 7/26/83 7/27/83
127 PSE&G Exhibit Number This Previous Filing Filing Commission Exchanges 4a(45) (a) 4 (a) 4 August 1, 1983 8/19/83 8119/83
4a(46) (d) 4(ii) (d) 4(ii) July 1, 1984 8/14/84 8/17/84
4a(47) (d) 4(ii) (d) 4(ii) September 1, 1984 11/2/84 11/9/84
4a(48) (b) 4(ii) (a) 4(ii) November 1, 1984 (No. 1) 1/4/85 1/9/85
4a(49) (W) 4(ii) (C) 4(ii) November 1, 1984 (No. 2) 1/4/85 1/9/85
4a(50) (a) 2 (a) 2 July 1, 1985 8/2/85 8/2/85
4a(51) (c) 4a(51) (c) 4a(51) January 1, 1986 2/11/86 2/11/86
4a(52) (a) 2 (a) 2 March 1, 1986 3/28/86 3/28/86
4a(53) (a) 2(a) (a) 2(a) April 1, 1986 (No. 1) 5/1/86 5/1/86
4a(54) (a) 2(b) (a) 2(b) April 1, 1986 (No. 2) 5/1/86 5/1/86
4a(55) (P) 4a(55) 4a(55) March 1, 1987 4/9/87 4/9/87
4a(56) (a) 4 (a)(d) 4 July 1, 1987 (No. 1) 8/17/87 8/17/87
4a(57) (d) 4 (d) 4 July 1, 1987 (No. 2) 11/13/87 11/20/87
4a(58) (a) 4 (a) 4 May 1, 1988 5/17/88 5/18/88
4a(59) (a) 4 (a) 4 September 1, 1988 9/27/88 9/28/88
4a(60) (a) 4 (a) 4 July 1, 1989 7/25/89 7/26/89
4a(61) (a) 4 (a) 4 July 1, 1990 (No. 1) 7/25/90 7/26/90
4a(62) (a) 4 (a) 4 July 1, 1990 (No. 2) 7/25/90 7/26/90
4a(63) (a) 4 (a) 4 June 1, 1991 (No. 1) 7/1/91 7/2/91
4a(64) (a) 4 (a) 4 June 1, 1991 (No. 2) 7/1/91 7/2/91
4a(65) (a) 4 (a) 4 November 1, 1991 (No. 1) 12/2/91 12/3/91
128 PSE&G Exhibit Number This Previous Filing Filing Commission Exchanges 4a(66) (a) 4 (a) 4 November 1, 1991 (No. 2) 12/2/91 12/3/91
4a(67) (a) 4 (a) 4 November 1, 1991 (No. 3) 12/2/91 12/3/91
4a(68) (a) 4 (a) 4 February 1, 1992 (No. 1) 2/27/92 2/28/92
4a(69) (a) 4 (a) 4 February 1, 1992 (No. 2) 2/27/92 2/28/92
4a(70) (a) 4 (a) 4 June 1, 1992 (No. 1) 6/17/92 6/11/92
4a(71) (a) 4 (a) 4 June 1, 1992 (No.2) 6/17/92 6/11/92
4a(72) (a) 4 (a) 4 June 1, 1992 (No. 3) 6/17/92 6/111/92
4a(73) (a) 4 (a) 4 January 1, 1993 (No. 1) 2/2/93 2/2/93
4a(74) (a) 4 (a) 4 January 1, 1993 (No. 2) 2/2/93 2/2/93
4a(75) (a) 4 (a) 4 March 1, 1993 3/17/93 3/18/93
4a(76) (b) 4 (a) 4 May 1, 1993 5/27/93 5/28/93
4a(77) (a) 4 (a) 4 May 1, 1993 (No. 2) 5/25/93 5/25/93
4a(78) (a) 4 (a) 4 May 1, 1993 (No. 3) 5/25/93 5/25/93
4a(79) (b) 4 (b) 4 July 1, 1993 12/1/93 12/1/93
4a(80) (a) 4 (a) 4 August 1, 1993 8/3/93 8/3/93
4a(81) (b) 4 (b) 4 September 1, 1993 12/1/93 12/1/93
4a(82) (a) 4 (a) 4 September 1, 1993 (No. 2) 12/1/93 12/1/93
4a(84) (a) 4 (a) 4 February 1, 1994 2/3/94 2/14/94
4a(85) (a) 4 (a) 4 March 1, 1994 (No. 1) 3/15/94 3/16/94
4a(86) (a) 4 (a) 4 March 1, 1994 (No. 2) 3/15/94 3/16/94
4a(87) (d) 4 (d) 4 May I, 1994 11/8/94 12/2/94
129 PSE&G Exhibit Number This Previous Filing 4aling Commission Exchanges 4a(88) (d) 4 (d) 4 June I, 1994 11/8/94 12/2/94
4a(89) (d) 4 (d) 4 August 1, 1994 11/8/94 12/2/94
4a(90) (d) 4 (d) 4 October 1, 1994 (No. I) 11/8/94 12/2/94
4a(91) (d) 4 (d) 4 October 1, 1994 (No. 2) 11/8/94 12/2/94
4a(92) (a) 4 (a) 4 January 1, 1996 (No.1) 1/26/96 1/26/96
4a(93) (a) 4 (a) 4 January 1, 1996 (No. 2) 1/26/96 1/26/96
4a(94) (c) 4 December 1, 1996 2/26/97
4a(95) (a) 4 (a) 4 June 1, 1997 6/17/97 6/17/97
4a(96) (a) 4 (a) 4 May 1, 1998 5/15/98 5/15/98
4b (b) 4 (b) 4 Indenture of Trust between PSE&G and Chase Manhattan Bank 12/1/93 12/1/93 (National Association), as Trustee, providing for Secured Medium-Term Notes dated July I, 1993
4c(1) (b) (c) Indenture between PSE&G and First Fidelity Bank, National 2/23/95 2/23/95 Association (now known as First Union National Bank), as Trustee, dated November I, 1994, providing for Deferrable Interest Subordinated Debentures in Series
4c(2) (a) 4b(5) (a) 4b(5) Supplemental Indenture between PSE&G and First Fidelity Bank, National Association (now known as First Union National Bank), (d) 4d(2) (d) 4d(2) as Trustee, dated September 1, 1995 providing for Deferrable 5/13/98 5/13/98 Interest Subordinated Debentures, Series B (relating to Monthly Preferred Securities)
4d(1) (d) 4e(i) (d) 4e(1) Indenture between PSE&G and First Union National Bank, as 5/13/98 5/13/98 Trustee, dated June 1, 1996 providing for Deferrable Interest Subordinated Debentures in Series (relating to Quarterly Preferred Securities)
4d(2) (d) 4e(2) (d) 4e(2) Supplemental Indenture between PSE&G and First Union 5/13/98 5/13/98 National Bank, as Trustee, dated February 1, 1997 providing for Deferrable Interest Subordinated Debentures, Series B (relating to Quarterly Preferred Securities) Senior Note Indenture
130 PSE&G Exhibit Number This Previous Filing Filing Commission Exchange 10a(1) (c) 10a(1) (c) 10a(l) Directors' Deferred Compensation Plan 2/25/00 2125/00
10a(2) (c) 10a(2) (c) 10a(2) Deferred Compensation Plan for Certain Employees 2/25/00 2/25/00 Employees 1Oa(3) (c) I Oa(3) (c) 10a(3) Limited Supplemental Benefits Plan for Certain 2/25/00 2/25/00 l0a(4) (c) 10a(4) (c) IOa(4) Mid Career Hire Supplemental Retirement Plan 2/25/00 2125/00 Plan 10a(5) (c) lOa(5) (c) lOa(5) Retirement Income Reinstatement 2/25/00 2/25/00
1Oa(6) (c) lOa(6) (c) 1Oa(6) 1989 Long-Term Incentive Plan 2/22/99 2/22/99
IOa(7) 2001 Long-Term Incentive Plan
IOa(8) Restated and Amended Management Incentive Compensation Plan lOa(9) (d) 10 (d) 10 Employment Agreement with E. James Ferland, dated June 16, 8/14/98 8/14/98 1998 (c) 10a(13) IOa(1 0) (c) 1Oa(13) Letter Agreement with Patricia A. Rado dated 2/26/94 3/9/94 March 24, 1993 lOa(1 1) (d) lOa(21) (d) Employment Agreement with Alfred C. Koeppe dated 11/13/00 October 17, 2000
11 Inapplicable
12(a) Computation of Ratios of Earnings to Fixed Charges
12(b) Computation of Ratios of Earnings to Fixed Charges Plus Preferred Stock Dividend Requirements
13 Inapplicable
16 Inapplicable
19 Inapplicable
21 Inapplicable
23 Independent Auditors' Consent
131 [THIS PAGE INTENTIONALLY LEFT BLANK] [THIS PAGE INTENTIONALLY LEFT BLANK] fTMS PAGE UMEN71ONALLY LEFT BLAMK) -
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-K N] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2000 or
LI TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number 1-3559
ATLANTIC CITY ELECTRIC COMPANY (Exact name of registrant as specified in its charter)
New Jersey 21-0398280 (State of Incorporation) (I.R.S. Employer Identification No.) 800 King Street, PO Box 231 Wilmington, Delaware 19899 (Address of principal executive offices) Registrant's telephone number (302) 429-3069
Securities registered pursuant to Section 12(b) of the Act: Name of each exchange on Title of each class which registered 8.25% Cumulative Quarterly Income Preferred New York Stock Exchange Securities, liquidation preference $25 per preferred security issued by Atlantic Capital 1 7 3/8% Cumulative Trust Preferred Capital New York Stock Exchange Securities, liquidation preference $25 per preferred security issued by Atlantic Capital II
Securities registered pursuant to Section 12(g) of the Act: None
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 [Z No FE Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or informa tion statements incorporated by reference in Part [II of this Form 10-K or any amendment to this Form 10-K. Z All 18.320.937 issued and outstanding shares of Atlantic City Electric Company common stock, $3 per share par value, are owned by Conectiv. N
TABLE OF CONTENTS
Page PART I Item 1. Business O verview ...... I-I Business Segm ents ...... 1-2 Contribution of Combustion Turbines to Conectiv ...... 1-2 Agreements for the Sale of Electric Generating Plants ...... 1-2 Electric Utility Industry Restructuring ...... 1-3 Basic Generation Service ...... 1-3 C apacity ...... 1-3 Electric Generating Plants ...... 1-4 Purchased Pow er ...... 1-4 Supplying Forecasted Peak Loads ...... 1-4 PJM Interconnection L.L.C ...... 1-4 N uclear Power Plants ...... 1-5 Fuel Supply for Electric Generation ...... 1-5 C oal ...... 1-6 O il ...... 1-6 G as ...... 1-6 N uclear ...... 1-6 Electric Energy Adjustment Clause ...... 1-6 Retail Electric Rates ...... 1-7 New Jersey Electric System Reliability Standards ...... 1-7 New Jersey Demand Side M anagement ...... 1-7 A ffiliated Transactions ...... 1-7 Federal Decontamination & Decommissioning Fund ...... 1-7 Capital Spending and Financing Program ...... 1-8 Environm ental M atters ...... 1-8 A ir Q uality Regulations ...... 1-8 W ater Q uality Regulations ...... 1-9 H azardous Substances ...... 1-9 Executive O fficers ...... 1-10 Item 2. Properties ...... 1-11 Item 3. Legal Proceedings ...... I-11 Item 4. Submission of Matters to a Vote of Security Holders ...... 1-1I PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters ...... I-I Item 6. Selected Financial Data ...... 11-2 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations .. 11-3 Item 7A. Quantitative and Qualitative Disclosures About Market Risk ...... 11-13 Item 8. Financial Statements and Supplementary Data ...... 11-14 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 11-43 PART III
Item 10. Directors and Executive Officers of the Registrant ...... III-I Item 11. Executive Compensation ...... 111-2 Item 12. Security Ownership of Certain Beneficial Owners and Management ...... 111-7 Item 13. Certain Relationships and Related Transactions ...... 111-7 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K ...... IV-I Signatures ...... IV -4 PART I
ITEM 1. BUSINESS
Overview
Atlantic City Electric Company (ACE) is a regulated public electric utility and a subsidiary of Conectiv, which is a Delaware corporation and a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). PUHCA imposes certain restrictions on the operations of registered holding companies and their subsidiaries. ACE was organized under the laws of New Jersey on April 28, 1924, by merger and consolidation of several utility companies. Effective March 1, 1998, Atlantic Energy, Inc. (Atlantic) and Delmarva Power & Light Company (DPL) consummated a series of merger transactions (the Merger) by which ACE and DPL became wholly-owned subsidiaries of Conectiv. Atlantic owned ACE prior to the Merger. For additional information about the Merger, refer to Note 4 to the Consolidated Financial Statements included in Item 8 of Part II.
On February 9, 2001, the Boards of Directors of Conectiv and Potomac Electric Power Company (Pepco) approved an Agreement and Plan of Merger (Conectiv/Pepco Merger Agreement) under which Pepco will acquire Conectiv for a combination of cash and stock. The transaction is subject to various statutory and regulatory approvals and approval by the stockholders of Conectiv and Pepco.
As a public electric utility, ACE supplies and delivers electricity to its customers. These businesses, which are discussed below, are weather sensitive and seasonal because sales of electricity are usually higher during the summer months due to air conditioning usage. ACE delivers electricity to approximately 501,000 customers through its transmission and distribution systems and also supplies electricity to most of its delivery customers. ACE's regulated service area covers about 2,700 square miles within the southern one-third of New Jersey and has a population of approximately 0.9 million.
ACE supplies electricity to customers within its service area with power purchased from other suppliers and electricity generated by its power plants. A transition to market pricing and terms of service for supplying electricity in ACE's regulated service area began in 1999. All of ACE's electricity delivery customers could elect to choose an alternative electricity supplier, beginning August 1, 1999.
ACE's electric retail utility business is subject to regulation by the New Jersey Board of Public Utilities (NJBPU), including rates charged to electric customers. The Federal Energy Regulatory Commission (FERC) also has regulatory authority over certain aspects of ACE's electric utility business. In 2000, the regulated retail electricity delivery and supply businesses provided about 87% of ACE's operating revenues and most of ACE's earnings. In 2000, ACE's regulated electric retail revenues were earned from the following customer classes: residential-50.4%; commercial-37.9%; industrial-9.7%; and other-2.0%.
Effective August 1, 1999, ACE's combustion turbines (502 megawatts of electric generating capacity) and the Deepwater plant (185 megawatts of electric generating capacity) were deregulated and the output of these plants was sold in markets not subject to price regulation. On July 1, 2000, ACE contributed the combustion turbines to Conectiv, as discussed under "Contribution of Combustion Turbines to Conectiv." The Deepwater plant is subject to an agreement for sale as discussed under "Agreements for the Sale of Electric Generating Plants."
Conectiv's service company, Conectiv Resource Partners, Inc. (CRP), provides a variety of support services to Conectiv subsidiaries. The costs of CRP are directly assigned and allocated to the Conectiv subsidiaries using CRP's services.
As of December 31, 2000, ACE had 660 employees, of which 498 were represented by a labor organization.
I-I Business Segments For other information concerning ACE's business segments, see Note 23 to ACE's 2000 Consolidated Financial Statements included in Item 8 of Part II.
Contribution of Combustion Turbines to Conectiv Effective July 1, 2000, ACE contributed at book value its combustion turbines (502 megawatts (MW) of capacity) and related transmission equipment, inventories, and liabilities to a wholly-owned subsidiary (Conectiv Atlantic Generation, LLC, or CAG). ACE then contributed CAG to Conectiv in conjunction with the formation of an energy-holding company by Conectiv, which is engaged in non-regulated electricity production and sales, and energy trading and marketing. This transaction caused an $86 million decrease in property, plant and equipment and an $83 million decrease in common stockholder's equity.
Agreements for the Sale of Electric Generating Plants ACE has entered into agreements for the sale of its ownership interests in non-strategic baseload nuclear and fossil fuel-fired electric generating plants. As of December 31, 2000, all of the electric generating plants of ACE were subject to sales agreements and the plants had a net book value of $132.1 million and an aggregate capacity of 1,122.7 MW. These electric generating plants held for sale include the following: (i) The ownership interests of ACE in nuclear electric generating plants: (a) The agreed upon selling price is $11 million plus the net book value of ACE's interests in nuclear fuel as of the closing date; (b) As of December 31, 2000, the capacity and the net book value of ACE's interests in these plants were 383 MW and $14.5 million, respectively. (ii) The ownership interests of ACE in certain wholly and jointly owned fossil fuel-fired electric generating units: (a) The agreed upon selling price is $178 million, before certain adjustments and selling expenses; (b) As of December 31, 2000, the capacity and the net book value of ACE's interests in these electric generating units were 739.7 MW and $117.6 million, respectively.
As of December 31, 1999, ACE had ownership interests in electric generating plants representing 1,624.7 MW of electric generating capacity. The 502 MW decrease in electric generating capacity from 1999 to 2000 resulted from the contribution of the combustion turbines to Conectiv, effective July 1, 2000. After the sales of the electric generating plants of ACE are completed. the principal remaining businesses of ACE will be the transmission and distribution of electricity.
ACE's exit from the business of electricity production is expected to cause a decrease in ACE's earnings capacity.
Consummation of the sales of the electric generating plants is subject to the receipt of required regulatory approvals. In addition, the agreements for the sales of the electric generating plants contemplated that the sales of the plants of ACE and DPL, which is also selling its electric generating plants, would occur simultaneously. Appeals related to the NJBPU's final order concerning restructuring the electricity supply business of Public Service Electric and Gas Company (PSE&G) and recent electricity shortages and price increases in California have resulted in delays in the issuance of required regulatory approvals, the NJBPU's final order concerning restructuring the electricity supply business of ACE, and the closings of the sales of the electric generating units. On December 6, 2000, the New Jersey S.;. ,reme Court affirmed the judgment of the New Jersey Superior Court Appellate Division. which had previously iheld the NJBPU's final order concerning the PSE&G restructuring. Management currently expects the sales ot ACE's nuclear and fossil fuel-fired electric generating plants to take
1-2 place during 2001. However, management cannot predict the timing of the issuance of required NJBPU approv als, the timing or outcome of appeals, if any, of such approvals, the effect of any of the foregoing on the ability of ACE to consummate the sales of various electric generating plants or the impact of any of the foregoing on ACE's ability to recover or securitize any related stranded costs.
For additional information, see "Agreements for the Sales of Electric Generating Plants" within Manage ment's Discussion and Analysis of Financial Condition and Results of Operations (MD&A), included in Item 7 of Part II, and Note 11 to the Consolidated Financial Statements included in Item 8 of Part II.
Electric Utility Industry Restructuring As discussed below, ACE's electric utility business was restructured during 1999 pursuant to enactment of New Jersey's Electric Discount and Energy Competition Act (New Jersey Act) and a Summary Order the NJBPU issued to ACE. All customers in ACE's service area could choose an alternative electricity supplier beginning August 1, 1999.
ACE supplies electricity to customers in its service area with power purchased from other suppliers and electricity generated by its power plants. The transition to market pricing and terms of service for supplying electricity to customers in ACE's service area began with enactment of the New Jersey Act on February 9, 1999 which provided customers of New Jersey electric utilities with a choice of electricity suppliers beginning August 1, 1999. On July 15, 1999 the NJBPU issued to ACE a Summary Order which provided for decreases in electric customer rates, the opportunity to recover stranded costs, securitization of ACE's stranded costs, and the regulatory treatment of any gain or loss arising from the divestiture of electric power plants. For information about restructuring the electricity supply business of ACE, see Notes 1, 6, 7, 8 and 14 to the Consolidated Financial Statements, included in Item 8 of Part II, and "Electric Utility Industry Restructuring" within the MD&A included in Item 7 of Part II.
Basic Generation Service Through July 31, 2002, under New Jersey's Basic Generation Service (BGS), ACE is obligated to supply electricity to customers who do not choose an alternative electricity supplier. ACE supplies the BGS load requirement with purchased power and the output generated by certain units to be sold. ACE's customer rates are designed to recover the costs of providing BGS service, including above-market portions of long-term purchased power contracts. As a result, ACE recognizes revenues for BGS service equal to the related costs incurred. Any difference between such revenues and costs results in a related adjustment to "Deferred energy supply costs." ACE had a regulatory liability of $34.7 million as of December 31, 2000 and $46.4 million as of December 31, 1999 for over-recovered energy supply costs. ACE's customer rates are to be adjusted for any deferred balance remaining after the initial four-year transition period ends July 31, 2003. ACE's recovery of BGS supply costs is subject to review by the NJBPU.
For additional information concerning the source of electricity supplied for BGS, see "Supplying Fore casted Peak Loads" below.
Capacity Capacity is the capability to produce electric power from owned electric generating units and differs from the electric energy markets, which trade the actual energy being generated. Capacity may also be purchased through third-party contracts. As discussed below, the PJM Interconnection, L.L.C. (PJM) power pool operates a centralized capacity market, which allows PJM member companies such as Conectiv to buy or sell capacity as needed for the electric utility operations of Conectiv subsidiaries. As a member of the PJM, Conectiv is obligated to maintain capacity levels based on its allocated share of estimated aggregate PJM capacity requirements. including the portion attributable to ACE. More capacity will need to be purchased after the electric generating units subject to sales agreements are sold.
1-3 Electric Generating Plants
The capacity provided by the electric generating plants of ACE as of December 31, 2000 is summarized in the chart below. As discussed above, all of the electric generating plants of ACE are subject to agreements for sale. The net generating capacity available for operations at any time may be less than the total net installed generating capacity due to generating units being out of service for inspection, maintenance, repairs, or unfore seen circumstances.
MWof Type of Electric Generating Plant Capacity C oal-fired ...... 471 O il-fired ...... 2 4 1 Combustion turbines ...... 22 Nuclear ...... 380 D iesel...... 9 Electric Generating Capacity...... 1,123
PurchasedPower
As discussed in Note 19 to the Consolidated Financial Statements included in Item 8 of Part II, as of December 31, 2000, ACE had long-term purchased power contracts, which provided 724 MW of capacity and the related energy. These long-term purchased power contracts include 524 MW of capacity and energy pur chased from non-utility generators (NUGs), at prices which generally are above market prices. ACE purchases electricity from the NUGs as a result of legislation enacted in 1978 which requires electric utilities to purchase such power. ACE recovers the costs of these contracts through rates charged to customers for BGS.
Supplying ForecastedPeak Loads Management currently forecasts a peak load of 2,074 MW in 2001 for ACE's BGS.
ACE intends to manage its BGS supply requirement through the use of a portfolio approach, including the use of competitive bidding. Approximately 50% of ACE's forecasted 2001 BGS load requirement will be supplied from a combination of existing bilateral long-term power purchases and electricity generated by plants of ACE. The balance of the supply is expected to be provided through additional bilateral contracts and the spot market.
PJM Interconnection, L.L.C Pursuant to Conectiv's PJM membership, the generation and transmission facilities of ACE are operated on an integrated basis with other electricity suppliers in Pennsylvania, New Jersey, Maryland, and the District of Columbia, and are interconnected with other major utilities in the eastern half of the United States. This power pool improves the reliability and operating economies of the systems in the group and provides capital economies by permitting shared reserve requirements. The PJM's installed capacity as of December 31, 2000, was 58,701 MW. The PIM's peak demand during 2000 was 49,430 MW on August 9, which resulted in a summer reserve margin of 18.4% (based on installed capacity of 58,524 MW on that date).
The PJM operates a centralized capacity credit market, enabling participants to procure or sell surplus capacity to meet reliability obligations within the PJM region.
The PJM Operating Agreement allows bids to sell electricity (energy) received from generation located within the PJM control area. Transactions that are bid into the PJM pool are capped at $1,000 per megawatt hour. All power providers are paid the locational marginal price (LMP) set through power providers' bids. The LMP will be higher in congested areas reflecting the price bids of those higher cost generating units that are
1-4 dispatched to supply demand and alleviate the transmission constraint. Furthermore, in the event that all available generation within the PJM control area is insufficient to satisfy demand, the PJM may institute emergency purchases from adjoining regions. The cost of such emergency purchases is not subject to any PIM price cap.
There are a number of factors that distinguish the PJM market from California, and make the types of problems recently experienced there less likely. The most prominent difference is the extent to which there is adequate generating capacity to meet demand in the region. The PJM's reserve margin is 18 percent, which is considerably higher than the reserve margin in California. The two markets have also operated differently. Considerable price risk for California utilities resulted from requirements to sell a significant portion of their generation assets and, until recently, buy their energy from the spot market (longer-term forward contracts were not permitted). In contrast, PJM utilities have not been required to divest of their generation assets and have been permitted to lock in prices through long-term contracts, and to mitigate risk with use of other hedging instruments. Finally, California is highly dependent on gas-fired and hydro electric generation, both of which are highly dependent on weather. In contrast, PJM has a more diverse fuel mix, including a substantial base of coal and nuclear generators.
Nuclear Power Plants ACE owns 5% of Hope Creek Nuclear Generating Station (Hope Creek), which has 1,031 MW of capacity, 7.41% of Salem, which has 2,212 MW of capacity excluding the on-site combustion turbine, and 7.51% of Peach Bottom, which has 2,186 MW of capacity. The Hope Creek Unit and Salem Units 1 and 2 are located adjacent to each other in Salem County, New Jersey, and are operated by PSE&G. Peach Bottom Units 2 and 3 are located in York County, Pennsylvania, and are operated by PECO Energy Company (PECO).
As discussed above under "Agreements for the Sale of Electric Generating Plants," the agreements for the sale of ACE's interests in the nuclear plants (164 MW in Peach Bottom, 167 MW in Salem, and 52 MW in Hope Creek) provide for (a) a sales price of approximately $1 I million plus the net book value of the interests of ACE in nuclear fuel on-hand as of the closing date and (b) the transfer of ACE's nuclear decommissioning funds and related obligation for decommissioning the plants to the purchasers upon completion of the sales. The net book value of ACE's ownership interests in the nuclear plants subject to agreements for sale was $14.5 mil lion as of December 31, 2000.
The operation of nuclear generating units is regulated by the Nuclear Regulatory Commission (NRC). Such regulation requires that all aspects of plant operations be conducted in accordance with NRC safety and environ mental requirements and that continuous demonstrations be made to the NRC that plant operations meet applica ble requirements. The NRC has the ultimate authority to determine whether any nuclear generating unit may operate.
For information concerning funding ACE's share of the estimated future cost of decommissioning the Salem. Hope Creek. and Peach Bottom nuclear reactors, see Note 13 to the Consolidated Financial Statements included in Item 8 of Part II.
Fuel Supply for Electric Generation The electric generating capacity of ACE by fuel type is shown above under "Electric Generating Plants." To facilitate the purchase of adequate amounts of fuel, ACE contracts with various suppliers of coal, oil, and natural gas on both a long- and short-term basis. Prices under oil and natural gas contracts are generally determined by market-based indices.
ACE's obligations for coal and oil supply contracts related to the fossil fuel-fired electric generating units to be sold are expected to be assumed by NRG Energy. Inc.. the party which has agreed to purchase the fossil fuel-fired plants. Under the sales agreements for ACE's interests in nuclear generating units, ACE will receive
1-5 proceeds for the book value of the nuclear fuel inventories, which are expected to be used to liquidate ACE's obligations for the lease of the nuclear fuel inventories.
Management does not anticipate any difficulty in obtaining adequate amounts of fuel for ACE's electric generating plants.
Coal During 2000, the coal for ACE's coal-fired units was purchased under contracts expiring in 2002 (repre senting 80% of 2000 coal requirements) and on the spot market (representing 20% of 2000 coal requirements). During 2001, management expects that approximately 75% of coal requirements will be purchased under supply contracts and the other 25% purchased on the spot market.
Oil All of the oil used by ACE's oil-fired electric generating units is purchased on a spot basis.
Gas The 19 MW combustion turbine located at Deepwater uses natural gas as a primary fuel source and the units at the Deepwater station, which use coal and oil as primary fuels, use natural gas as a secondary fuel. Natural gas for the combustion turbine and the Deepwater station is primarily purchased from a local gas distribution company on a semi-firm basis and is also purchased from other suppliers such as marketers, produc ers, and utilities. Natural gas is delivered through the interstate pipeline system under a mix of long-term firm, short-term firm, and interruptible contracts.
Nuclear PSE&G has informed ACE that it has several long-term contracts with uranium ore operators, converters, enrichers and fabricators to meet the currently projected fuel requirements for Salem and Hope Creek. ACE has also been advised by PECO that it has contracts similar to PSE&G's contracts to satisfy the fuel requirements of Peach Bottom. Currently, there is an adequate supply of nuclear fuel for Salem, Hope Creek, and Peach Bottom.
After spent fuel is removed from a nuclear reactor, it is placed in temporary storage for cooling in a spent fuel pool at the nuclear station site. Under the Nuclear Waste Policy Act of 1982 (NWPA), the federal govern ment entered into contracts with utilities operating nuclear power plants for transportation and ultimate disposal of spent nuclear fuel and high level radioactive waste. However, no permanent government-owned and operated repositories are in service or under construction. The United States Department of Energy has stated that it would not be able to open a permanent, high level nuclear waste storage facility until 2010, at the earliest.
Pursuant to NRC rules, spent nuclear fuel generated in any reactor can be stored in reactor facility storage pools or in independent spent nuclear fuel storage installations located at or away from reactor sites for at least 30 years beyond the licensed life for operation (which may include the term of a revised or renewed license). PSE&G has advised ACE that adequate spent fuel storage capacity is estimated to be available through 2011 for Salem Unit 1, 2015 for Salem Unit 2, and 2007 for Hope Creek. PECO has advised ACE that it has constructed an on-site dry storage facility at Peach Bottom which provides adequate storage capacity through the end of the current licenses for the two Peach Bottom units.
Electric Energy Adjustment Clause Through July 31, 1999, ACE's tariffs for its electric customers included energy adjustments for fuel costs, purchased energy costs, and capacity purchased from non-utility electricity suppliers. Effective August 1, 1999, through various components of regulated rates, the rates charged to ACE's BGS customers for electricity supply.
1-6 include ACE's fuel costs, purchased energy costs, and capacity purchased from non-utility electricity suppliers. For additional information, see "Basic Generation Service" above.
Retail Electric Rates In its Summary Order, the NJBPU directed ACE to implement a 5% aggregate rate reduction effective August 1, 1999 and an additional 2% rate reduction by January 1, 2001. By August 1, 2002, rates must be reduced by 10% from the rates that were in effect as of April 30, 1997. The initial 5% rate reduction effective August 1, 1999 reduced annual revenues by approximately $50 million. The additional 2% rate reduction required by January 1, 2001 was implemented through two separate 1% rate reductions effective January 1, 2000 and 2001, respectively. Each of the 1% rate reductions reduces annual revenues by approximately $10 million, or $20 million in total. The final rate reduction, which is required by August 1, 2002, is expected to reduce revenues by an additional $30 million, which would result in a cumulative rate reduction of $100 million since August 1, 1999.
For additional information concerning the impact of electric utility industry restructuring on customer rates, see Note 7 to the Consolidated Financial Statements included in Item 8 of Part II.
New Jersey Electric System Reliability Standards In November 1999, the NJBPU began a general review of the reliability of the electric systems of ACE and all other New Jersey utilities. The NJBPU began its review as a result of electric service outages which occurred during an extended period of hot and humid weather in July 1999. On November 28, 2000, the NJBPU approved interim reliability standards which are in effect through 2002 and are designed to reduce outage frequency and duration, as well as improve maintenance and inspection of electric facilities. Final reliability standards are expected to be adopted in late-2002, after the NJBPU reviews data submitted by the utilities. Expenditures of approximately $5 million are expected by ACE during 2001 in order to comply. The NJBPU could fine utilities up to $50,000 per violation of the rule requirements.
New Jersey Demand Side Management The NJBPU adopted rules in 1991 to encourage utilities to offer demand side management (DSM) and conservation services. The New Jersey Act requires the continuation of these energy efficiency programs and the initiation of renewable energy programs, the costs of which are to be recovered through a societal benefits charge to electric and gas customers of New Jersey public utilities. On June 9, 1999, the NJBPU initiated the Compre hensive Resource Analysis (CRA) proceeding causing a comprehensive resource analysis of energy programs to be undertaken including the re-evaluation of existing DSM programs and the incorporation of new energy efficiency and renewable energy programs. A key issue in the CRA proceeding is the determination of the appropriate level of funding for energy efficiency and renewable energy programs on a statewide basis. Hearings have been conducted and a record has been established to permit the NJBPU to render decisions for each New Jersey utility in lieu of settlements, if necessary. A decision by the NJBPU is expected in 2001.
Affiliated Transactions On March 15, 2000, the NJBPU adopted Interim Affiliate Relations, Fair Competition and Accounting Standards and Related Reporting Requirements (Interim Standards). These Interim Standards will remain in effect for no longer than 18 months, until final standards are issued by the NJBPU. A compliance audit of these interim standards was conducted during 2000 and a final order is pending by the NJBPU.
Federal Decontamination & Decommissioning Fund The Energy Policy Act of 1992 provided for creation of a Decontamination & Decommissioning (D&D) Fund to pay for the future clean-up of DOE gaseous diffusion enrichment facilities. Domestic utilities and the
1-7 federal government are required to make payments to the D&D Fund. The liability accrued for ACE's D&D Fund liability was $5.1 million as of December 31, 2000. The terms of agreements for the sale of ACE's interests in the nuclear power plants provide for the buyers of the plants to assume the amount of this liability which exists at the time the sale is completed.
Capital Spending and Financing Program
For financial information concerning ACE's capital spending and financing program, refer to "Liquidity and Capital Resources" in the MD&A included in Item 7 of Part II and Notes 16 and 17 to the Consolidated Financial Statements, included in Item 8 of Part II.
ACE's ratios of earnings to fixed charges and earnings to fixed charges and preferred stock dividends under the Securities and Exchange Commission (SEC) Methods for 2000-1996 are shown below.
Year Ended December 31, 2000 1999 1991 1997 1996 Ratio of Earnings to Fixed Charges (SEC Method) ...... 2.03 2.57 1.66 2.84 2.59 Ratio of Earnings to Fixed Charges and Preferred Stock Dividends (SEC M ethod) ...... 1.95 2.44 1.55 2.58 2.16
For purposes of computing the above ratios, earnings, including Allowance For Funds Used During Con struction, are income before extraordinary item plus income taxes and fixed charges. Fixed charges include gross interest expense, the estimated interest component of rentals, and dividends on preferred securities of a subsidiary trust. For the ratio of earnings to fixed charges and preferred dividends, preferred stock dividends represent preferred stock dividend requirements multiplied by the ratio that pre-tax income bears to net income.
Environmental Matters ACE is subject to various federal, regional, state, and local environmental regulations, including air and water quality control, oil pollution control, solid and hazardous waste disposal, and limitation on land use. Permits are required for construction projects and the operation of existing facilities. ACE has incurred, and expects to continue to incur, capital expenditures and operating costs because of environmental considerations and requirements. Included in ACE's forecasted capital requirements are construction expenditures for compli ance with environmental regulations, which are estimated to be $1 million in 2001.
ACE has a continuing program to assure compliance with the environmental standards adopted by various regulatory authorities.
Air QualitY Regulations The federal Clean Air Act required utilities and other industries to significantly reduce emissions of air pollutants such as sulfur dioxide (SO2) and oxides of nitrogen (NO1 ) by the year 2000. All wholly or jointly owned electric generating units of ACE are in compliance with these requirements.
The electric generating plants of ACE have complied with Title I of the Clean Air Act, the ozone non-at tainment provisions, which require states to promulgate Reasonably Available Control Technology (RACT) regulations for existing sources located within ozone non-attainment areas or within the Northeast Ozone Trans port Region (NOTR). Additional "post-RACT" NO, emission regulations are being pursued by states in the NOTR. In 2000, the electric generating plants of ACE complied with post-RACT requirements. In addition to the above requirements, the United States Environmental Protection Agency (USEPA) has proposed summer seasonal NO, controls commensurate with reductions of up to 85% below baseline years by the year 2003 for a 22-state region, including New Jersey. Since the State of New Jersey will require a greater percent reduction
1-8 than that required by the USEPA, the ACE facilities will most likely achieve compliance with the USEPA requirement by 2003. The estimated cost to comply is approximately $5-$8 million over the next five years.
In July 1997, the USEPA adopted new federal air quality standards for particulate matter and ozone. The new particulate matter standard addresses fine particulate matter. Attainment of the fine particulate matter stan dard may require reductions in NO. and S02. However, under the time schedule announced by the USEPA, particulate matter non-attainment areas will not be designated until 2002 and control measures to meet this standard will not be identified until 2005.
The USEPA requested data from a number of electric utilities regarding older coal-fired units in order to determine compliance with the regulations for the Prevention of Significant Deterioration of Air Quality (PSD). A number of settlements have been announced throughout the utility industry. On February 23, 2000, ACE received a request for data from the USEPA and the New Jersey Department of Environmental Protection (NJDEP) on coal-fired operations at the Deepwater and B.L. England electric generating stations. Data was submitted, as requested by the USEPA throughout 2000. At this time it is not possible to predict the impact of this request, if any, on Deepwater or B.L. England operations.
Water Quality Regulations
The Clean Water Act provides for the imposition of effluent limitations to regulate the discharge of pollu tants, including heat, into the waters of the United States. National Pollution Discharge Elimination System (NPDES) permits issued by state environmental regulatory agencies specify effluent limitations, monitoring requirements, and special conditions with which facilities discharging waste-waters must comply. To ensure that water quality is maintained, permits are issued for a term of five years and are modified as necessary to reflect requirements of new or revised regulations or changes in facility operations.
ACE holds New Jersey Pollution Discharge Elimination System (NJPDES) permits issued by the NIDEP for the Deepwater and B.L. England power stations. The NJPDES permit for the Deepwater Station expired in 1991. The permit has been administratively extended and the plant continues to operate under the conditions of the existing permit while negotiations are underway for permit renewal. The NJPDES permit for the B.L. England station expired in December 1999, but has been administratively extended and the plant continues to operate under the conditions of the existing permit until a renewal permit is issued by NJDEP.
Hazardous Substances
The nature of the electric business results in the production or handling of various by-products and sub stances, which may contain substances defined as hazardous under federal or state statutes. The disposal of hazardous substances can result in costs to clean up facilities found to be contaminated due to past disposal practices. Federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or uncontrolled hazardous waste sites. ACE's exposure is minimized by adherence to envi ronmental standards for ACE-owned facilities and through a waste disposal contractor screening and audit process.
ACE had accrued a current liability of $1.0 million as of December 31, 2000 and 1999 for clean-up and other potential costs related to federal and state superfund sites. ACE does not expect such future costs to have a material effect on its financial position or results of operations. For additional information, see Note 22 to the Consolidated Financial Statements included in Item 8 of Part II.
1-9 Executive Officers The names, ages, and positions of all of the executive officers of ACE as of December 31, 2000, are listed below, along with their business experiences during the past five years. Officers of ACE are elected annually by ACE's Board of Directors. There are no family relationships among these officers, nor any arrangement or understanding between any officer and any other person pursuant to which the officer was selected.
Executive Officers of ACE (As of December 31, 2000)
Name, Age and Position Business Experience During Post 5 Years Joseph M. Rigby, 44 ...... Elected 2000 as Senior Vice President of Conectiv and President President of Atlantic City Electric Company. 1999, Vice President, Electric Delivery, Conectiv. 1998, Vice President, Gas Delivery, Conectiv. 1997, Vice President, Merger Integration Team, Conectiv. 1996, Director of Human Resources, Atlantic Energy, Inc. John C. van Roden, 51 ...... Elected 2000 as Senior Vice President and Chief Financial Officer Chief Financial Officer of Conectiv and Chief Financial Officer of Atlantic City Electric Company. Elected 1998 as Senior Vice President and Chief Financial Officer of Conectiv. Principal, Cook and Belier, Inc. in 1998. Senior Vice President/Chief Financial Officer and Vice I4 Presidentflreasurer,Lukens, Inc. from 1987 to 1998. James P. Lavin, 53 ...... Elected 1998 as Controller of Conectiv and Atlantic City Electric Controller and Chief Accounting Officer Company. Elected 1993 as Comptroller, Delmarva Power & Light Company.
1-10 ITEM 2. PROPERTIES Generating Capacity Electric Generating Station Location (kilowatts) Coal-Fired B L England ...... Beesley's Pt., NJ ...... 284,000 Conemaugh ...... New Florence, PA ...... 65,000* Keystone ...... Shelocta, PA ...... 42,000* Deepwater ...... Pennsville, NJ ...... 80,000 471,000 Oil-Fired B L England ...... Beesley's Pt., NJ ...... 155,000 Deepwater ...... Pennsville, NJ ...... 86,000 241,000 Combustion Turbines Deepwater ...... Pennsville, NJ ...... 19,000 Salem ...... Lower Alloways Creek Twp., NJ.. 3,000* 22,000 Nuclear Peach Bottom ...... Peach Bottom Twp., PA ...... 164,000* Salem ...... Lower Alloways Creek Twp., NJ.. 164,000* Hope Creek ...... Lower Alloways Creek Twp., NJ.. 52,000* 380,000 Diesel Units B L England ...... Beesley's Pt., NJ ...... 8,000 K eystone ...... Shelocta, PA ...... 300* Conem augh ...... New Florence, PA ...... 400* 8,700 Total Electric Generating Capacity ...... 1,122,700
* Represents ACE's ownership interest in jointly-owned plants. The above table sets forth the summer electric capacity of the electric generating plants of ACE. Substantially all utility plants and properties of ACE are subject to the lien of the Mortgage under which First Mortgage Bonds are issued. The electric transmission and distribution systems of ACE includes 1,231 transmission poleline miles of overhead lines, 9,419 distribution poleline miles of overhead lines, and 1,198 distribution cable miles of under ground cables.
ITEM 3. LEGAL PROCEEDINGS On October 24, 2000, the City of Vineland, New Jersey, filed an action in a New Jersey Superior Court to acquire by eminent domain ACE electric distribution facilities located within the City limits. The City has offered approximately $11 million for these assets, including the right to provide electric service in this area. ACE believes that, properly evaluated, the assets sought by the City are worth approximately $40 million.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matter was submitted during the fourth quarter of the fiscal year covered by this report to a vote of security holders, through the solicitation of proxies or otherwise.
1-11 ATLANTIC CITY ELECTRIC COMPANY
PART H
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS All shares of ACE's common stock are owned by Conectiv, its parent company.
ACE's certificate of incorporation requires payment of all preferred dividends in arrears (if any) prior to payment of common dividends to Conectiv, and has certain other limitations on the payment of common dividends.
As a subsidiary of a registered holding company under PUHCA, ACE can pay dividends only to the extent of its retained earnings unless SEC approval is obtained.
1I-1 ATLANTIC CITY ELECTRIC COMPANY
ITEM 6. SELECTED FINANCIAL DATA
Year Ended Deember 31, 2000 1999(1) 1998(2) 1997(3) 1996 (Dollars in Thousands) Operating Results Operating Revenues ...... $ 968,383 $1,076,585 $1,039,750 $1,084,890 $ 989,647 Operating Income ...... 166,524 171,931 108,868 190,052 165,120 Income Before Extraordinary Item ...... 54,434 63,930 30,276 85,747 75,017 Extraordinary Item, Net of Income Taxes of $40,474 (4) ...... (58,095) Net Income ...... 54,434 5,835 30,276 85,747 75,017 Earnings Applicable to Common Stock ..... 52,302 3,703 29,385 80,926 65,113 Capitalization Common Stockholder's Equity ...... $ 580,119 $ 677,951 $ 730,093 $ 783,033 $ 778,425 Preferred Stock Not Subject to Mandatory Redemption 6,231 6,231 6,231 30,000 30,000 Subject to Mandatory Redemption ..... 23,950 23,950 23,950 33,950 43,950 Preferred Securities of Subsidiary Trusts Subject To Mandatory Redemption ...... 95,000 95,000 95,000 70,000 70,000
, , Variable Rate Demand Bonds (VRDB) (5)... 22,600 22,600 22,600 22,600 Long-Term Debt ...... 857,653 954,752 791,127 811,144 802,245 Total Capitalization with VRDB ...... $1,585,553 $1,780,484 $1,669,001 $1,750,727 $1,724,620 Other Information Total Assets ...... $2,481,382 $2,654,659 $2,367,222 $2,436,755 $2,460,741 Long-Term Capital Lease Obligations ...... 12,872 14,911 19,523 24,077 24,212 Capital Expenditures ...... 53,717 48,931 71,342 80,896 88,914 Common Dividends Declared (6) ...... 67,309 55,845 81,450 80,857 82,163 (1) As discussed in Note 4 to the Consolidated Financial Statements, Atlantic City Electric Company (ACE) and Delmarva Power & Light Company (DPL) became wholly-owned subsidiaries of Conectiv (the 1998 Merger) on March 1, 1998. In 1999, special charges for employee separations, additional costs related to the 1998 Merger, and other non-recurring costs reduced operating income by $12.3 million and income before extraordinary item, net income, and earnings applicable to common stock by $7.3 million. (2) In 1998, special charges for the costs of 1998 Merger-related employee separations and relocations and other 1998 Merger-related charges reduced operating income by $61.1 million and income before extraordi nary item, net income, and earnings applicable to common stock by $36.6 million. Also, in 1998, the write down to fair value of certain operational and administrative facilities to be sold due to the Merger reduced operating income by $18.0 million and income before extraordinary item, net income, and earnings applica ble to common stock by $10.6 million. (3) In 1997, special charges for 1998 Merger-related employee separation benefits reduced operating income by $22.6 million and income before extraordinary item, net income, and earnings applicable to common stock by $15.6 million. (4) As discussed in Note 6 to the Consolidated Financial Statements, the extraordinary item in 1999 resulted from the restructuring of the electric utility industry and discontinuing the application of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation." (5) Although Variable Rate Demand Bonds are classified as current liabilities, ACE intends to use the bonds as a source of long-term financing as discussed in Note 17 to ACE's Consolidated Financial Statements. (6) Amounts shown as total, rather than on a per-share basis, since ACE is a wholly-owned subsidiary of Conectiv.
11-2 ATLANTIC CITY ELECTRIC COMPANY ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS The Private Securities Litigation Reform Act of 1995 (Litigation Reform Act) provides a "safe harbor" for forward-looking statements to encourage such disclosures without the threat of litigation, provided those state ments 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 "intend," "will," "anticipate," "estimate," "expect," "believe," 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: the effects of deregulation of energy supply and the unbundling of delivery services; the ability to enter into purchased power agreements on acceptable terms; market demand and prices for energy, capacity, and fuel; weather variations affecting energy usage; operating performance of power plants; an increasingly competitive marketplace; results of any asset dispositions; sales retention and growth; federal and state regulatory actions; future litigation results; costs of construction; operating restrictions; increased costs and construction delays attributable to environmental regulations; nuclear decommissioning and the availability of reprocessing and storage facilities for spent nuclear fuel; and credit market concerns. Atlantic City Electric (ACE) undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing list of factors pursuant to the Litigation Reform Act should not be construed as exhaustive or as any admission regarding the adequacy of disclosures made prior to the effective date of the Litigation Reform Act.
OVERVIEW ACE is a subsidiary of Conectiv, which is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA). On March 1, 1998, Conectiv was formed (the 1998 Merger) through an exchange of common stock with the former owner of ACE, Atlantic Energy, Inc. (Atlantic), and Delmarva Power & Light Company (DPL). In conjunction with the 1998 Merger, ACE became a Conectiv subsidiary and Atlantic was merged into Conectiv.
On February 9, 2001, the Boards of Directors of Conectiv and Potomac Electric Power Company (Pepco) approved an Agreement and Plan of Merger under which Pepco will acquire Conectiv for a combination of cash and stock. The transaction is subject to various statutory approvals and approval by the stockholders of Conectiv and Pepco. ACE is a public utility located in the southern one-third of New Jersey and supplies electricity to customers with power purchased from other suppliers and electricity generated by its power plants. A transition to market pricing and terms of service for supplying electricity in ACE's regulated service area began on August 1, 1999. All of ACE's customers can elect to choose an alternative electricity supplier. Effective July 1, 2000, Conectiv formed Conectiv Energy Holding Company (CEH), which has subsidiaries engaged in non-regulated electricity production and sales, and energy trading and marketing. In connection with forming CEH, ACE contributed at book value its combustion turbines (502 megawatts of electric generating capacity) and related transmission equipment, inventories, and liabilities to a wholly owned subsidiary, Conectiv Atlantic Generation, LLC (CAG), effective July 1, 2000. ACE then contributed CAG to Conectiv. The primary effects on ACE's balance sheet of the contribution to Conectiv were as follows: (a) property, plant and equipment decreased $86 million (primarily electric generating plants); (b) fuel and other inventories decreased $6 million; (c) deferred income taxes and investment tax credits decreased $9 million; and (d) the additional paid-in capital portion of common stockholder's equity decreased $83 million.
11-3 The electric generating plants of ACE had generating capacity of 1,122.7 megawatts (MW) as of Decem ber 31, 2000, compared to 1,624.7 MW as of December 31, 1999. The 502 MW decrease in electric generating capacity from 1999 to 2000 resulted from the contribution of the combustion turbines to Conectiv, effective July 1, 2000. During 1999 and 2000, as discussed below under "Agreements For The Sale of Electric Generating Plants," ACE entered into agreements for the sale of its nuclear and baseload fossil fuel-fired electric generating plants. All the electric generating plants owned by ACE as of December 31, 2000 were subject to the sales agreements. After the sales of the electric generating plants of ACE are completed, the principal remaining businesses of ACE will be the transmission and distribution of electricity. ACE will purchase power to supply electricity to customers who do not choose alternative electricity suppliers, as discussed under "Basic Generation Service."
ACE's exit from the business of electricity production is expected to cause a decrease in ACE's earnings capacity.
EARNINGS RESULTS SUMMARY Earnings applicable to common stock were $52.3 million for 2000, compared to $3.7 million for 1999. In 1999, earnings applicable to common stock of $3.7 million included (i) a $58.1 million extraordinary charge, after income taxes of $40.5 million, for discontinuing the application of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," (SFAS No. 71) to ACE's electricity supply businesses because of deregulation, and (ii) $7.3 million of special charges, net of taxes, primarily for the costs of 1998 Merger-related employee separations and relocations and other 1998 Merger ' .' related costs. For additional information concerning deregulation and the extraordinary charge to earnings, see Notes 1, 6, 7, 8 and 14 to the Consolidated Financial Statements and the "Electric Utility Industry Restructur ing" section within the MD&A.
As discussed in Note 6 to the Consolidated Financial Statements, ACE's 1999 extraordinary charge was based on a Summary Order issued by the New Jersey Board of Public Utilities (NJBPU) which addressed stranded costs, unbundled rates, and other matters related to restructuring. The NJBPU indicated that a more detailed order would be issued at a later time. If the NJBPU's final detailed order were to differ materially from the Summary Order, then another extraordinary item may result due to adjustment of the 1999 extraordinary charge. For information concerning a delay in the issuance of the NJBPU's final detailed order, see "Agreements for the Sales of Electric Generating Plants" in the MD&A.
Earnings of $52.3 million for 2000 represent a $16.8 million decrease from earnings of $69.1 million for 1999, adjusted to exclude the 1999 extraordinary and special charges. The $16.8 million decrease in earnings (excluding the extraordinary and special charges) was primarily due to lower electricity sales during the summer when average rates are higher, lower customer rates related to electric utility industry restructuring, and higher interest expense, partly offset by the benefit of lower operating expenses and a lower effective income tax rate.
In 1998, earnings applicable to common stock were $29.4 million, after special charges of $47.2 million after taxes. The 1998 special charges were comprised of (i) $36.6 million after taxes for the costs of 1998 Merger-related employee separations and relocations and other 1998 Merger-related costs, and (ii) $10.6 million after taxes for the write-down to fair value of certain operational and administrative facilities to be sold, as a result of the 1998 Merger.
Excluding the extraordinary and special charges, earnings applicable to common stock decreased to $69.1 million in 1999 from $76.6 million in 1998. The $7.5 million earnings decrease was primarily due to higher operation and maintenance expenses and the customer rate decreases which resulted from the electric utility industry restructuring, partly offset by additional revenues from higher regulated sales of electricity to retail customers. The decrease also reflects a higher effective income tax rate and the absence of the $2.5 million gain in 1998 from the redemption of preferred stock.
11-4 ELECTRIC UTILITY INDUSTRY RESTRUCTURING Based on the NJBPU's Summary Order, ACE determined that the requirements of SFAS No. 71 no longer applied to its electricity supply business as of August 1, 1999. As a result, ACE discontinued applying SFAS No. 71 and applied the requirements of SFAS No. 101, "Regulated Enterprises-Accounting for the Discontinu ation of Application of FASB Statement No. 7 1" (SFAS No. 101) and Emerging Issues Task Force (EITF) Issue No. 97-4, "Deregulation of the Pricing of Electricity-Issues Related to the Application of FASB Statements No. 71 and No. 101" (EITF 97-4), which among other things, resulted in an extraordinary charge to earnings of $58.1 million, net of $40.5 million of income taxes. The provisions of the NJBPU's Summary Order are summarized below.
Revenue Reductions Pursuant to the NJBPU's Summary Order, electric rate decreases became effective on the dates shown in the table below. Estimated Annuafized Revenue Decrease Effective Date $50.0 million, or 5% ...... August 1, 1999 $10.0 million, or 1% ...... January 1, 2000 $10.0 million, or 1% (1) ...... January 1, 2001 (1) In addition, by August 1, 2002, rates must be ten percent lower than the rates that were in effect April 30, 1997. This rate decrease is expected to result in an additional $30 million revenue reduction.
Regulatory Implications on Sales of Electric Generating Plants Except for the Deepwater plant (185 MW of capacity), any gain or loss realized upon the sale of electric generating plants of ACE will affect the amount of ACE's recoverable stranded costs (discussed below), due to the terms of the Summary Order. Accordingly, any gain or loss realized by ACE on the sale of these plants would not affect future earnings. Any loss on the sale of the Deepwater plant, which was written down to fair value in the fourth quarter of 1999, cannot be recovered from ACE's customers.
Stranded Cost Recovery and Securitization Stranded costs are the uneconomic portion of assets and long-term contracts that resulted from electric utility industry restructuring. The NJBPU's Summary Order provides ACE the opportunity to recover 100% of the net stranded costs related to certain generation units to be divested and the stranded costs associated with power purchased from non-utility generators (NUGs). The Summary Order, in conjunction with the Electric Discount and Energy Competition Act (the New Jersey Act) also permits securitization of stranded costs through the issuance of transitibn bonds in the amount of the after-tax stranded cost recovery approved by the NJBPU. Management expects the transition bonds will be issued after completion of the sale of the electric generating units of ACE. The ability to issue transition bonds would depend not only upon approval of the NJBPU, but also on the conditions in the relevant capital markets at the times of the offerings. Proceeds from the transition bonds may be used to refinance ACE's debt and preferred securities, finance the restructuring of purchased power contracts, or otherwise reduce costs in order to decrease regulated electricity rates. Amounts designed to repay the principal of and interest on the transition bonds will be collected from customers through a transition bond charge. The income tax expense associated with the revenues from transition bond charges will be collected from customers through a separate market transition charge. As of December 31, 2000, the balance for ACE's pre-tax recoverable stranded costs was approximately $959 million, which includes the stranded costs estimated and recorded as a result of discontinuing the application of SFAS No. 71 during 1999 and the $228.5 million payment in December 1999 to terminate a NUG contract (see "Termination and Restructuring of Purchased Power Contracts" below). ACE's amount of recoverable stranded costs remains subject to adjustment based on the actual gains and losses realized on the sale of certain electric generating plants, additional buyouts or buydowns of NUG contracts, the NJBPU's final restructuring order, and the final amount determined to be recoverable through customer rates under the New Jersey Act.
I1-5 Shopping Credits
Customers who choose an alternative electricity supplier receive a credit to their bill, or a shopping credit, which generally represents the cost of electricity supply and transmission service.
Basic Generation Service
Through July 31, 2002, under New Jersey's Basic Generation Service (BGS), ACE is obligated to supply electricity to customers who do not choose an alternative electricity supplier. In accordance with the Summary Order, ACE supplies the BGS load requirement primarily with power purchased under its NUG contracts and the output generated by certain units to be sold. To replace the output of the generating units to be sold, ACE plans to increase the amount of power it purchases to supply the BGS load. ACE intends to manage BGS supply requirements (net of sources otherwise available to it at any particular time) through the use of a portfolio approach, including the use of competitive bidding. ACE's customer rates are designed to recover the costs of providing BGS service, including above-market portions of NUG power. As a result, ACE recognizes revenues for BGS service equal to the related costs incurred. Any difference between such revenues and costs results in a related adjustment to "Deferred energy supply costs." ACE's customer rates are to be adjusted for any deferred balance remaining after the initial four-year transition period ends July 31, 2003. ACE's recovery of BGS supply costs is subject to review by the NJBPU.
Termination and Restructuring of Purchased Power Contracts
On November 10, 1999, the NJBPU issued an order approving termination of a contract under which ACE had purchased energy and 116 MW of capacity from a NUG partnership (Pedricktown Co-generation Limited Partnership, or "Pedricktown"), which is owned 50% by other Conectiv subsidiaries. The NJBPU order pro vided that ACE is entitled to recover from customers the contract termination payment of $228.5 million, transaction costs, and interim financing costs. The NJBPU order also found that the contract termination payment and related transaction costs are eligible for long-term financing through the issuance of transition bonds. On December 28, 1999, ACE paid $228.5 million to terminate the contract and borrowed funds to finance the contract termination payment (as discussed in Note 17 to the Consolidated Financial Statements). The contract termination payment and related costs are included in "Recoverable Stranded Costs" on the Consolidated Balance Sheets. ACE's customer rates were reduced by about 1% (approximately $10 million of revenues on an annualized basis) effective January 1, 2000 as a result of the net savings from the contract termination.
On December 6, 2000, the NJBPU approved ACE's payment on January 22, 2001 of $3.45 million in connection with restructuring ACE's purchased power contract with a NUG, American Ref-Fuel Company of Delaware Valley, L.P.
Management anticipates that securitization will ultimately be used to finance the stranded costs associated with the buyout or buydown of ACE's NUG contracts.
AGREEMENTS FOR THE SALE OF ELECTRIC GENERATING PLANTS
On September 30, 1999, Conectiv announced that ACE reached agreements to sell its ownership interests in nuclear electric generating plants to PSEG Power LLC (a subsidiary of Public Service Enterprise Group Incorporated) and PECO Energy Company (PECO). ACE's interests in the nuclear units that are subject to the sales agreements include a 7.51% (164 MW) interest in Peach Bottom, a 7.41% interest (167 MW) in Salem and a 5.0% interest (52 MW) in Hope Creek. These plants had a net book value of approximately $14.5 million as of December 31, 2000. The agreements for the sale of ACE's interests in the nuclear plants provide for (i) a sales price of approximately $11 million plus the net book value of the interests of ACE in nuclear fuel on-hand as of
11-6 the closing date and (ii) the transfer of ACE's nuclear decommissioning funds and related obligation for decommissioning the plants to the purchasers upon completion of the sales.
On January 19, 2000, Conectiv announced that ACE reached an agreement to sell certain wholly and jointly owned fossil fuel-fired units to NRG Energy, Inc. (NRG), a subsidiary of Northern States Power Company, for $178 million. The units to be sold to NRG have a total capacity of 739.7 MW, and had a net book value of $117.6 million as of December 31, 2000. Management expects the proceeds from the planned sales of the electric generating plants will be used to repay debt and to fund expansion of Conectiv's electric generation business. Some or all of ACE's proceeds from the sale of the electric generating plants could be paid as a dividend to Conectiv, or invested in Conectiv's pool of funds that Conectiv subsidiaries borrow from or invest in depending on their cash position.
Consummation of the sales of the electric generating plants is subject to the receipt of required regulatory approvals. In addition, the agreements for the sales of the electric generating plants contemplated that the sales of the plants of ACE and DPL, which is also selling its electric generating plants, would occur simultaneously. Appeals related to the NJBPU's final order concerning restructuring the electricity supply business of Public Service Electric and Gas Company (PSE&G) and recent electricity shortages and price increases in California have resulted in delays in the issuance of required regulatory approvals, the NJBPU's final order concerning restructuring the electricity supply business of ACE, and the closings of the sales of the electric generating units. Effective October 3, 2000, the agreements relating to the sale of the nuclear plants were amended to, among other things, permit separate closings of the sales of the ACE and DPL interests in the nuclear plants. DPL's ownership interests in nuclear electric generating plants were sold on December 29, 2000. On December 6, 2000, the New Jersey Supreme Court affirmed the judgment of the New Jersey Superior Court Appellate Division, which had previously upheld the NJBPU's final order concerning the PSE&G restructuring. Management cur rently expects the sales of ACE's nuclear and fossil electric generating plants to take place during 2001. Howev er, management cannot predict the timing of the issuance of required NJBPU approvals, the timing or outcome of appeals, if any, of such approvals, the effect of any of the foregoing on the ability of ACE to consummate the sales of various electric generating plants or the impact of any of the foregoing on ACE's ability to recover or securitize any related stranded costs.
As of December 31, 2000, $5.3 million of costs associated with selling the electric generating plants had been deferred as an adjustment to the expected future gain or loss on the sales. In the event the sales are not completed, these costs would be expensed.
WHOLESALE TRANSACTION CONFIRMATION LETTER AGREEMENTS On October 3, 2000, ACE entered into Wholesale Transaction Confirmation letter agreements (Letter Agree ments). The Letter Agreements provide for the sale of the electricity output and capacity associated with the ownership interests of ACE in Peach Bottom, Salem, and Hope Creek. PECO and PSEG Energy Resources & Trade LLC (PSER&T), an indirect subsidiary of Public Service Enterprise Group, purchase the electricity output and capacity from ACE under the Letter Agreements. The Letter Agreements became effective October 7, 2000, and terminate for each plant upon the earlier of (1) the closing of the sale of the plant, (2) the termination of the agreement relating to the sale of the plant or (3) September 30, 2001.
In exchange for the electricity output and capacity purchased from a given plant, PECO and PSER&T reimburse ACE for the nuclear fuel amortized during the term of the Letter Agreements at each plant, and are responsible for the payment of operation and maintenance costs, inventories, capital expenditures (subject, in certain circumstances, to reimbursement by ACE) and certain other liabilities associated with the ownership interests of ACE in each plant.
11-7 OPERATING REVENUES 2000 (Dollan1999 1991 -in miious) Regulated electric revenues ...... $916.8 $1,048.6 $1,003.3 Non-regulated electric revenues ...... 40.7 19.9 31.6 Other revenues ...... 10.9 8.1 4.8 Total operating revenues ...... $968.4 $1,076.6 $1,039.7
The table above shows the amounts of electric revenues earned which are subject to price regulation (Regulated) and which are not subject to price regulation (Non-regulated). "Regulated electric revenues" include revenues for delivery (transmission and distribution) service and BGS. In 2000, "Regulated electric revenues" decreased by $131.8 million to $916.8 million, from $1,048.6 million for 1999. In 1999, "Regulated electric revenues" increased by $45.3 million to $1,048.6 million, from $1,003.3 million for 1998. The gross margin (revenues less fuel and purchased power costs) earned from regulated electricity sales decreased by approximately $62.6 million in 2000 and increased by approximately $24.5 million in 1999. Details of the variances in "Regulated electric revenues" are shown below. Increase eawe) in Regulated Electric Revenues 2000 compared 1999 compared to 1999 to 1991 (Dollars In millions)
, , Customers choosing alternative electricity suppliers ...... $ (86.0) $ (0.5) Decrease in retail rates for electric utility industry restructuring .... (38.9) (23.5) Revenue adjustment related to BGS cost recovery ...... 0.3 17.2 Variance in volumes of interchange sales ...... 4.0 5.0 Retail sales volume, sales mix, and all other ...... (11.2) 47.1 $(131.8) $45.3
As a result of customers choosing alternative electricity suppliers, "Regulated electric revenues" decreased by $86.0 million in 2000 and by $0.5 million in 1999. The revenue decrease was larger in 2000 mainly because actual purchases of electricity by customers from alternative suppliers did not begin until late-1999, even though customers could begin choosing alternative suppliers effective August 1, 1999. Regulated retail electricity delivery sales increased 0.5% in 2000 and 2.6% in 1999. Although regulated retail electricity sales increased 0.5% in 2000, milder weather caused electricity sales to decrease during the summer when average customer rates are higher. The milder summer weather in 2000 was the primary cause of the $11.2 million revenue decrease shown above as "Retail sales volume, sales mix, and all other." Similarly, the $47.1 million revenue increase in 1999 shown above as "Retail sales volume, sales mix, and all other" was mainly due to hotter summer weather. "Non-regulated electric revenues" include revenues from the combustion turbines and Deepwater electric generating plant which became deregulated on August 1, 1999. Upon the transfer of the combustion turbines to Conectiv on July 1, 2000, "non-regulated electric revenues" (and expenses) from these units were excluded from ACE's results of operations. ACE's non-regulated electricity generation business will end upon completion of the sale of the Deepwater electric generating plant, which is expected to occur in 2001. "Non-regulated electric revenues" increased $20.8 million for 2000 compared to 1999, mainly due to the timing of deregulation which resulted in a longer period of deregulated power plant operations in 2000. "Non regulated electric revenues" decreased $11.7 million for 1999 because revenues from electric trading activities for 1998 were higher than revenues earned in the second half of 1999 from ACE's deregulated electric generating units. However, the gross margin earned in 1999 from the deregulated electric generating units was higher than the gross margin earned from 1998 electricity trading activities.
11-8 OPERATING EXPENSES
Electric Fuel and Purchased Energy and Capacity "Electric fuel and purchased energy and capacity" decreased $59.6 million for 2000 compared to 1999 mainly due to lower average costs, reflecting termination of the Pedricktown purchased power agreement in December 1999, and prior year costs recorded pursuant to the energy adjustment clause, which was eliminated effective August 1, 1999. "Electric fuel and purchased energy and capacity" decreased $2.3 million in 1999 due to lower volumes of energy supplied for non-regulated electricity sales, largely offset by higher volumes of energy supplied for regulated retail electricity sales and higher average energy costs.
Special Charges ACE's operating results for 1999 include special charges of $12.3 million before taxes ($7.3 million after taxes) for the cost of planned employee separations, additional costs related to the 1998 Merger and certain other nonrecurring costs.
ACE's operating results for 1998 include special charges of $61.1 million before taxes ($36.6 million after taxes) for the costs of 1998 Merger-related employee separations and relocations and other 1998 Merger-related costs and $18.0 million before taxes ($10.6 million after taxes) for the write-down to fair value of certain operational and administrative facilities to be sold, as a result of the 1998 Merger.
Operation and Maintenance Expenses In 2000, operation and maintenance expenses decreased $10.3 million primarily due to lower costs for pension and other postretirement benefits. In 1999, operation and maintenance expenses increased $39.4 million due to higher costs for the electric delivery business, including customer care expenses, higher power plant maintenance expenses, higher administrative costs, and lower capital expenditures which caused proportionately more resources to be expensed and less resources to be capitalized.
Depreciation and Amortization In 2000, depreciation and amortization expenses decreased $12.2 million mainly due to the contribution of the combustion turbines to Conectiv on July 1, 2000 and the write-downs in the third and fourth quarters of 1999 of electric generating plants in connection with restructuring the electric utility industry in New Jersey. Depreciation expense for capital improvements to the electric transmission and distribution systems recently placed in-service and amortization of "Recoverable stranded costs" partly offset the decrease from lower depre ciation of power plants.
Taxes Other Than Income Taxes Taxes other than income taxes decreased $8.4 millicr. in 2000 mainly due to a decrease in New Jerscy's transitional energy facility assessment, which is being phased out over a five-year period that ends December 31, 2003.
INTEREST EXPENSE In 2000, interest charges, net of amounts capitalized, increased $15.8 million primarily due to interest charges on $228.5 million borrowed in December 1999 to finance the payment to terminate the Pedricktown purchased power contract. In 1999, interest expense, net of amounts capitalized, decreased $3.2 million mainly due to lower balances of long- and short-term debt.
DIVIDENDS ON PREFERRED SECURITIES AND PREFERRED STOCK "Preferred stock dividend requirements on preferred securities of subsidiary trusts" increased $1.6 million in 1999 due to the issuance of $25 million of 73A% preferred securities in November 1998. "Dividends on
II-9 preferred stock" decreased $1.3 million in 1999 due to ACE's October 1998 purchase of $23.8 million of various series of its preferred stock (4.4% average dividend rate). As a result of the October 1998 purchase of preferred stock, ACE realized a gain of $2.5 million that is included in ACE's 1998 results of operations.
INCOME TAXES Income taxes decreased $12.6 million in 2000, primarily due to lower pre-tax income and also due to a lower effective income tax rate. Income taxes increased $31.1 million in 1999 mainly due to higher pre-tax income and also due to a higher effective income tax rate.
NEW ACCOUNTING STANDARD ACE implemented the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), as amended, effective January 1, 2001. SFAS No. 133 establishes accounting and reporting standards for derivative instruments and for hedging activities. SFAS No. 133 requires all derivative instruments, within the scope of the statement, to be recognized as assets or liabilities on the balance sheet at fair value. Changes in the fair value of derivatives that are not hedges, under SFAS No. 133, are recognized in earnings. The gain or loss on a derivative that hedges exposure to variable cash flow of a forecasted transaction is initially recorded in other comprehensive income (a separate component of common stockholder's equity) and is subsequently reclassified into earnings when the forecasted transaction occurs. Changes in the fair value of other hedging derivatives result in a change in the value of the asset, liability, or firm commitment being hedged, to the extent the hedge is effective. Any ineffective portion of a hedge is recognized in earnings immediately.
ACE's financial statements were not affected by the initial adoption of SFAS No. 133, effective January 1, 2001, because ACE did not hold derivative instruments as of December 31, 2000. To the extent ACE holds derivative instruments subsequent to initial adoption of SFAS No. 133, there may be increased volatility in ACE's earnings, revenues and common stockholder's equity.
LIQUIDITY AND CAPITAL RESOURCES
General ACE's primary sources of capital are internally generated funds (net cash provided by operating activities less common and preferred dividends) and external financings. Additionally, restructuring the electric utility industry has created new opportunities for raising capital. As discussed under "Agreements For The Sale Of Electric Generating Plants," ACE plans to sell electric generating units with 1,122.7 MW of capacity in 2001 for approximately $189 million, before certain adjustments and selling expenses. As discussed under "Stranded Cost Recovery and Securitization," capital is also expected to be raised through the securitization of ACE's stranded costs, subsequent to ACE's application to the NJBPU for approval of such securitization. Capital requirements generally include construction expenditures for the electric delivery business and electric generating units, repayment of debt, preferred stock, preferred securities, and capital lease obligations.
ACE's cash flows for 2000, 1999, and 1998 are summarized below.
2000 1999 1998 (Dolars in Millions) Cash Flows Provided / (Used) By: Operating Activities ...... $ 282.6 $ (33.3) $ 242.6 Investing Activities ...... (124.4) (121.6) (78.8) Financing Activities ...... (158.0) 134.1 (155.8) Net change in cash and cash equivalents ...... $ 0.2 $ (20.8) $ 8.0
11-10 Cash Flows From Operating Activities Cash flows from operating activities provided $282.6 million of cash in 2000 and used $33.3 million of cash in 1999 due to the $228.5 million payment by ACE in December 1999 to terminate its purchased power contract with Pedricktown. Excluding the $228.5 million contract termination payment, operating activities provided net cash of $195.2 million in 1999 compared to $282.6 million for 2000. This $87.4 million increase in cash flow for 2000 compared to 1999 was due to a $170.9 million decrease in income tax payments, partly offset by the effects of prior-year over-collections of energy costs from customers, lower electricity sales, rate decreases and higher interest expense payments. The decrease in income tax payments reflects $114.2 million of tax refunds received in 2000, which were primarily related to the December 1999 payment to terminate the Pedricktown purchased power contract. Cash flows from operating activities for 1999, excluding the Pedricktown contract termination payment, decreased $47.4 million to $195.2 million, from $242.6 million for 1998. The decrease reflects higher income tax payments and rate decreases. As of December 31, 2000, ACE had a balance of $10.2 million for accrued taxes payable, compared to a balance of $88.5 million for prepaid income taxes as of December 31, 1999. This variance resulted primarily from the income tax refunds received by ACE during 2000. ACE had a $34.7 million current liability for deferred energy supply costs related to its BGS as of December 31, 2000. This liability will decrease to the extent there are any under-recoveries of BGS and certain other costs. ACE's customers rates are to be adjusted for the deferred balance which remains as of July 31, 2003.
Cash Flows From Investing Activities The most significant items included in cash flows from investing activities during 2000, 1999, and 1998 are summarized below. Cash Provtded/(Used) 2006 1999 1998 (Dollars in MiUlions) Investment in Conectiv money pool ...... $ (74.4) $ (73.5) $ Capital expenditures ...... (53.7) (48.9) (71.3) All other investing cash flows, net ...... 3.7 0.8 (7.5) Net cash used by investing activities ...... $(124.4) $(121.6) $(78.8)
The $74.4 million and $73.5 million uses of cash in 2000 and 1999 for "Investment in Conectiv money pool" represent the incremental amount of ACE's investment in Conectiv's pool of funds that Conectiv subsidi aries borrow from or invest in, depending on their cash position. Capital expenditures were $53.7 million in 2000, $48.9 million in 1999, and $71.3 million in 1998. Capital expenditures for 2000 include transmission and distribution system upgrades to increase system reliability. Capital expenditures in 1999 decreased by $22.4 million from 1998 primarily due to a shift in the funding of expenditures for certain assets to Conectiv's service subsidiary. See "Overview" for information concerning the non-cash investing and financing transaction during 2000 involving the contribution to Conectiv of combustion turbines with 502 MW of electric generating capacity. Among other effects on the balance sheet, this transaction caused an $86 million decrease in property, plant and equipment and an $83 million decrease in common stockholder's equity.
Cash Flows From Financing Activities ACE pays a common dividend each quarter to Conectiv. Common dividends paid were $67.3 million in 2000, $59.3 million in 1999, and $81.5 million in 1998. As a subsidiary of a registered holding company under PUHCA, ACE can pay dividends only to the extent of its retained earnings unless SEC approval is obtained.
11-1l During 2000, 1999, and 1998, ACE's external financing activities primarily involved debt. Cash flows from debt financing activity are summarized below. Cash Provlded/(Used) Total 2000 1999 1998 (Dollars in millon) Long-term debt Issuances ...... $313.5 $ - $228.5 $ 85.0 Purchases & redemptions ...... (153.6) (46.1) (48.9) (58.6) Net ...... 159.9 (46.1) 179.6 26.4 Net change in short-term debt ...... (72.1) (30.0) 30.0 (72.1) Net financing activity for long- and short-term debt ...... $ 87.8 $(76.1) $209.6 $(45.7)
ACE redeemed $46.0 million of 6.83% Medium Term Notes at maturity on January 26, 2000 and repaid $0.1 million of other long-term debt during 2000. In 2000, ACE repaid the $30 million it borrowed on a short term basis during 1999 and had no short-term debt outstanding as of December 31, 2000.
ACE borrowed $228.5 million under a revolving credit facility on December 28, 1999 to provide interim financing for a payment made to terminate a purchased power contract with Pedricktown, as discussed in Note 17 to the Consolidated Financial Statements. In December 2000, ACE exercised its option to convert the revolving loan balance to a term loan, which is due in two installments; (1) 25% of the principal balance is due December 20, 2001, and (2) the remaining term loan principal is due December 20, 2002. ACE intends to repay this debt with proceeds from the expected issuance of transition bonds, which are discussed in Note 7 to the Consolidated Financial Statements.
During 1999, ACE repaid $48.9 million of long-term debt, including $30.0 million of Medium Term Notes (7.52% average interest rate) and $18.9 million of First Mortgage Bonds (6.87% average interest rate). In 1998, ACE issued $85.0 million of Medium Term Notes (6.1% average interest rate) and repaid $56.0 million of 6.26% Medium Term Notes and $2.6 million of 7.25% bonds.
In 1998, a subsidiary trust owned by ACE issued $25 million of 73A% preferred securities. In 1998, ACE also redeemed $10 million of its preferred stock subject to mandatory redemption ($8.20 annual dividend rate per $100 of preferred stock) and $23.8 million of various series of preferred stock not subject to mandatory redemption which had an average dividend rate of 4.4%.
ACE's capital structure as of December 31, 2000 and 1999, expressed as a percentage of total capitalization is shown below. December 31, December 31. 2000 1999 Common stockholder's equity ...... 34.5% 36.5% Preferred stock and preferred trust securities ...... 7.4% 6.7% Long-term debt and variable rate demand bonds ...... 52.3% 52.7% Short-term debt and current maturities of long-term debt ...... 5.8% 4.1% As discussed above, the contribution of combustion turbines to Conectiv during 2000 caused an $83 million decrease in common stockholder's equity. As a result, there was a decrease in common stockholder's equity as a percentage of total capitalization.
Forecasted capital requirements ACE's expected capital expenditures are estimated to be approximately $65 million in 2001, primarily for ACE's electric delivery business. During 2002 and 2003, capital expenditures for ACE's electric delivery busi ness are expected to range from $55 million to $65 million per year. Capital requirements for electric generating
11-12 plants have been reduced by the contribution of the combustion turbines to Conectiv in July 2000. After the expected sale in 2001 of ACE's temporarily retained electric generating plants, ACE would not have any electric generating plants or the related capital expenditure requirements.
Scheduled maturities of long-term debt over the next five years are as follows: 2001-$97.2 million; 2002 $221.5 million; 2003-$70.1 million; 2004-$67.1 million, 2005-$40.1 million. Future capital requirements are expected to be funded through internally generated funds and external financings.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS The following discussion contains "forward looking statements." These projected results have been pre pared based upon certain assumptions considered reasonable given the information currently available to ACE. Nevertheless, because of the inherent unpredictability of interest rates and equity market prices as well as other factors, actual results could differ materially from those projected in such forward-looking information.
Interest Rate Risk ACE is subject to the risk of fluctuating interest rates in the normal course of business. ACE manages interest rates through the use of fixed and, to a lesser extent, variable rate debt. As of December 31, 2000, a hypothetical 10% change in interest rates for variable rate debt would result in a $0.1 million change in interest costs and earnings before taxes.
Equity Price Risk ACE maintains trust funds, as required by the Nuclear Regulatory Commission, to fund certain costs of nuclear decommissioning (See Note 13 to the Consolidated Financial Statements). These funds are invested primarily in domestic and international equity securities, fixed-rate, fixed income securities, and cash and cash equivalents. The equity securities included in ACE's portfolio are exposed to price fluctuations in equity markets, and the fixed-rate, fixed income securities are exposed to changes in interest rates. The accounting for nuclear decommissioning recognizes that the net costs are recovered through electric rates and the effects of fluctuations in equity prices and interest rates on the securities in the nuclear decommissioning trust funds do not affect ACE's earnings.
Commodity Price Risk Effective August 1, 1999, ACE's combustion turbines (502 MW of electric generating capacity) and Deep water plant (185 MW of electric generating capacity) were deregulated. On July 1, 2000, ACE contributed the combustion turbines to Conectiv in conjunction with formation of an energy holding company and retained the Deepwater plant, which is subject to an agreement for sale as discussed in Note 11 to the Consolidated Financial Statements. Beginning August 1, 1999, ACE sold the megawatt-hour (MWH) output of these plants in markets not subject to price regulation. From time-to-time, ACE hedged the MWH output of its deregulated electric generating units, primarily through forward contracts, which were used to lock-in selling prices for electricity.
ACE uses a value-at-risk model to assess the market risk of the electricity output of its deregulated generat ing units. The model includes fixed price sales commitments, physical forward contracts, and commodity deriva tive instruments. Value at risk represents the potential gain or loss on instruments or portfolios due to changes in market factors, for a specified time period and confidence level. ACE estimates value-at-risk using a delta-normal variance/covariance model with a 95 percent confidence level and assuming a five-day holding period. As of December 31, 2000, ACE had no value at risk with respect to commodity price exposure because ACE did not hold any derivative instruments. As of December 31, 1999, ACE's calculated value at risk with respect to its commodity price exposure for the output of its deregulated generating plants was approximately $6.4 million.
11-13 ATLANTIC CITY ELECTRIC COMPANY Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF MANAGEMENT
Management is responsible for the information and representations contained in the consolidated financial statements of Atlantic City Electric Company (ACE). Our consolidated financial statements have been prepared in conformity with accounting principles generally accepted in the United States of America, based upon cur rently available facts and circumstances and management's best estimates and judgments of the expected effects of events and transactions.
ACE and its subsidiary companies maintain a system of internal controls designed to provide reasonable, but not absolute, assurance of the reliability of the financial records and the protection of assets. The internal control system is supported by written administrative policies, a program of internal audits, and procedures to assure the selection and training of qualified personnel.
PricewaterhouseCoopers LLP, independent accountants, are engaged to audit the financial statements and express their opinion thereon. Their audits are conducted in accordance with auditing standards generally ac cepted in the United States which include a review of selected internal controls to determine the nature, timing, and extent of audit tests to be applied.
The Audit Committee of Conectiv's Board of Directors, composed of outside directors only, meets with management, internal auditors, and independent accountants to review accounting, auditing, and financial report ing matters. The independent accountants are appointed by the Board of Directors on recommendation of the Audit Committee.
/S/ JOSEPH M. RIGBY /S/ JOHN C. VAN RODEN Joseph M. Rigby John C. van Roden President Chief Financial Officer
February 12, 2001
1-14 REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors Atlantic City Electric Company Wilmington, Delaware
In our opinion, the accompanying consolidated financial statements listed in the accompanying index ap pearing under Item 14(a)(1) on page IV-I present fairly, in all material respects, the financial position of Atlantic City Electric Company and subsidiary companies ("ACE") as of December 31, 2000 and 1999, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2000, in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the accompanying index appearing under Item 14(a)(2) on page IV- 1, presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of ACE's management; our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of the consolidated financial statements in accordance with auditing standards generally accepted in the United States of America which require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/S/ PRICEWATERHOUSECOOPERS LLP PricewaterhouseCoopers LLP Philadelphia, Pennsylvania
February 12, 2001
11-15 ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF INCOME
For the Year Ended December 31, 2000 199 1998 (Dollars in Thousands) Operating Revenues ...... $968,383 $1,076,585 $1,039,750 Operating Expenses Electric fuel and purchased energy and capacity ...... 420,737 480,381 482,684 Special charges ...... 12,301 79,091 Operation and maintenance ...... 243,682 253,970 214,553 Depreciation and amortization ...... 101,527 113,714 112,711 Taxes other than income taxes ...... 35,913 44,288 41,843 801,859 904,654 930,882 Operating Income ...... 166,524 171,931 108,868 O ther Incom e ...... 7,808 8,712 8,621 Interest Expense Interest charges ...... 76,178 60,562 63,940 Allowance for borrowed funds used during construction and capitalized interest ...... (645) (809) (957) 75,533 59,753 62,983 Preferred Dividend Requirements on Preferred Securities of Subsidiary Trusts ...... 7,619 7,634 6,052 Income Before Income Taxes and Extraordinary Item ...... 91,180 113,256 48.454 Income Taxes, Excluding Income Taxes Applicable To Extraordinary Item ...... 36,746 49,326 18,178 Income Before Extraordinary Item ...... 54,434 63,930 30,276 Extraordinary Item (Net of income taxes of $40,474) ...... (58,095) Net Income ...... 54,434 5,835 30,276 Dividends on Preferred Stock ...... 2,132 2,132 3,436 Gain on Preferred Stock Redemption ...... 2.545 Earnings Applicable to Common Stock ...... $ 52,302 $ 3,703 $ 29.385
See accompanying Notes to Consolidated Financial Statements.
11-16 ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the Year Ended December 31, 2000 1999 1996 (Donan in Thousands) Cash Flows From Operating Activities Net income ...... $ 54,434 $ 5,835 $ 30,276 Adjustments to reconcile net income to net cash provided by operating activities: Deferred recoverable purchased power contract termination payment ...... - (228,500) Extraordinary item net of income taxes ...... - 58,095 Special charges ...... - 12,301 79,091 Depreciation and amortization ...... 113,853 126,857 117,285 Investment tax credit adjustments, net ...... (3,157) (2,534) (1,690) Deferred income taxes, net ...... 23,121 71,897 (37,915) Deferred energy supply costs ...... (13,839) 23,844 43,001 Net change in: Accounts receivable ...... (7,333) (22,644) (500) Inventories ...... ' ' *9,110 (7,949) 5,077 Prepaid New Jersey sales & excise taxes ...... 13,374 22,216 (16,274) Accounts payable ...... (15,008) 7,921 18,765 Taxes accrued ...... 98,726 (111,399) 16,994 Other current assets and liabilities (1) ...... (2,721) (3,796) (29,511) Other, net ...... 12,023 14,527 18,018 Net cash provided (used) by operating activities ...... 282,583 (33,329) 242,617 Cash Flows From Investing Activities Investment in Conectiv money pool ...... (74,422) (73,532) Capital expenditures ...... (53,717) (48,931) (71,342) Deposits to nuclear decommissioning trust funds ...... (405) (3,213) (6,424) Other, net ...... 4,196 4,070 (1,040) Net cash used by investing activities ...... (124,348) (121,606) (78,806) Cash Flows From Financing Activities Common dividends paid ...... (67,309) (59,321) (81,450) Preferred dividends paid ...... (2,332) (2,821) (3,436) Preferred securities issued ...... - - 25,000 Preferred stock redeemed ...... - - (33,769) Long-term debt issued ...... - 228.500 85,000 Long-term debt redeemed ...... (46,075) (48,900) (58,575) Principal portion of capital lease payments ...... (12,326) (13,143) (12,295) Net change in short-term debt ...... (30,000) 30,000 (72,100) Other, net ...... - (223) (4,184) Net cash provided (used) by financing activities ...... (158,042) 134,092 (155,809) Net change in cash and cash equivalents ...... 193 (20,843) 8,002 Beginning of year cash and cash equivalents ...... 7,924 28,767 20,765 End of year cash and cash equivalents ...... $ 8,117 $ 7,924 $ 28,767
(1) Other than debt and deferred income taxes classified as current.
See accompanying Notes to Consolidated Financial Statements.
11-17 ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS
As of December 31, 2000 1999 (Dollars in Thousands) ASSETS Current Assets Cash and cash equivalents ...... 8,117 $ 7,924 Accounts receivable net of allowances of $4,423 and $3,500, respectively... 140,785 133,879 Investment in Conectiv money pool ...... 147,954 73,532 Inventories, at average cost Fuel (coal and oil) ...... 6,818 19,598 M aterials and supplies ...... 6,786 8,890 Prepaid income taxes ...... - 88,483 Deferred income taxes, net ...... 15,750 6,245 Other prepayments ...... 1,738 2,223 327,948 340,774 Investm ents ...... 112,501 105,371 Property, Plant and Equipment Electric generation ...... 142,243 256,899 Electric transmission and distribution ...... 1,255,184 1,224,644 Other electric facilities ...... 119,782 128,388 Other property, plant, and equipment ...... 5,772 5,772 1,522,981 1,615,703 Less: Accumulated depreciation ...... 640,103 626,080 Net plant in service ...... 882,878 989,623 Construction work-in-progress ...... 50,247 46,025 Leased nuclear fuel, at amortized cost ...... 28,352 30,391 961,477 1,066,039 Deferred Charges and Other Assets Recoverable stranded costs, net ...... 958,883 988,273 Unrecovered purchased power costs ...... 14,487 28,923 Deferred recoverable income taxes ...... 13,978 21,867 Unrecovered New Jersey state excise taxes ...... 10,360 22.567 Deferred debt refinancing costs ...... 12,409 13,574 Deferred other postretirement benefit costs ...... 29,981 32,479 Unamortized debt expense ...... 12,842 14,197 O ther ...... 26,516 20,595 1,079,456 1,142,475 Total Assets ...... $2,48 1,382 $2,654,659
See accompanying Notes to Consolidated Financial Statements.
11-18 ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED BALANCE SHEETS
As of December 31, 2000 1999 (Dollars in Tlhosands) CAPITALIZATION AND LIABILITIES Current Liabilities Short-term debt ...... $ - $ 30,000 Long-term debt due within one year ...... 97,200 46,075 Variable rate demand bonds ...... 22,600 22,600 Accounts payable ...... 50,744 62,169 Taxes accrued ...... 10,243 Interest accrued ...... 18,193 20,182 Dividends payable ...... 17,871 18,071 Current capital lease obligation ...... 15,480 15,480 Deferred energy supply costs ...... 34,650 46,375 Above-market purchased energy contracts and other electric restructuring liabilities ...... 7,586 7,992 O ther ...... 30,268 31,893 304,835 300,837 Deferred Credits and Other Liabilities Deferred income taxes, net ...... 405,385 389,594 Regulatory liability for New Jersey income tax benefit ...... 49,262 49,262 Above-market purchased energy contracts and other electric restructuring liabilities ...... 16,744 16,921 Deferred investment tax credits ...... 35,851 39,608 Long-term capital lease obligation ...... 12,872 14,911 Pension benefit obligation ...... 26,948 20,309 Other postretirement benefit obligation ...... 37,614 42,952 O ther ...... 28,918 22,381 613,594 595,938 Capitalization Common stock, $3 par value; shares authorized: 25.000,000; shares outstanding: 18,320,937 ...... 54,963 54,963 Additional paid-in capital ...... 410,194 493,007 Retained earnings ...... 114,962 129,981 Total common stockholder's equity ...... 580,119 677,951 Preferred stock not subject to mandatory redemption ...... 6,231 6,231 Preferred stock subject to mandatory redemption ...... 23,950 23,950 Preferred securities of subsidiary trusts subject to mandatory redemption.. 95,000 95,000 Long-term debt ...... 857,653 954,752 1,562,953 1,757,884 Commitments and Contingencies (Note 22) ...... -_ Total Capitalization and Liabilities ...... $2,481,382 $2,654,659
See accompanying Notes to Consolidated Financial Statements.
11-19 ATLANTIC CITY ELECTRIC COMPANY CONSOLIDATED STATEMENTS OF CHANGES IN COMMON STOCKHOLDER'S EQUITY
Total Common Additional Stockholder's Common Paid-in Retained Equity Stock Capital Earnings (Dollars in Thousands) Balance as of December 31, 1997 ...... $783,033 $54,963 $493,161 $234,909 Net income ...... 30,276 30,276 Preferred Stock Redemption ...... 1,959 135 1,824 Less Cash Dividends: Preferred stock ...... (3,436) (3,436) Comm on stock ...... (81,450) (81,450) O ther ...... (289) (289) Balance as of December 31, 1998 ...... 730,093 54,963 493,007 182,123 N et incom e ...... 5,835 5,835 Less Cash Dividends: Preferred stock ...... (2,132) (2,132) Comm on stock ...... (55,845) (55,845) Balance as of December 31, 1999 ...... 677,951 54,963 493,007 129,981 N et incom e ...... 54,434 54,434 i - - I , Less Cash Dividends: Preferred stock ...... (2,132) (2,132) Common stock ...... (67,309) (67,309) Contribution to Conectiv of subsidiaries which owned combustion turbine electric generating units (1) ...... (82,825) - (82,813) (12) Balance as of December 31, 2000 ...... $580,119 $54,963 $410,194 $114,962
As of December 31, 2000, ACE had 25 million authorized shares of common stock at $3 par value.
There were 18,320,937 shares outstanding during 1998, 1999, and 2000, which are owned by Conectiv. (1) See Note I I to the Consolidated Financial Statements for additional information.
See accompanying Notes to Consolidated Financial Statements.
11-20 ATLANTIC CITY ELECTRIC COMPANY NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES
Nature of Business As discussed in Note 4 to the Consolidated Financial Statements, effective March 1, 1998, Atlantic Energy, Inc. (Atlantic), and Delmarva Power & Light (DPL) consummated a series of merger transactions (the 1998 Merger) by which Atlantic City Electric Company (ACE) and DPL became wholly-owned subsidiaries of Conectiv. Conectiv is a registered holding company under the Public Utility Holding Company Act of 1935 (PUHCA).
On February 9, 2001, the Boards of Directors of Conectiv and Potomac Electric Power Company (Pepco) approved an Agreement and Plan of Merger under which Pepco will acquire Conectiv for a combination of cash and stock. The transaction is subject to various statutory approvals and approval by the stockholders of Conectiv and Pepco.
ACE is a public utility which supplies and delivers electricity to its customers under the trade name Conectiv Power Delivery. A transition to market pricing and terms of service for supplying electricity to cus tomers in the regulated service area of ACE began on August 1, 1999. During 1998-2000, ACE also supplied electricity in markets which were not subject to price regulation. ACE delivers electricity within its service area to approximately 501,000 customers through its transmission and distribution systems and also supplies electric ity to most of its electricity delivery customers, who have the option of choosing an alternative supplier. ACE's regulated service area covers about 2,700 square miles within the southern one-third of New Jersey and has a population of approximately 0.9 million.
Effective July 1, 2000, ACE contributed at net book value its combustion turbines, with an electric generat ing capacity of 502 megawatts (MW), and related assets and liabilities to Conectiv. Conectiv contributed the plants to a subsidiary of Conectiv Energy Holding Company (CEH). CEH and its subsidiaries are engaged in non-regulated electricity production and sales, and energy trading and marketing.
During 1999 and 2000, as discussed in Note 11 to the Consolidated Financial Statements, ACE entered into agreements for the sale of its nuclear and non-strategic baseload fossil fuel-fired electric generating plants. After the sales of the nuclear and non-strategic baseload fossil electric generating plants of ACE are completed, the principal remaining businesses of ACE will be the transmission and distribution, or delivery, of electricity. ACE will purchase power to supply electricity to customers who do not choose alternative electricity suppliers.
Regulation of Utility Operations Certain aspects of ACE's electric utility business are subject to regulation by the New Jersey Board of Public Utilities (NJBPU) and the Federal Energy Regulatory Commission (FERC).
ACE's electric delivery business is subject to the requirements of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71). As discussed below, prior to the third quarter of 1999, ACE's electricity supply business was subject to the require ments of SFAS No. 71. The NJBPU occasionally provides for future recovery from customers of current period expenses. When this happens, these expenses are deferred as regulatory assets and subsequently recognized in the Consolidated Statements of Income during the periods the expenses are recovered from customers. Similarly, regulatory liabilities may also be created due to the economic impact of an action taken by the NJBPU.
In July 1999, as discussed in Note 7 to the Consolidated Financial Statements, the NJBPU issued a Sum mary Order to ACE concerning restructuring the electricity supply business of ACE. This Summary Order was
11-21 issued pursuant to the New Jersey electric restructuring legislation enacted earlier in 1999. Based on the Sum mary Order, ACE determined that the requirements of SFAS No. 71 no longer applied to its electricity supply business as of August 1, 1999. As a result, ACE discontinued applying SFAS No. 71 to its electricity supply business and applied the requirements of SFAS No. 101, "Regulated Enterprises-Accounting for the Discon tinuation of Application of FASB Statement No. 71" (SFAS No. 101) and Emerging Issues Task Force (EITF) Issue No. 97-4, "Deregulation of the Pricing of Electricity-Issues Related to the Application of FASB State ments No. 71 and No. 101" (EITF 97-4). For information concerning the extraordinary charge to earnings that resulted from applying the requirements of SFAS No. 101 and EITF 97-4, refer to Note 6 to the Consolidated Financial Statements.
Refer to Note 14 for information about regulatory assets and liabilities arising from the financial effects of rate regulation.
Financial Statement Presentation The Consolidated Financial Statements include the accounts of ACE and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation.
Within the Consolidated Statements of Income, amounts previously reported for 1999 and 1998 as "Electric fuel and purchased power" and "Purchased electric capacity" have been combined and reported as "Electric fuel and purchased energy and capacity." Certain reclassifications of prior period data have been made to conform with the current presentation.
Use of Estimates The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates and assumptions.
Revenue Recognition ACE recognizes revenues for the supply and delivery of electricity upon delivery to the customer, including amounts for services rendered, but not yet billed.
Energy Supply Costs Under the Levelized Energy Clause prior to deregulation of electricity supply, regulated electric customer rates were subject to adjustment for differences between energy costs incurred in supplying regulated customers and amounts billed to customers for recovery of such costs. As a result, the amount recognized in the Consoli dated Statements of Income for energy costs incurred in supplying electricity to regulated customers was adjusted to match the amounts billed to ACE's regulated customers. An asset was recorded for under-collections from customers and a liability was recorded for over-collections from customers. Effective August 1, 1999, the accounting for energy costs associated with supplying electricity changed as discussed below.
As discussed under "Shopping Credits and Basic Generation Service" in Note 7 to the Consolidated Financial Statements, the Summary Order issued by the NJBPU to ACE provides for recovery through customer rates of energy and other costs of supplying customers who do not choose an alternative electricity supplier. Effective August 1, 1999, in recognition of these cost-based, rate-recovery mechanisms, ACE adjusts revenues from customer billings to the amount of the related costs incurred, including an allowed return on certain electric generating plants.
11-22 Nuclear Fuel The ownership interests of ACE in nuclear fuel at the Peach Bottom Atomic Power Station (Peach Bottom), the Salem Nuclear Generating Station (Salem), and the Hope Creek Nuclear Generating Station (Hope Creek) are financed through contracts accounted for as capital leases. Nuclear fuel costs, including a provision for the future disposal of spent nuclear fuel, are charged to fuel expense on a unit-of-production basis.
Risk Management Activities Effective August 1, 1999, ACE's combustion turbines (502 MW) and the Deepwater plant (185 MW) were deregulated. On July 1, 2000, ACE contributed the combustion turbines to Conectiv and retained the Deepwater plant, which is subject to an agreement for sale as discussed in Note 11 to the Consolidated Financial Statements. Beginning August 1, 1999, ACE sold the megawatt-hour (MWH) output of these plants in markets not subject to price regulation. From time-to-time, ACE hedged the MWH output of its deregulated electric generating units, primarily through forward contracts, which are used to lock-in selling prices for electricity. ACE also wrote (or sold) options for sale of the deregulated MWH output. Premiums received for written options were recorded initially as a deferred credit and were amortized to operating revenues over the option term.
ACE implemented the provisions of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended, effective January 1, 2001. SFAS No. 133 establishes accounting and reporting standards for derivative instruments and for hedging activities. SFAS No. 133 requires all derivative instruments, within the scope of the statement, to be recognized as assets or liabilities on the balance sheet at fair value. Changes in the fair value of derivatives that are not hedges, under SFAS No. 133, are recognized in earnings. The gain or loss on a derivative that hedges exposure to variable cash flow of a forecasted transaction is initially recorded in other comprehensive income (a separate component of common stockholder's equity) and is subsequently re classified into earnings when the forecasted transaction occurs. Changes in the fair value of other hedging derivatives result in a change in the value of the asset, liability, or firm commitment being hedged, to the extent the hedge is effective. Any ineffective portion of a hedge is recognized in earnings immediately.
ACE's financial statements were not affected by the initial adoption of SFAS No. 133, effective January 1, 2001, because ACE did not hold derivative instruments as of December 31, 2000. To the extent ACE holds derivative instruments subsequent to initial adoption of SFAS No. 133, there may be increased volatility in ACE's earnings, revenues and common stockholder's equity.
The cash flows from derivatives are included in the "Cash Flows from Operating Activities" section of the Consolidated Statements of Cash Flows.
Depreciation The annual provision for depreciation on utility property is computed on the straight-line basis using composite rates by classes of depreciable property. Accumulated depreciation is charged with the cost of depre ciable property retired, including removal costs less salvage and other recoveries. Depreciation expense includes a provision for ACE's share of the estimated cost of decommissioning nuclear power plant reactors based on site-specific studies. Refer to Note 13 to the Consolidated Financial Statements for additional information on nuclear decommissioning. ACE's overall composite rate of depreciation was 3.6% for 2000, 3.7% for 1999, and 3.9% for 1998.
Income Taxes The Consolidated Financial Statements include two categories of income taxes, which are current and deferred. Current income taxes represent the amounts of tax expected to be reported on ACE's federal and state income tax returns. Deferred income taxes are discussed below.
11-23 Deferred income tax assets and liabilities represent the tax effects of temporary differences between the financial statement and tax bases of existing assets and liabilities and are measured using presently enacted tax rates. The portion of ACE's deferred tax liability applicable to utility operations that has not been recovered from utility customers represents income taxes recoverable in the future and is shown on the Consolidated Balance Sheets as "Deferred recoverable income taxes."
Deferred income tax expense generally represents the net change during the reporting period in the net deferred tax liability and deferred recoverable income taxes.
Investment tax credits from utility plant purchased in prior years are reported on the Consolidated Balance Sheets as "Deferred investment tax credits." These investment tax credits are being amortized to income over the useful lives of the related utility plant.
Deferred Debt Refinancing Costs Prior to the third quarter of 1999, the costs of refinancing debt of the utility business were deferred and amortized over the period during which the costs are recovered in rates, which is generally the life of the new debt. In the third quarter of 1999, the deferred costs associated with previously refinanced debt attributed to ACE's electric generation business were written-off and a regulatory asset, recoverable stranded costs, was established to the extent recovery was provided for through rates charged to regulated delivery customers. Future debt refinancing costs that are to be recovered through customer rates of the regulated utility businesses will be deferred and subsequently amortized to interest expense during the rate recovery period. The costs of other debt refinancings will be accounted for in accordance with SFAS No. 4, "Reporting Gains and Losses from Extin guishment of Debt," which requires such costs to be expensed.
Interest Expense The amortization of debt discount, premium, and expense, including deferred refinancing expenses associ ated with the regulated electric transmission and distribution business, is included in interest expense.
Utility Plant As discussed in Note 6 to the Consolidated Financial Statements, the book cost basis of electric generation plants which became impaired as a result of deregulation of the electric utility industry in 1999, is the estimated fair value of the plants at the time of deregulation. The estimated fair values were based on amounts included in agreements for the sale of certain electric generating plants of ACE, as discussed in Note I I to the Consolidated Financial Statements. Utility plant which is not impaired is stated at original cost.
Utility plant is generally subject to a first mortgage lien.
Allowance for Funds Used During Construction Effective in the third quarter of 1999, the cost of financing the construction of electric generation plant is capitalized in accordance with SFAS No. 34, "Capitalization of Interest Cost."
Allowance for Funds Used During Construction (AFUDC) is included in the cost of utility plant and represents the cost of borrowed and equity funds used to finance construction of new utility facilities. In the Consolidated Statements of Income, the borrowed funds component of AFUDC is reported as a reduction of interest expense and the equity funds component of AFUDC is reported as other income. AFUDC was capitalized on utility plant construction at the rate of 8.25% for all periods.
11-24 Cash Equivalents In the Consolidated Financial Statements, ACE considers all highly liquid investments and debt securities purchased with a maturity of three months or less to be cash equivalents.
Investments Investments primarily include deposits in ACE's external nuclear decommissioning trust funds, which are stated at fair market value. Changes in the fair market value of the trust funds are also reflected in the accrued liability for nuclear decommissioning which is included in accumulated depreciation.
NOTE 2. SUPPLEMENTAL CASH FLOW INFORMATION Cash paid during the year 2000 1999 1998 (Dollars in Thousands) Interest, net of capitalized amounts ...... $ 73,520 $ 51,723 $ 68,278 Income taxes, net of refunds ...... $(80,677) $ 90,185 $ 48,215
During 2000, ACE received federal and state income tax refunds of $114.2 million and made estimated tax payments of $33.5 million, resulting in $80.7 million of net income taxes received. The income tax refunds received in 2000 were primarily related to the tax benefit associated with ACE's payment of $228.5 million on December 28, 1999 to terminate ACE's purchase of electricity under a contract with the Pedricktown Co-gener ation Limited Partnership (Pedricktown). For additional information concerning the contract termination, see Note 8 to the Consolidated Financial Statements.
Non-cash Investing and Financing Transaction For information concerning a non-cash transaction related to investing and financing activities, see "Contri bution of Combustion Turbines to Conectiv" in Note I I to the Consolidated Financial Statements.
NOTE 3. INCOME TAXES ACE, as a subsidiary of Conectiv, is included in the consolidated federal income tax return of Conectiv. Income taxes are allocated to ACE based upon the taxable income or loss, determined on a separate return basis.
Components of Consolidated Income Tax Expense 2000 1999 1998 (Dollars in Thousands) Operations Federal: Current ...... $ 6,930 $(20,940) $ 43,133 Deferred ...... 22,509 57,713 (27,694) State: Current ...... 9,853 902 14,650 Deferred ...... 611 14,185 (10,221) Investment tax credit adjustments ...... (3,157) (2,534) (1,690) 36,746 49,326 18,178 Extraordinary Item Federal: Deferred ...... - (31,585) State: Deferred ...... - (8,889) - (40,474) Total Income Tax Expense ...... $36,746 $ 8,852 $ 18,178
11-25 Reconciliation of Effective Income Tax Rate The amount computed by multiplying "Income before income taxes and extraordinary item" by the federal statutory rate is reconciled below to income tax expense on operations (which excludes amounts applicable to the extraordinary item). 2000 1999 199" Amount Rate Amount Rate Amount Rate (Dollars In Thousands) Statutory federal income tax expense ...... $31,913 35% $39,639 35% $16,959 35% State income taxes, net of federal tax benefit ...... 6,951 8 9,806 9 2,878 6 Plant basis differences ...... 2,172 2 2,275 2 3,767 8 Amortization of investment tax credits ...... (3,157) (3) (2,534) (2) (1,690) (3) Other, net ...... (1,133) (2) 140 - (3,736) (8) Total income tax expense ...... $36,746 40% $49,326 44% $18,178 38%
Components of Deferred Income Taxes
Items comprising deferred tax balances as of December 31, 2000 and 1999 are as follows: M 1999 (Dollars In Thousands) Deferred tax liabilities: Utility plant basis differences ...... $335,221 $334,587 Deferred recoverable income taxes ...... 4,915 7,689 Unrecovered purchased power costs ...... - 2,267 State excise taxes ...... 2,153 6,487 Payment for termination of purchased power contract with non-utility electric generator ...... 94,982 94,429 Other ...... 49,897 11,821 Total deferred tax liabilities ...... 487,168 457,280 Deferred tax assets: Deferred investment tax credits ...... 19,324 21,349 O ther ...... 78,209 52,582 Total deferred tax assets ...... 97,533 73,931 Total deferred taxes, net ...... $389,635 $383,349
NOTE 4. 1998 MERGER On March 1, 1998, ACE and DPL became wholly-owned subsidiaries of Conectiv (the 1998 Merger). Before the 1998 Merger, Atlantic owned ACE and non-utility subsidiaries. As a result of the 1998 Merger, Atlantic's existence ended and Conectiv became the owner of (directly or indirectly) ACE, DPL and the non-util ity subsidiaries that were formerly held separately by Atlantic and DPL. Conectiv is a registered holding com pany under the PUHCA.
In connection with the 1998 Merger, Atlantic stockholders received 0.75 shares of Conectiv common stock and 0.125 shares of Conectiv Class A common stock for each share of Atlantic stock held.
The 1998 Merger was accounted for under the purchase method, with DPL as the acquirer. ACE's financial statements do not reflect "push-down" accounting-the adjustment of the values of assets and liabilities as of the 1998 Merger date and recording of goodwill. Push-down accounting was not used because ACE had preferred stock and public debt outstanding as of the 1998 Merger date.
11-26 NOTE 5. SPECIAL CHARGES ACE's operating results for 1999 include special charges of $12.3 million before taxes ($7.3 million after taxes) for the costs of employee separations, additional costs related to the 1998 Merger, and certain other nonrecurring costs.
ACE's operating results for 1998 include special charges of $61.1 million before taxes ($36.6 million after taxes) for the costs of 1998 Merger-related employee separations and relocations and other 1998 Merger-related costs and $18.0 million before taxes ($10.6 million after taxes) for the write-down to fair value of certain operational and administrative facilities to be sold, as a result of the 1998 Merger.
NOTE 6. EXTRAORDINARY ITEM As discussed in Note 1 to the Consolidated Financial Statements, based on the NJBPU's Summary Order, ACE discontinued applying SFAS No. 71 to its electricity supply business and applied the requirements of SFAS No. 101 and EITF 97-4 in the third quarter of 1999. Pursuant to the requirements of SFAS No. 101 and EITF 97-4, ACE recorded extraordinary charges in the third and fourth quarters of 1999 which reduced earnings by $58.1 million, net of income taxes of $40.5 million. The portion of the extraordinary charge related to impaired assets was determined in accordance with SFAS No. 121, "'Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets To Be Disposed Of" (SFAS No. 121). The extraordinary charge primarily resulted from impaired electric generating plants and certain other assets, uneconomic energy contracts, and other effects of deregulation requiring loss recognition. The impairment amount for electric generating plants was determined based on expected proceeds under agreements for the sale of the electric generating plants, which are discussed in Note 11 to the Consolidated Financial Statements. The extraordinary charge was decreased by the regulatory asset established for the amount of stranded costs expected to be recovered through regulated electricity delivery rates.
As discussed in Note 7 to the Consolidated Financial Statements, ACE's extraordinary charge was based on the NJBPU's Summary Order and the NJBPU is to issue a more detailed order at a later date. If the NJBPU's final detailed order were to differ materially from the Summary Order, then another extraordinary item may result due to adjustment of the 1999 extraordinary charge.
The details of the 1999 extraordinary charge are shown below.
Mltions Items Included in the 1999 Extraordinary Charge of Dollars The net book value of the nuclear power plants and certain fossil fuel-fired plants and other electric plant-related assets including inventories, were written-down due to impairment ...... $(662.1) Generation-related regulatory assets and certain other utility assets impaired from deregulation were written-off. Also, various liabilities resulting from deregulation were recorded ...... (205.7) A regulatory asset, recoverable stranded costs, was established for the amount of stranded costs expected to be recovered through regulated electricity delivery rates ...... 769.2 Total pre-tax extraordinary charge ...... (98.6) Income tax benefit ...... 40.5 Total extraordinary charge, net of income taxes ...... $ (58.1)
11-27 NOTE 7. REGULATORY MATTERS
New Jersey Electric Utility Industry Restructuring
On February 9, 1999, New Jersey enacted the Electric Discount and Energy Competition Act (the New Jersey Act) which, among other things, provided customers of New Jersey electric utilities with a choice of electricity suppliers beginning August 1, 1999. Pursuant to the New Jersey Act, on July 15, 1999, the NJBPU issued a Summary Order to ACE concerning stranded costs, unbundled rates, and other matters related to restructuring. The NJBPU indicated that a more detailed order would be issued at a later time. Issuance of the NJBPU's final order for ACE has been delayed due to appeals of the NJBPU's final order concerning restructur ing the electricity supply business of Public Service Electric and Gas Company (PSE&G) and recent electricity shortages and price increases in California. On December 6, 2000, the New Jersey Supreme Court affirmed judgment of the New Jersey Superior Court Appellate Division which had previously affirmed the NJBPU's final order concerning the PSE&G restructuring. However, management cannot predict the timing or outcome of this or related matters, such as securitization by ACE of its stranded costs and the sale of electric generating plants, as discussed in Note 11 to the Consolidated Financial Statements.
The key provisions of the Summary Order issued by the NJBPU to ACE are discussed below.
Rate Decreases In its Summary Order, the NJBPU directed ACE to implement a 5% aggregate rate reduction effective August 1, 1999 and an additional 2% rate reduction by January 1, 2001. By August 1, 2002, rates must be reduced by 10% from the rates that were in effect as of April 30, 1997.
The initial 5% rate reduction effective August 1, 1999 reduced annual revenues by approximately $50 million. The additional 2% rate reduction required by January 1, 2001 was implemented through two separate 1% rate reductions effective January 1, 2000 and 2001, respectively. Each of the 1% rate reductions reduced annual revenues by approximately $10 million, or $20 million in total. The final rate reduction, which is required by August 1, 2002, is expected to reduce revenues by an additional $30 million, which would result in a cumulative rate reduction of $100 million since August 1, 1999.
Stranded Cost Recovery and Securitization
Stranded costs are the uneconomic portion of assets and long-term contracts that resulted from electric utility industry restructuring. The Summary Order provides that ACE may divest its nuclear and fossil fuel-fired baseload units and transfer combustion turbine electric generating units to a non-utility affiliated company at net book value. Additional NJBPU approvals are required prior to the sale of the nuclear and fossil fuel-fired baseload units of ACE. The NJBPU determined that ACE will have the opportunity to recover 100% of the net stranded costs related to certain generation units to be divested and the stranded costs associated with power purchased from non-utility generators (NUGs), subject to further NJBPU proceedings. The Summary Order, in conjunction with the New Jersey Act, also permits securitization of stranded costs through the issuance of transition bonds in the amount of the after-tax stranded cost recovery approved by the NJBPU. Management expects the transition bonds will be issued after ACE completes the sale of certain electric generating units, as discussed in Note 11 to the Consolidated Financial Statements. The ability to issue transition bonds would depend not only upon approval of the NJBPU, but also on the conditions in the relevant capital markets at the times of the offerings. Proceeds from the transition bonds may be used to refinance ACE's debt and preferred securities, finance the restructuring of purchased power contracts, or otherwise reduce costs in order to decrease regulated electricity rates. The Summary Order allows securitization of (a) 100% of the net stranded costs of certain generation units to be divested, over a period not to exceed 15 years, and (b) 100% of the costs to effect potential NUG contract buyouts or buydowns, over a period not to exceed the remaining term of the restructured
11-28 contracts. The Summary Order provides for the principal of and interest on transition bonds to be collected from customers through a transition bond charge over the securitization term. The Summary Order also provides for customer rates to include a separate market transition charge for recovery of the income tax expense associated with the revenues from transition bond charges.
The balance for ACE's pre-tax recoverable stranded costs, net of amortized amounts, was approximately $959 million as of December 31, 2000 and $988 million as of December 31, 1999. The balances of recoverable stranded costs include the stranded costs estimated and recorded as a result of discontinuing the application of SFAS No. 71 (as discussed in Note 6 to the Consolidated Financial Statements) and the $228.5 million payment to terminate a NUG contract (as discussed in Note 8 to the Consolidated Financial Statements). ACE's amount of recoverable stranded costs remains subject to adjustment based on the actual gains and losses realized on the sale of certain electric generating plants, additional buyouts or buydowns of NUG contracts, the NJBPU's final restructuring order, and the final amount determined to be recoverable through customer rates under the New Jersey Act.
Shopping Credits and Basic Generation Service The Summary Order established minimum initial shopping credits for customers who choose an alternative electricity supplier, from a system average 5.27 cents per kilowatt-hour (kWh), effective August 1, 1999, to a system average of 5.48 cents per kWh in 2003. These shopping credits include transmission costs and charges by ACE for its Basic Generation Service (BGS) provided to retail customers who do not choose an alternative electricity supplier. ACE is obligated to provide BGS through July 31, 2002; thereafter, the BGS supplier is expected to be determined each year based on a competitive bidding process.
In accordance with the Summary Order, the rates charged to ACE's customers for BGS include a component for the market-value of power purchased from NUGs. The above-market portion of the cost of NUG power is being collected through a non-bypassable "Net NUG Charge" included in regulated electricity delivery rates, over the remaining term of the NUG contracts. The above-market portion of the costs of certain of ACE's power plants is being recovered through a "Market Transition Charge," included in regulated electricity delivery rates. The NJBPU's Summary Order also provided that ACE's regulatory liability for over-recovered energy supply costs as of July 31, 1999 would be offset by any subsequent under-recoveries of the costs associated with BGS. Due to under-recoveries of such costs, ACE reduced its liability for over-recovered energy supply costs and recognized like amounts of revenues in the amounts of $17.5 million for 2000 and $17.2 million for 1999. Customer rates are to be adjusted for any deferred balance remaining after the initial four-year transition period, which ends July 31, 2003. ACE's recovery of BGS supply costs is subject to review by the NJBPU.
Customer Account Services During the fourth quarter of 1999, the NJBPU began a proceeding concerning customer metering, billing, and other account administration functions (Customer Account Services). On December 22, 2000, the NJBPU approved a stipulation, to which ACE and certain other New Jersey utilities were parties, in the Customer Account Services proceeding. One of the terms of the stipulation requires ACE to begin purchasing the receiv ables of third parties supplying electricity to ACE's delivery customers in the second quarter of 2001. The stipulation remains effective through August 1, 2003.
NOTE 8. TERMINATION AND RESTRUCTURING OF PURCHASED POWER CONTRACTS On November 10, 1999, the NJBPU issued an order approving termination of a contract under which ACE had purchased energy and 116 MW of capacity from Pedricktown, a NUG partnership which was owned 50% by other Conectiv subsidiaries. The NJBPU order also provided that ACE is entitled to recover from customers the contract termination payment of $228.5 million, transaction costs, and interim financing costs. The NJBPU order found that the contract termination payment and related transaction costs are eligible for long-term financ ing through the issuance of securitized bonds. On December 28, 1999, ACE paid $228.5 million to terminate the
11-29 contract and borrowed funds to finance the contract termination payment (as discussed in Note 17 to the Consolidated Financial Statements). The contract termination payment and related costs are included in "Recov erable Stranded Costs" on the Consolidated Balance Sheets. ACE's customer rates were reduced by about 1% (approximately $10 million of revenues on an annualized basis) effective January 1, 2000 as a result of the net savings from the contract termination.
On December 6, 2000, the NJBPU approved ACE's payment on January 22, 2001 of $3.45 million in connection with restructuring ACE's purchased power contract with a NUG, American Ref-Fuel Company of Delaware Valley, L.P.
Management anticipates that transition bonds will ultimately be used to finance the stranded costs associated with the buyout or buydown of ACE's NUG contracts.
NOTE 9. RISK MANAGEMENT ACTIVITIES Effective August 1, 1999, ACE's combustion turbines (502 MW of electric generating capacity) and Deep water plant (185 MW of electric generating capacity) were deregulated. On July 1, 2000, ACE contributed the combustion turbines to Conectiv in conjunction with formation of an energy holding company and retained the Deepwater plant, which is subject to an agreement for sale as discussed in Note 11 to the Consolidated Financial Statements. Beginning August 1, 1999, ACE sold the megawatt-hour (MWH) output of these plants in markets not subject to price regulation. From time-to-time, ACE hedged the MWH output of its deregulated electric generating units, primarily through forward contracts, which were used to lock-in selling prices for electricity. As of December 31, 2000, ACE did not hold derivative instruments. As of December 31, 1999, ACE hedged 512,300 MWH of forward generation output, through the sale of forward contracts, which resulted in an $0.7 million unrealized and unrecognized gain as of December 31, 1999.
NOTE 10. JOINTLY-OWNED PLANT ACE's Consolidated Balance Sheets include its proportionate share of assets and liabilities related to jointly owned plant. ACE has ownership interests in electric generating plants, transmission facilities, and other facilities in which various parties have ownership interests. ACE's proportionate shares of operating and maintenance expenses of the jointly owned plant are included in the corresponding expenses in ACE's Consolidated State ments of Income. ACE is responsible for providing its share of financing for the jointly owned facilities.
Information with respect to ACE's share of jointly owned plant as of December 31, 2000 is shown below. As discussed in Note II to the Consolidated Financial Statements, agreements have been reached to sell to third parties the jointly-owned nuclear and coal-fired plants listed below.
11-30 Megawatt Construction Ownership Capability Plant In Accumulated Work In Share Owned Serve Deprecadom Progreus (Dollars In Thousands) Nuclear Peach Bottom ...... 7.51% 164 $ 4,847 $ 944(a) $4,760 Salem ...... 7.41% 167(b) 3,892 2,236(a) 2,517 Hope Creek ...... 5.00% 52 1,930 923(a) 619 Coal-Fired Keystone ...... 2.47% 42 13,758 4,561 542 Conemaugh ...... 3.83% 65 34,777 10,205 970 Transmission Facilities ...... Various 24,881 11,191 Other Facilities ...... Various 1,111 177 Total ...... 490 $85,196 $30,237 $9,408
(a) Excludes Nuclear Decommissioning Reserve. (b) Includes 3 MW for on-site combustion turbine.
NOTE 11. DIVESTITURE OF ELECTRIC GENERATING PLANTS As discussed below, ACE contributed at net book value its combustion turbine electric generating units to Conectiv on July 1, 2000 and all remaining electric generating plants of ACE are subject to agreements for sale. After the sales of ACE's electric generating plants are completed, the principal remaining businesses of ACE will be the transmission and distribution of electricity. ACE will purchase power to supply electricity to custom ers who do not choose alternative electricity suppliers. ACE's exit from the electricity production business is expected to cause a decrease in ACE's earnings capacity.
Contribution of Combustion Turbines to Conectiv Effective July 1, 2000, ACE contributed at book value its combustion turbines (502 megawatts of capacity) and related transmission equipment, inventories, and liabilities to a wholly-owned subsidiary (Conectiv Atlantic Generation, LLC, or CAG). ACE then contributed CAG to Conectiv in conjunction with the formation of an energy-holding company by Conectiv, which is engaged in non-regulated electricity production and sales, and energy trading and marketing. The primary effects on ACE's balance sheet of the contribution to Conectiv were as follows: (a) property, plant and equipment decreased $86 million (primarily electric generating plants); (b) fuel and other inventories decreased $6 million; (c) deferred income taxes and investment tax credits decreased $9 million; and (d) the additional paid-in capital portion of common stockholder's equity decreased $83 million.
Agreements for the Sale of Electric Generating Plants ACE has entered into agreements to sell the nuclear and non-strategic baseload fossil fuel-fired electric generating plants which are shown in the table below. As of December 31, 2000 MWof Net Book Capacity Value ($ in milions) Fossil Units: W holly-owned ...... 632.0 $ 82.3 Jointly-owned ...... 107.7 35.3 Jointly-owned nuclear units ...... 383.0 14.5 1,122.7 $132.1
11-31 On September 30, 1999, Conectiv announced that ACE reached agreements to sell its ownership interests in nuclear electric generating plants to PSEG Power LLC (a subsidiary of Public Service Enterprise Group Incorporated) and PECO Energy Company (PECO). ACE's interests in the nuclear units that are subject to the sales agreements include a 7.51% (164 MW) interest in Peach Bottom, a 7.41% interest (167 MW) in Salem and a 5.0% interest (52 MW) in Hope Creek. The net book value of the nuclear units to be sold was $14.5 million as of December 31, 2000. The agreements for the sale of ACE's interests in the nuclear plants provide for (i) a sales price of approximately $11 million plus the net book value of the interests of ACE in nuclear fuel on-hand as of the closing date and (ii) the transfer of ACE's nuclear decommissioning funds and related obligation for decommissioning the plants to the purchasers upon completion of the sales.
On January 19, 2000, Conectiv announced that ACE reached an agreement to sell certain wholly and jointly owned fossil fuel-fired units to NRG Energy, Inc. (NRG), a subsidiary of Northern States Power Company, for $178 million. The units to be sold to NRG have a total capacity of 739.7 MW, and had a net book value of $117.6 million as of December 31, 2000. Management expects the proceeds from the planned sales of the electric generating plants will be used to repay debt and to fund expansion of Conectiv's electric generation business. Some or all of ACE's proceeds from the sale of the electric generating plants could be paid as a dividend to Conectiv, or invested in Conectiv's pool of funds that Conectiv subsidiaries borrow from or invest in depending on their cash position.
Consummation of the sales of the electric generating plants is subject to the receipt of required regulatory approvals. In addition, the agreements for the sales of the electric generating plants contemplated that the sales of the plants of ACE and DPL, which is also selling its electric generating plants, would occur simultaneously. Appeals related to the NJBPU's final order concerning restructuring the electricity supply business of Public Service Electric and Gas Company (PSE&G) and recent electricity shortages and price increases in California have resulted in delays in the issuance of required regulatory approvals, the NJBPU's final order concerning restructuring the electricity supply business of ACE, and the closings of the sales of the electric generating units. Effective October 3, 2000, the agreements relating to the sale of the nuclear plants were amended to, among other things, permit separate closings of the sales of the ACE and DPL interests in the nuclear plants. DPL's ownership interests in nuclear electric generating plants were sold on December 29, 2000. On December 6, 2000, the New Jersey Supreme Court affirmed the judgment of the New Jersey Superior Court Appellate Division, which had previously upheld the NJBPU's final order concerning the PSE&G restructuring. Management cur rently expects the sales of ACE's nuclear and fossil electric generating plants to take place during 2001. Howev er, management cannot predict the timing of the issuance of required NJBPU approvals, the timing or outcome of appeals, if any, of such approvals, the effect of any of the foregoing on the ability of ACE to consummate the sales of various electric generating plants or the impact of any of the foregoing on ACE's ability to recover or securitize any related stranded costs.
As of December 31, 2000, $5.3 million of costs associated with selling the electric generating plants had been deferred as an adjustment to the expected future gain or loss on the sales. In the event the sales are not completed, these costs would be expensed.
NOTE 12. WHOLESALE TRANSACTION CONFIRMATION LETTER AGREEMENTS On October 3, 2000, ACE entered into Wholesale Transaction Confirmation letter agreements (Letter Agree ments). The Letter Agreements provide for the sale of the electricity output and capacity associated with the ownership interests of ACE in Peach Bottom. Salem, and Hope Creek. PECO and PSEG Energy Resources & Trade LLC (PSER&T), an indirect subsidiary of Public Service Enterprise Group, purchase the electricity output and capacity from ACE under the Letter Agreements. The Letter Agreements became effective October 7, 2000, and terminate for each plant upon the earlier of (1) the closing of the sale of the plant, (2) the termination of the agreement relating to the sale of the plant or (3) September 30, 2001.
In exchange for the electricity output and capacity purchased from a given plant, PECO and PSER&T reimburse ACE for the nuclear fuel amortized during the term of the Letter Agreements at each plant, and are
11-32 responsible for the payment of operation and maintenance costs, inventories, capital expenditures (subject, in certain circumstances, to reimbursement by ACE) and certain other liabilities associated with the ownership interests of ACE in each plant.
NOTE 13. NUCLEAR DECOMMISSIONING ACE records a liability for its share of the estimated cost of decommissioning the Peach Bottom, Salem, and Hope Creek nuclear reactors over the remaining lives of the plants based on amounts collected in rates charged to electric customers. ACE estimates its share of future nuclear decommissioning costs ($157 million) based on site specific studies filed with and approved by the NJBPU. The ultimate cost of nuclear decommissioning for the Peach Bottom, Salem, and Hope Creek reactors may exceed the current estimates, which are updated periodically.
ACE's consolidated accrued nuclear decommissioning liability, which is reflected in the accumulated re serve for depreciation, was $109.0 million as of December 31, 2000 and $101.0 million as of December 31, 1999. The provision reflected in depreciation expense for nuclear decommissioning was $3.7 million in 1999 and $6.4 million in 1998. During 2000, no provision was included in depreciation expense for nuclear decommissioning. External trust funds established by ACE for the purpose of funding nuclear decommissioning costs had an aggregate book balance (stated at fair market value) of $109.0 million as of December 31, 2000 and $100.5 million as of December 31, 1999. Earnings on the trust funds are recorded as an increase to the accrued nuclear decommissioning liability, which, in effect, reduces the expense recorded for nuclear decommissioning. As discussed in Note 11 to the Consolidated Financial Statements, upon completion of the expected sales of the nuclear plants, ACE will transfer its respective nuclear decommissioning trust funds to the purchasers who will then assume full responsibility for the decommissioning of the nuclear plants.
The staff of the Securities and Exchange Commission has questioned certain of the current accounting practices of the electric utility industry, including ACE, regarding the recognition, measurement and classifica tion of decommissioning costs for nuclear generating stations in the financial statements of electric utilities. In February 2000, the FASB issued an exposure draft of a new accounting standard which addresses the accounting for obligations associated with the retirement of long-lived assets, such as decommissioning costs of nuclear generating stations. Under this proposed accounting standard, the fair value of the decommissioning obligation would be capitalized as part of the cost of the nuclear generating station and recorded as a liability. The cost capitalized would be depreciated over the life of the nuclear generating station. Changes in the liability due to the passage of time would be recorded as interest expense. Changes in the liability resulting from revisions in the timing or amount of cash flows would increase or decrease the liability and the carrying amount of the nuclear generating station. Trust fund income from the external decommissioning trusts would be reported as investment income under the proposed accounting standard rather than as a reduction of decommissioning expense.
NOTE 14. REGULATORY ASSETS AND LIABILITIES In conformity with SFAS No. 71, ACE's accounting policies reflect the financial effects of rate regulation and decisions issued by the NJBPU. The NJBPU occasionally provides for future recovery from customers of current period expenses. When this happens, the expenses are deferred as regulatory assets and subsequently recognized in the Consolidated Statement of Income during the period the expenses are recovered from custom ers. Similarly, regulatory liabilities may also be created due to the economic impact of an action taken by the NJBPU.
As discussed in Notes 1, 6, and 7 to the Consolidated Financial Statements, in the third quarter of 1999, the electricity supply business of ACE no longer met the requirements of SFAS No. 71. Accordingly, regulatory assets and liabilities related to the electricity supply business were written off, except to the extent that future cost recovery was provided for through the regulated electricity delivery business. A regulatory asset, "Recover able stranded costs," was established to recognize amounts to be collected from regulated delivery customers for stranded costs which resulted from deregulation of the electricity supply business.
11-33 The table below displays the regulatory assets and liabilities as of December 31, 2000 and 1999.
December31, December31, Regulatory Assets (Liabilities) 20M0 1999 (Millions of Dollars) Recoverable stranded costs ...... $958.9 $ 988.3 Deferred recoverable income taxes ...... 14.0 21.9 Deferred debt refinancing costs ...... 12.4 13.6 Unrecovered state excise taxes ...... 10.4 22.6 Deferred other postretirement benefit costs ...... 30.0 32.5 Unrecovered purchased power costs ...... 14.5 28.9 Regulatory liability for deferred energy supply costs ...... (34.7) (46.4) Deferred costs for nuclear decommissioning/decontamination ...... 5.1 5.6 Regulatory liability for New Jersey income tax benefit ...... (49.3) (49.3) Asbestos removal costs ...... 8.0 8.3 T otal ...... $969.3 $1,026.0
Recoverable Stranded Costs: Represents amounts to be collected from regulated delivery customers (net of amounts which have been amortized to expense) for stranded costs which resulted from deregulation of the electricity supply business. Any gain realized on the sale of certain of ACE's electric generating plants will reduce the amount of recoverable stranded costs. The pre-tax balances of $958.9 million as of December 31, 2000 and $988.3 million as of December 31, 1999 arose from the $228.5 million NUG contract termination
P payment in 1999, as discussed in Note 8 to the Consolidated Financial Statements, and discontinuing the application of SFAS No. 71 to the electricity supply business in 1999, as discussed in Note 6 to the Consolidated Financial Statements.
Deferred Recoverable Income Taxes: Represents the portion of deferred income tax liabilities applicable to ACE's utility operations that has not been reflected in current customer rates for which future recovery is probable. As temporary differences between the financial statement and tax bases of assets reverse, deferred recoverable income taxes are amortized.
Deferred Debt Refinancing Costs: See "Deferred Debt Refinancing Costs" in Note I to the Consoli dated Financial Statements.
Unrecovered State Excise Taxes: Represents additional amounts paid, by ACE, as a result of prior legislative changes in the computation of New Jersey state excise taxes. These costs are included in current customer rates, with the remaining balance scheduled for full recovery over the next 2 years.
Deferred Other Postretirement Benefit Costs: Represents the non-cash portion of other postretirement benefit costs deferred by ACE during 1993 through 1997. This cost is being recovered over a 15-year period which began on January 1, 1998.
Unrecovered Purchased Power Costs: Includes costs incurred by ACE for renegotiation of a long-term capacity and energy contract. These costs are included in current customer rates with the balance scheduled for full recovery over the next 14 years. The balance as of December 31, 1999 also included $12 million of prior deferrals by ACE of capacity costs; the amortization of these costs to expense expired in 2000.
Deferred Energy Supply Costs: See "Energy Supply Costs" in Note I to the Consolidated Financial Statements.
Deferred Costs for Nuclear Decommissioning/Decontamination: Represents amounts recoverable from ACE's customers for amounts owed by ACE to the U.S. government for clean-up of gaseous diffusion enrich ment facilities pursuant to the Energy Policy Act of 1992.
[1-34 Regulatory Liability for New Jersey Income Tax Benefit: In 1999, a deferred tax asset arising from the write down of ACE's electric generating plant was established. The deferred tax asset represents the future tax benefit expected to be realized when the higher tax basis of the generating plants is deducted for New Jersey state income tax purposes. ACE has requested the New Jersey Division of Taxation to rule on whether or not this tax benefit may be used to reduce the rates charged to ACE's regulated electricity delivery customers for stranded cost recovery. To recognize that this tax benefit probably will be given to ACE's regulated electricity delivery customers through lower electric rates, ACE established a regulatory liability.
Asbestos Removal Costs: Represents costs incurred by ACE to remove asbestos insulation from a whol ly-owned generating station. These costs are included in current customer rates with the balance scheduled for full recovery over the next 29 years.
NOTE 15. COMMON STOCKHOLDER'S EQUITY Effective March 1, 1998, all 18,320,937 outstanding shares ($3 per share par value) of ACE were acquired by Conectiv, pursuant to the 1998 Merger, as discussed in Note 4 to the Consolidated Financial Statements.
For information concerning changes to common equity accounts of ACE, see the Consolidated Statements of Changes in Common Stockholder's Equity.
ACE's certificate of incorporation requires payment of all preferred dividends in arrears (if any) prior to payment of common dividends to Conectiv, and has certain other limitations on the payment of common dividends.
As a subsidiary of a registered holding company under PUHCA, ACE can pay dividends only to the extent of its retained earnings unless SEC approval is obtained.
NOTE 16. PREFERRED STOCK AND PREFERRED SECURITIES OF SUBSIDIARY TRUSTS ACE has authorized 799,979 shares of Cumulative Preferred Stock, $100 Par Value, two million shares of No Par Preferred Stock and three million shares of Preference Stock, No Par Value. If preferred dividends are in arrears for at least a full year, preferred stockholders have the right to elect a majority of directors to the Board of Directors until all dividends in arrears have been paid.
Preferred Stock Not Subject to Mandatory Redemption Current 2000 1999 Redemption Series Shares (000) Shares (000) Price 4%, $100 par value ...... 24,268 $2,427 24,268 $2,427 $105.50 4.1%, $100 par value ...... 20,504 2,051 20,504 2,051 101.00 4.35%, $100 par value ...... 3,102 310 3,102 310 101.00 4.35%, $100 par value ...... 1,680 168 1,680 168 101.00 4.75%, $100 par value ...... 8,631 863 8,631 863 101.00 5%, $100 par value ...... 4,120 412 4,120 412 100.00 Total ...... 62,305 $6,231 62,305 $6,231
In the fourth quarter of 1998, ACE purchased and retired 237,695 shares, or $23.8 million of various series of $100 per share par value preferred stock, which had an average dividend rate of 4.4%. ACE realized a $2.5 million gain on this preferred stock redemption which is presented as Gain on Preferred Stock Redemption within the 1998 Consolidated Statement of Income.
11-35 Preferred Stock Subject to Mandatory Redemption As of December 31, 2000 and 1999, there were 239,500 outstanding shares of preferred stock subject to mandatory redemption with a $100 stated value per share and a $7.80 annual dividend rate per share. Beginning May 1, 2001, 115,000 shares are subject to mandatory redemption annually.
In August 1998, ACE redeemed 100,000 shares of its $8.20 No Par Preferred Stock ($100 per share stated value).
Preferred Securities of Subsidiary Trusts Subject to Mandatory Redemption The amounts outstanding as of December 31, 2000, and December 31, 1999 of preferred securities issued by subsidiary trusts owned by ACE are presented below.
Securities Outstanding Amount Issuer seres 2000 1999 2000 1999 Atlantic (Dollars in Thousands) Capital I * ...... $25 per share, 8.25% 2,800,000 2,800,000 $70,000 $70,000 Atlantic Capital H * ...... $25 per share, 7.375% 1,000,000 1,000,000 25,000 25,000 $95,000 $95,000
* Per share value is stated liquidation value.
In November 1998, Atlantic Capital H, a wholly-owned subsidiary financing trust, issued $25 million 3 in aggregate liquidation amount of 7 A% Cumulative Trust Preferred Capital Securities (representing 1,000,000 preferred securities at $25 per security). At the same time, $25.8 million in aggregate principal amount of 73A% Junior Subordinated Debentures, Series I, due 2028 (73A% Debentures) were issued by ACE to Atlantic Capital II. For consolidated financial reporting purposes, ACE's 73A% Debentures are eliminated in consolidation against the trust's investment in the 73A% Debentures. The trust preferred securities are subject to mandatory redemption upon payment of the 73A% Debentures at maturity or upon redemption. The 73A,%Debentures are subject to redemption, in whole or in part at the option of ACE, at 100% of their principal amount plus accrued interest, after an initial period during which they may not be redeemed and at any time upon the occurrence of certain events.
Atlantic Capital I is a wholly-owned subsidiary financing trust which is structured similarly to Atlantic Capital II (discussed above). Atlantic Capital I had $70 million (2,800,000 securities with a stated liquidation preference of $25 each) of 8.25% Cumulative Quarterly Income ACE Obligated Mandatorily Redeemable Pre ferred Securities outstanding during 2000, 1999, and 1998.
The combination of the obligations of ACE pursuant to the Debentures held by Atlantic Capital I and Atlantic Capital IL and ACE's guarantee of distributions with respect to trust securities, to the extent the trusts have funds available therefor, constitute a full ana unconditional guarantee by ACE of the obligations of the trusts under the trust securities that the trusts have issued. ACE is the owner of all of the common securities of the trusts, which constitute approximately 3% of the liquidation amount of all of the trust securities issued by the trusts.
NOTE 17. DEBT Substantially all of ACE's utility plant is subject to the lien of the Mortgage and Deed of Trust dated January 15, 1937, as amended and supplemented, collateralizing ACE's First Mortgage Bonds and Secured Medium Term Notes. ACE's mortgage requires that the electric generating plants being sold (as discussed in Note 11 to the Consolidated Financial Statements) be released from the lien of the mortgage. These assets may be released with a combination of cash, bondable property additions, and credits representing previously issued and retired first mortgage bonds. ACE expects to have sufficient bondable property additions and retired first mortgage bonds to release such assets at fair values.
11-36 Maturities of long-term debt during the next five years are as follows: 2001-$97.2 million; 2002-$221.5 million; 2003-$70. 1 million; 2004-$67. I million; and, 2005-$40. 1 million.
As discussed in Note 8 to the Consolidated Financial Statements, ACE borrowed $228.5 million under a revolving credit facility on December 28, 1999 to provide interim financing for a payment made to terminate a NUG purchased power contract with Pedricktown. In December 2000, ACE exercised its option to convert the revolving loan balance to a term loan, which is due in two installments; (1) 25% of the principal balance is due December 20, 2001, and (2) the remaining term loan principal is due December 20, 2002. ACE intends to repay this debt with proceeds from the expected issuance of transition bonds. (See Note 7 to the Consolidated Financial Statements for information concerning transition bonds.)
ACE redeemed $46.0 million of 6.83% Medium Term Notes at maturity on January 26, 2000.
11-37 Long-term debt outstanding as of December 31, 2000 and 1999 is presented below. Maturity December 31, Type of Debt Date 2000 1999 (Dollars in Thousands) Secured debt Medium Term Notes Series B (6.83%) ...... 2000 $ - $ 46,000 Medium Term Notes Series C (6.86%) ...... 2001 40,000 40,000 Medium Term Notes Series C (7.02%) ...... 2002 30,000 30,000 Medium Term Notes Series B (7.18%) ...... 2003 20,000 20,000 Medium Term Notes Series D (6.00%) ...... 2003 20,000 20,000 Medium Term Notes Series A (7.98%) ...... 2004 30,000 30,000 Medium Term Notes Series B (7.125%) ...... 2004 28,000 28,000 Medium Term Notes Series C (7.15%) ...... 2004 9,000 9,000 Medium Term Notes Series B (6.45%) ...... 2005 40,000 40,000 Medium Term Notes Series D (6.19%) ...... 2006 65,000 65,000 63A% Pollution Control Series ...... 2006 2,200 2,275 Medium Term Notes Series C (7.15%) ...... 2007 1,000 1.000 Medium Term Notes Series B (6.76%) ...... 2008 50,000 50,000 Medium Term Notes Series C (7.25%) ...... 2010 1,000 1,000 5 6 A% First Mortgage Bonds ...... 2013 68,600 68,600 Medium Term Notes Series C (7.63%) ...... 2014 7,000 7,000 Medium Term Notes Series C (7.68%) ...... 2015 15,000 15,000 Medium Term Notes Series C (7.68%) ...... 2016 2,000 2,000 6.80% Pollution Control Series A ...... 2021 38,865 38,865 7% First Mortgage Bonds ...... 2023 62,500 62,500 5.60% Pollution Control Series A ...... 2025 4,000 4,000 7% First Mortgage Bonds ...... 2028 75,000 75,000 6.15% Pollution Control Series A ...... 2029 23,150 23,150 7.20% Pollution Control Series A ...... 2029 25,000 25,000 7% Pollution Control Series B ...... 2029 6,500 6,500 663,815 709,890 Unsecured debt 6.46% Medium Term Notes Series A ...... 2002 20,000 20,000 6.63% Medium Term Notes Series A ...... 2003 30,000 30,000 7.52% Medium Term Notes Series A ...... 2007 5,000 5,000 7.50% Medium Term Notes Series A ...... 2007 10,000 10,000 65,000 65,000 Other Obligations 7.11% Term Loan ...... 2001 57,125 57,125 7.11 % Term Loan ...... 2002 171,375 171,375 Unamortized Premium and Discount, Net ...... (2,462) (2,563) Current Maturities of Long-Term Debt ...... (97,200) (46,075) Total Long Term Debt ...... 857,653 954,752 Variable Rate Demand Bonds, Pollution Control Series A* ...... 2014 18,200 18,200 Variable Rate Demand Bonds, Pollution Control Series B* ...... 2017 4,400 4,400 Total Long Term Debt and Variable Rate Demand Bonds ...... $880,253 $977,352 Variable Rate Demand Bonds (VRDB) are classified as current liabilities because the VRDB are due on demand by the bondholder. However, bonds submitted to ACE for purchase are remarketed by a remarketing agent on a best efforts basis. ACE expects that bonds submitted for purchase will continue to be remarketed successfully due to ACE's credit worthiness and the bonds' interest rates being set at market ACE also may utilize one of the fixed rate/fixed term conversion options of the bonds. Thus, ACE considers the VRDB to be a source of long-term financing. Average interest rates on the VRDB were 3.9% for 2(XWO and 2.8% for 1999.
11-38 NOTE 18. FAIR VALUE OF FINANCIAL INSTRUMENTS
The year-end fair value of certain financial instruments are listed below. The fair values were based on quoted market prices of ACE's securities or securities with similar characteristics.
2OOO 1999 Carrying Fair Carrying Fair Value Value Value Value (Dollars in Thousands) Investments ...... $112,501 $112,501 $105,371 $105,371 Long Term Debt ...... 857,653 850,753 954,752 921,844 Preferred Stock Subject to Mandatory Redemption ... 23,950 24,369 23,950 23,950 Preferred Securities of Subsidiary Trusts Subject to Mandatory Redemption ...... 95,000 92,914 95,000 79,750
NOTE 19. LONG-TERM PURCHASED POWER CONTRACTS As discussed in Note 6 to the Consolidated Financial Statements, the net present value of expected losses under uneconomic purchased power contracts that existed when electric utility deregulation occurred in the third quarter of 1999 was included in the extraordinary item recorded in 1999.
Based on existing contracts as of December 31, 2000, ACE's commitments during the next five years for capacity (724 MW) and energy under long-term purchased power contracts are estimated to be as follows: $288 million in 2001, $254 million in 2002; $216 million in 2003; $209 million in 2004; and $236 million in 2005.
To replace the output of the electric generating units expected to be sold during 2001, ACE plans to increase the amount of power it purchases to supply the BGS load. ACE intends to manage BGS supply requirements (net of sources otherwise available to it at any particular time) through the use of a portfolio approach, including the use of competitive bidding.
NOTE 20. LEASES
Nuclear Fuel The ownership interests of ACE in nuclear fuel at Peach Bottom, Salem, and Hope Creek are financed through nuclear fuel energy contracts, which are accounted for as capital leases. Payments under the contracts are based on the quantity of nuclear fuel burned by the plants. The obligation of ACE under the contracts is generally the net book value of the nuclear fuel financed, which was $28.4 million, in total, as of December 31, 2006. As discussed in Note 11 to the Consolidated Financiai Statements, under agreements for the sale of ACE's ownership interests in nuclear power plants, the nuclear fuel is to be sold at its net book value upon completion of the sales.
Leased nuclear fuel costs included in operating expenses were $14.2 million for 2000, $14.8 million for 1999, and $12.7 million for 1998.
Lease Commitments ACE also leases other types of property and equipment for use in its operations. Amounts charged to operating expenses for these leases were $10.1 million in 2000, $7.6 million in 1999, and $4.6 million in 1998. Future minimum rental payments for all non-cancelable lease agreements, excluding nuclear fuel, are less than $10 million per year for each of the next five years.
11-39 NOTE 21. PENSION AND OTHER POSTRETIREMENT BENEFITS The employees of ACE and other Conectiv subsidiaries are provided pension benefits and other postretirement benefits under Conectiv benefit plans. The amounts shown below are for the benefit plans of Conectiv and include amounts for all covered employees of the Conectiv subsidiaries which elect to participate in the benefit plans.
Assumptions 2000 1999 1998 Discount rates used to determine projected benefit obligation as of December 31... 7.50% 7.75% 6.75% Expected long-term rates of return on assets ...... 9.50% 9.00% 9.00% Rates of increase in compensation levels ...... 4.50% 4.50% 4.50% Health-care cost trend rate on covered charges ...... 8.00% 6.50% 7.00% The health-care cost trend rate, or the expected rate of increase in health-care costs, is assumed to gradually decrease to 5.0% by 2004. Increasing the health-care cost trend rates of future years by one percentage point would increase Conectiv's total accumulated postretirement benefit obligation by $10.1 million and would in crease Conectiv's total annual aggregate service and interest costs by $0.9 million. Decreasing the health-care cost trend rates of future years by one percentage point would decrease Conectiv's total accumulated postretirement benefit obligation by $10.5 million and would decrease Conectiv's total annual aggregate service and interest costs by $1.0 million.
The following schedules reconcile the beginning and ending balances of the pension and other postretirement benefit obligations and related plan assets for Conectiv. Other postretirement benefits include
.4 I medical benefits for retirees and their spouses and retiree life insurance.
Change in Conectiv's Benefit Obligation Other Postretirement Pension Benefits Benefits 2000 1999 2000 1999 (Dollars in Thousands) Benefit obligation at beginning of year .... $673,095 $748,689 $194,031 $232,374 Service cost ...... 18,388 20,288 3,908 5,282 Interest cost ...... 51,856 51,442 14,513 13,839 Plan participants' contributions ...... - - 511 500 Plan amendment ...... 4,359 5,500 Actuarial (gain) loss ...... 12,689 (75,244) (43,861) Benefits paid ...... (66,438) (64,671) (16,970) (9,436) O ther ...... 672 (7,409) (4,667) Benefit obligation at end of year ...... $694,621 $673,095 $201,493 $194,031
Change in Conectiv's Plan Assets Other Postretirement Pension Benefits Benefits 2000 1999 2000 1999 (Dollars in Thousands) Fair value of assets at beginning of year . $1,017,844 $ 951,474 $120,072 $ 95,164 Actual return on plan assets ...... (3,363) 138,450 166 13,494 Employer contributions ...... - - 15,945 25.017 Plan participants' contributions ...... - - 511 500 Benefits paid ...... (66,438) (64,671) (16,970) (9.436) O ther ...... - (7,409) - (4.667) Fair value of assets at end of year ...... $ 948,043 $1,017,844 $119,724 $120.072
11-40 Reconciliation of Funded Status of Conectiv's Plans Other Pirelrentet Pension Benefits Benefits 2000 1999 200 199 (Dollars In Thomiaý) Funded status at end of year ...... $ 253,422 $ 344,749 $(81,769) $(73,959) Unrecognized net actearial (gain) ...... (181,008) (300,864) (46,246) (63,286) Unrecognized prior service cost ...... 7,794 4,129 149 198 Unrecognized net transition (asset) obligation ...... (10,245) (13,009) 37,531 40,659 Net amount recognized at end of year ...... $ 69,963 $ 35,005 $(90,335) $(96,388) Portion applicable to ACE ...... $ (26,948) $ (20,309) $(37,614) $(42,952)
Based on fair values as of December 31, 2000, Conectiv's pension plan assets were comprised of publicly traded equity securities ($606.7 million or 64%) and fixed income obligations ($341.3 million or 36%). Based on fair values as of December 31, 2000, Conectiv's other postretirement benefit plan assets included equity securities ($77.8 million or 65%) and fixed income obligations ($41.9 million or 35%).
Components of Conectiv's Net Periodic Benefit Cost Pension Benefits Other Postretremnt Benefits 2000 1999 1996 2000 1999 1991 (Dollars In lhousands) Service cost ...... $ 18,388 $ 20,288 $ 18,933 $3,908 $ 5,282 $ 5,221 Interest cost ...... 51,856 51,442 48,291 14,513 13,839 13,636 Expected return on assets ...... (90,037) (83,999) (81,259) (8,645) (6,769) (4,845) Amortization of: Transition obligation (asset) ...... (2,764) (2,764) (2,764) 3,128 3,128 3,244 Prior service cost ...... 694 406 1,911 49 49 50 Actuarial (gain) ...... (13,767) (4,248) (9,165) (3,060) (1,059) (567) Benefit cost before items below ...... (35,630) (18,875) (24,053) 9,893 14,470 16,739 Special termination benefits ...... 59,610 2,682 Curtailment (gain) loss ...... (10,256) 6,614 Settlement (gain) loss ...... (45,291) 6,457 Total net periodic benefit cost ...... $(35,630) $(18,875) $(019,990) $9,893 $14,470 $32,492 Portion of net periodic benefit cost applicable to ACE ...... $ 6,154 $ 9,546 $ 18,118 $4,607 $ 8,856 $22,475 ACE portion of net periodic benefit cost included in results of operations ...... $ 6,154 $ 9,546 $ 15,514 $4,607 $ 8,856 $19,553
The special termination benefits and curtailment and settlement gains and losses shown above for 1998 resulted from 1998 Merger-related employee separation programs primarily for ACE and DPL employees. ACE's 1998 results of operations include an $8.3 million charge to the cost of pension benefits and a $7.9 million charge to the cost of other postretirement benefits for the net expense of special termination benefits and curtailment and settlement gains and losses attributed to ACE's employees.
Conectiv also maintains 401(k) savings plans for covered employees. Conectiv contributes to the plans, in the form of Conectiv stock, at varying levels up to $0.50 for each dollar contributed by employees, up to 6% of employee base pay. The amount expensed for ACE's share of the 401(k) savings plan was $1.0 million in 2000. $1.6 million in 1999, and $1.9 million in 1998.
[1-41 NOTE 22. COMMITMENTS AND CONTINGENCIES
Commitments
ACE's capital expenditures for 2001 are estimated to be approximately $65 million. See Note 19 to the Consolidated Financial Statements for commitments related to long-term purchased power contracts and Note 20 to the Consolidated Financial Statements for commitments related to leases.
Environmental Matters ACE is subject to regulation with respect to the environmental effects of its operations, including air and water quality control, solid and hazardous waste disposal, and limitation on land use by various federal, regional, state, and local authorities. Costs may be incurred to clean up facilities found to be contaminated due to past disposal practices. Federal and state statutes authorize governmental agencies to compel responsible parties to clean up certain abandoned or uncontrolled hazardous waste sites. ACE is a potentially responsible party at a state superfund site and has agreed, along with other responsible parties, to remediate the site pursuant to an Administrative Consent Order with the New Jersey Department of Environmental Protection. ACE is also a defendant in an action to recover costs at a federal superfund site in Gloucester, New Jersey. ACE's liability for clean-up costs is affected by the activities of these governmental agencies and private land-owners, the nature of past disposal practices, the activities of others (including whether they are able to contribute to clean-up costs), and the scientific and other complexities involved in resolving clean-up-related issues (including whether ACE or a corporate predecessor is responsible for conditions on a particular parcel). There is $1.0 million included in ACE's current liabilities as of December 31, 2000 and 1999, for remediation activities at these sites. ACE does not expect such future costs to have a material effect on its financial position or results of operations.
Nuclear Insurance In conjunction with ACE's ownership interests in Peach Bottom, Salem, and Hope Creek, ACE could be assessed for a portion of any third-party claims associated with an incident at any commercial nuclear power plant in the United States. Under the provisions of the Price Anderson Act, if third party claims relating to such an incident exceed $200 million (the amount of primary insurance), ACE could be assessed up to $30.7 million on an aggregate basis for such third-party claims. In addition, Congress could impose a revenue-raising measure on the nuclear industry to pay such claims. The co-owners of Peach Bottom, Salem, and Hope Creek maintain property insurance coverage of approxi mately $1.8 billion for each unit for loss or damage to the units, including coverage for decontamination expense and premature decommissioning. In addition, ACE is a member of an industry mutual insurance company (NEIL), which provides replacement power cost coverage in the event of a major accidental outage at a nuclear power plant. Under these coverages, ACE is subject to potential retrospective loss experience assessments of up to $1.9 million on an aggregate basis. Under changes in NEIL's by-laws effective December 31, 2000, member account balances no longer exist. NEIL members who sell their interests in nuclear electric generating plants after December 31, 2000, may choose either (I) to continue to receive certain policyholders' distributions from NEIL (if, as, and when declared) over a 5-year period or (2) to remain a NEIL member by purchasing other insurance products from NEIL and thus remain eligible for policyholders' distributions (if. as, and when declared) for a longer period. If the sale of ACE's ownership interests in nuclear electric generating plants is completed, then ACE will be able to choose one of the two options available to it.
Other On October 24, 2000, the City of Vineland, New Jersey, filed an action in a New Jersey Superior Court to acquire ACE electric distribution facilities located within the City limits by eminent domain. The City has offered
11-42 approximately $11 million for these assets, including the right to provide electric service in this area. ACE believes that, properly evaluated, the assets sought by the City are worth approximately $40 million.
NOTE 23. BUSINESS SEGMENTS Conectiv's organizational structure and management reporting information is aligned with Conectiv's busi ness segments, irrespective of the subsidiary, or subsidiaries, through which a business is conducted. Businesses are managed based on lines of business, not legal entity. Business segment information is not produced, or reported, on a subsidiary by subsidiary basis. Thus, as a Conectiv subsidiary, no business segment information (as defined by SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information") is available for ACE on a stand-alone basis. However, ACE's principal business is expected to be the transmission and distribution of electricity upon completion of the sale of the electric generating plants of ACE (as discussed in Note 11 to the Consolidated Financial Statements). The transfer of the combustion turbines to Conectiv effective July 1, 2000, resulted in electricity transmission and distribution representing a greater proportion of ACE's business.
NOTE 24. QUARTERLY FINANCIAL INFORMATION (UNAUDITED) The quarterly data presented below reflect all adjustments necessary in the opinion of management for a fair presentation of the interim results. Quarterly data normally vary seasonally because of temperature varia tions, differences between summer and winter rates, and the scheduled downtime and maintenance of electric generating units. 2000 First Second Third Fourth Quarter Quarter Quarter Quarter Total (Dollars in Thousands) Operating Revenues ...... $208,886 $236,249 $282,966 $240,282 $968,383 Operating Income ...... 22,680 36,411 66,123 41,310 166,524 Net Income ...... 1,573 14,113 28,155 10,593 54,434 Earnings Applicable to Common Stock ...... 1,040 13,581 27,621 10,060 52,302 1999 First Second Third Fourth Quarter Quarter Quarter Quarter Total (Dollars In Thousands) Operating Revenues ...... $244,839 $246,143 $351,372 $234,231 $1,076,585 Operating Income ...... 38,034 35,967 85,300 12,630 171,931 Income (Loss) Before Extraordinary Item ...... 15,091 14,878 35,953 (1,992) 63,930 Extraordinary Item (1) ...... - - (17,483) (40,612) (58,095) Net Income/(Loss) ...... 15,091 14,878 18,470 (42,604) 5,835 Earnings (Loss) Applicable to Common Stock .... 14,558 14,345 17,937 (43,137) 3,703 (1) For information concerning the extraordinary item recorded in the third and fourth quarters of 1999, see Note 6 to the Consolidated Financial Statements.
ACE's operating results for the third quarter of 1999 include special charges for the costs of employee separations, additional costs related to the 1998 Merger, and certain other nonrecurring items which caused operating income to decrease $12.3 million and income before extraordinary item, net income, and earnings applicable to common stock to decrease $7.3 million.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Reference is made to Item 4 of Report on Form 8-K filed March 5, 1998.
[1-43 PART mI
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Directon Business Experience during Past 5 Year. As of December 31, 2000 Howard E. Cosgrove, 57.. Elected 1998 as Chairman of the Board and Chief Executive Officer of Conectiv Chairman of the Board and Chairman of the Board of Atlantic City Electric Company. Elected 1992 as Chairman of the Board, President and Chief Executive Officer of Delmarva Power & Light Company Thomas S. Shaw, 53 ..... Elected 2000 as President and Chief Operating Officer of Conectiv. Elected 1998 Director as Executive Vice President of Conectiv. Elected 1992 as Senior Vice President of Delmarva Power & Light Company. John C. van Roden, 51 ... Elected 2000 as Senior Vice President and Chief Financial Officer of Conectiv Director and Chief Financial Officer of Atlantic City Electric Company. Elected 1998 as Senior Vice President and Chief Financial Officer of Conectiv. Principal, Cook and Belier, Inc. in 1998. Senior Vice President/Chief Financial Officer and Vice President/Treasurer, Lukens, Inc. from 1987 to 1998. Barbara S. Graham, 52... Elected 1999 as Senior Vice President of Conectiv. Elected 1998 as Senior Vice Director President and Chief Financial Officer of Conectiv. Elected 1994 as Senior Vice President, Treasurer and Chief Financial Officer of Delmarva Power & Light Company.
Executives Information about ACE's executive officers is included under Item 1.
III-I ITEM 11. EXECUTIVE COMPENSATION
Personnel and Compensation Committee Interlocks and Insider Participation The Personnel and Compensation Committee is comprised solely of non-employee directors. There are no Personnel and Compensation Committee interlocks.
Summary Compensation Table For the year ended December 31, 2000, the following table shows information regarding the compensation earned during the past year by the President of ACE, during the past three fiscal years for the Chief Financial Officer of ACE, and during the past year for ACE's other three most highly compensated executive officers.
Table 1--SUMMARY COMPENSATION TABLE
Long Term Compensation Annual Compensation Awards Payouts Variable Restricted Securities Compensation Other Annual Stock Underlying LTIP AU Other Name and Principal Position Year(l) Salary (Bonus)(2) Compensation Awards(3) Options Payouts(4) Compensation(S) J.M. Rigby, President ...... 2000 $182,800 $70,240 0 $12,500 28,500 - $4,884 J.C. van Roden, Chief Financial Officer..... 2000 $275.000 $85,400 0 $90,625 34,700 - $9,810 1999 $250,000 $72,500 0 - 170,000 - $8.342 1998 $ 17,686 - 0 -
J.C. Weller, Vice President .... 2000 $158,794 $34.500 0 $41,000 11,100 - $4,429
J.M. Castaldi. Vice President .. 2000 $126,000 $28.800 0 0 6.800 - $4,580
J.M. Wathen, Director ...... 2000 $120,000 $16,800 0 $20,571 6.500 - $4,362
(1) Except for J.C. van Roden, this group of executive officers was appointed as of June 2000 and, therefore, only compensation for 2000 is listed. Mr. van Roden joined Conectiv and ACE on November 30, 1998, and the 1998 salary shown is his actual salary. Mr. Howard E. Cosgrove and Mr. Thomas S. Shaw served for the first half of 2000 as officers. Mr. Cosgrove's compensation for the past three years is as follows: Salary: 1998-$600,000, 1999-$600,000, 2000-$600,000; Variable Compensation (Bonus): 1998-$300,000 of which $150,000 purchased Restricted Stock Units ("RSU's"), 1999-$435,000, of which $217,500 pur chased RSU's, 2000-$496,800, of which $248,400 purchased RSU's; Other Annual Compensation: 1998, 1999, 2000-$0; Restricted Stock Awards: 1998-$0, 1999-$187,500, 2000-$271,875; Securities Un derlying Options: 1998-360,000, 1999-57,000, 2000-124,000; LTIP Payouts: 1998-"572,134, 1999 $0, 2000-$0; Dividends deferred on Dividend Equivalent Units ("DEU's"): 1998-$23,100, 1999 $48,263, 2000-$92,400; All other compensation: 1998-$512,329, 1999-$18,204, 2000-$17,682 (which includes $282, term life insurance premiums paid by Conectiv, $3,000 in Conectiv matching contributions to Conectiv's Savings and Investment Plan and $14,400 in Conectiv matching contributions to Conectiv's Deferred Compensation Plan). Mr. Shaw's compensation for the past three years is as follows: Salary: 1998-$325,000, 1999-$325,000, 2000-$354,700; Variable Compensation (Bonus): 1998-5156,000, of which $78,000 purchased RSU's, 1999-$240,000, of which $120,000 purchasing RSU's, 2000-$245,000, of which $122,500 purchased RSU's, Other Annual Compensation for 1998, 1999, 2000-$0; Restricted Stock Awards: 1998-$0, 1999-$291,500, 2000-$150,000; Securities Underlying Options: 1998 170,000, 1999-26,000, 2000-51,900; LTIP Payouts: 1998-$155,267, 1999-$0, 2000-$0; Dividends deferred on DEU's: 1998-$7,700, 1999-$18,975, 2000-$37,367. All other compensation: 1998 $9,478, 1999-$8,258, 2000-$10,606 (which includes $156, term life insurance premiums paid by Conectiv, $3.267 in Conectiv matching contributions to Conectiv's Savings and Investment Plan and $7,183 in Conectiv matching contributions to Conectiv's Deferred Compensation Plan).
111-2 (2) The target award is 40% of annualized salary for Mr. Rigby, 45% for Mr. van Roden, 30% for Mr. Weller, 20% for Mr. Castaldi and 20% for Mr. Wathen. For 2000, the dollar value of the bonus reported above has been reduced by the portion of the bonus deferred, as follows: J.M. Rigby ($87,800 bonus with $17,560 purchasing RSU's; J.C. van Roden ($170,800 bonus with $85,400 purchasing RSU's); J.C. Weller ($69,000 bonus with $34,500 purchasing RSU's); J.M. Castaldi ($36,100 bonus with $7,220 purchasing RSU's); J.M. Wathen ($33,600 bonus with $16,800 purchasing RSU's). The 1999 bonus reported above for J.C. van Roden has been reduced by the portion of the bonus deferred ($145,000 bonus with $72,500 purchasing RSU's). (3) A mandatory 20% of the bonus (reported in this Table as "Variable Compensation") and any additional portion of the bonus that an executive elects to defer (up to an additional 30%) is deferred for at least three years under the Management Stock Purchase Program ("MSPP") and used to purchase RSU's at a 20% discount. The dollar value of RSU's deferred under MSPP in 2000 (inclusive of the discounted portion), based on the fair market value at the award date, was as follows: J.M. Rigby ($12,500 of which $2,500 is the discount); J.C. van Roden ($90,625 of which $18,125 is the discount); JC. Weller ($41,000 of which $8,200 is the discount), J.M. Wathen ($20,571 of which $4,114 is the discount). J.M. Castaldi was not a member of the plan in 1999. At the end of 2000, the number and value of the aggregate restricted stock holdings (including RSU's, Performance Accelerated Restricted Stock ("PARS") and special grants) val ued at $20.0625, the closing Conectiv common stock price on December 29, 2000, for the individuals identified in the Summary Compensation Table was as follows; for Mr. Rigby, 4,612 restricted stock holdings valued at $92,528; for Mr. van Roden, 12,217 restricted stock holdings valued at $245,104; for Mr. Weller, 6,174 restricted stock holdings valued at $123,866; for Mr. Wathen 3,671 restricted stock holdings valued at $73,549; for Mr. Castaldi 1,000 restricted stock holdings valued at $20,063. (4) Dividends on shares of restricted stock and dividend equivalents are accrued at the same rate as that paid to all holders of Conectiv common stock. As of December 31, 2000, Mr. Rigby held 3,800 shares of restricted stock and 11,750 DEU's; Mr. van Roden held 7,700 shares of restricted stock (3,000 for 1999 and 4,700 for 2000) and 27,350 DEU's (10,000 for 1999 and 17,350 for 2000); Mr. Weller held 4,000 shares of restricted stock and 12,350 DEU's; Mr. Castaldi held 1,000 shares of restricted stock and 3,400 DEU's; Mr. Wathen held 4,000 shares of restricted stock and 7,250 DEU'S. Dividends paid on DEU's for 1998 were as follows: Mr. Rigby, $3,480, Mr. Weller, $3,886, Mr. Wathen, $2,320. Dividends paid on DEU's for 1999 were as follows: Mr. Rigby, $7,260, Mr. van Roden, $8,250, all of which was deferred into the Conectiv Deferred Compensation Plan; Mr. Weller, $8,289, Mr. Wathen, $4,840. Dividends paid on DEU's for 2000 were as follows: Mr. Rigby, $10,340, Mr. van Roden, $20,251, all of which was deferred into the Conectiv Deferred Compensation Plan; Mr. Weller, $8,289, Mr. Castaldi, $2,992, and Mr. Wathen, $6,380. Holders of re stricted stock are entitled to receive dividends as, if and when declared. (5) The amount of All Other Compensation for each of the named executive officers for fiscal year 2000 include the following: Mr. Rigby, $4,533 in Conectiv matching contributions to Conectiv's Savings and Investment Plan and $351 in term life insurance premiums paid by Conectiv; for Mr. van Roden, $5,100 in Conectiv matching contributions to Conectiv's Savings and Investment Plan, $3,150 in Conectiv matching contribu tions to Conectiv's Deferred Compensation Plan and $156 in term life insurance premiums paid by Conectiv; for Mr. Weller, $3,193 in Conectiv matching contributions to Conectiv's Savings and Investment Plan, and $1,236 in term life insurance premiums paid by the Conectiv; for Mr. Castaldi, $3,780 in Conectiv matching contributions to Conectiv's Savings and Investment Plan, and $800 in term life insurance premi ums paid by the Conectiv; and for Mr. Wathen, $3,525 in Conectiv matching contributions to Conectiv's Savings and Investment Plan and $837 in term life insurance premiums paid by Conectiv.
111-3 Table 2-Conectiv Option Grants in Last Fiscal Year(l) Number of % of Total Securities Optiom Underlying Granted to Exercise Grant Date Options Employees In Price Expiration Present Name Granted (#) Fiscal Year ($/Sb) Date Value(3) J.M. Rigby ...... 28,500(2) 4.1% $16.5625 1/3/10 $115,710 J.C. van Roden ...... 34,700(2) 5.0% $16.5625 1/3/10 $140,882 J.C. Weller ...... 11,100(2) 1.6% $16.5625 1/3/10 $ 45,066 J.M. Castaidi ...... 6,800(2) 1.0% $16.5625 1/3/10 $ 27,608 J.M. Wathen ...... 6,500(2) 0.9% $16.5625 1/3/10 $ 26,390
(1) Currently, Conectiv does not grant stock appreciation rights. For Mr. Cosgrove the number of securities underlying options granted in 2000 were 124,000, or 18% of total options granted to employees in 2000; those options granted had an exercise price per share of $16.5625, an expiration date of January 3, 2010. and a grant date present value of $503,440. For Mr. Shaw the number of securities underlying options granted in 2000 were 51,900 or 7.5% of total options granted to employees in 2000, those options granted had an exercise price per share of $16.5625, an expiration date of January 3, 2010 and a grant date present value of $210,714. (2) Denotes Nonqualified Stock Options. One-half of such Options vest and are exercisable at the end of the second year from date of grant. Second one-half vest and are exercisable at end of the third year from the date of grant. (3) Determined using the Black-Scholes model, incorporating the following material assumptions and adjust ments: (a) exercise price of $16.5625, equal to the Fair Market Value as of date of grant (b) an option term of ten years (c) risk-free rate of return of 5.00% (d) volatility of 20.00% and (e) dividend yield of 4.75%.
Table 3-Aggregated Conectiv Option Exercises in Last Fiscal Year and FY-End Option Values(l) Number of Securities Value of Unexercised Shares Underlying Uueercised in-the-Money Acquired Value Options at FY-End(3) Options at FY-End(2) Name On Exercise Realized ($)(2) Exercdsable/Unexercisable ExercisablefUnexercisable J.M. Rigby ...... 0 0 3,000/37,500 $ 0/99,750 J.C. van Roden ...... 0 0 0/204,700 $0/121,450 J.C. Weller ...... 0 0 3,500/36,300 $ 0/38,500 J.M. Castaldi ...... 0 0 0/6,800 $ 0/23,800 J.M. Wathen ...... 0 0 2,635112,500 $ 0/22,750 (1) Neither Mr. Cosgrove nor Mr. Shaw exercised any options during 2000. Mr. Cosgrove has 35,900 options that are exercisable and 511,000 options unexercisable. 124,000 out of the 511,000 unexercisable options are in the money. The value of unexercised in the money options at fiscal year-end exercisable/unexercisable is $0/$434,000. Mr. Shaw has 10,000 options that are exercisable and 237,900 options unexercisable. 51,900 out of 237,900 unexercisable options are in the money. The values of unexercised in the money options at fiscal year-end exercisable/unexercisable are $0/$181,650. (2) The closing price for Conectiv's common stock as reported by the New York Stock Exchange on December 29, 2000 was $20.0625. Any value in the options is based on the difference between the exercise price of the options and the value at the time of the exercise (e.g., $20.0625 as of the close of business on December 29, 2000), which difference is multiplied by the number of options exercised. (3) 28,500 out of 37,500 of Mr. Rigby's unexercisable options are in the money. 34,700 out of 204,700 of Mr. van Roden's unexercisable options are in the money. 11,000 out of 36,300 of Mr. Weller's unexercisable options are in the money. All of Mr. Castaldi's 6,800 unexercisable options are in the money. 6,500 out of 12,500 of Mr. Wathen's unexercisable options are in the money. Unless vesting is accelerated under the terms of Conectiv's Long-Term Incentiv Plan ("LTIP"), none of the remaining options may be exercised earlier than two years from date of grant for regular, non-performance based options and nine and one half years from date of grant for performance based options (subject to accelerated vesting for favorable stock price performance).
111-4 Table 4-Conectiv Long-Term Incentive Plans-Awards in Last Fiscal Year(l) Number of Restricted Performance Period Shares/Dividend Until Maturation Name Equivalent Units (#) Or Payout(2) J.M. Rigby ...... 1,400 shares/5,100 units 1/3/07 J.C. van Roden ...... 4,700 shares/17,350 units 1/3/07 J.C. Weller ...... 1,300 shares/4,900 units 1/3/07 J.M. Castaldi ...... 800 shares/3,000 units 1/3/07 J.M. Wathen ...... 800 shares/2,900 units 1/3/07 (1) Mr. Cosgrove was granted 16,600 shares of PARS and 62,000 DEU's in 2000, with a performance period ending January 3, 2007, and with the same terms and conditions described below in note 2. Mr. Shaw was granted 7,000 shares of PARS and 25,950 DEU's in 2000, with a performance period ending January 3, 2007, and with the same terms and conditions described below in note 2. (2) Awards of PARS and DEU's were made to all of the named executive officers. The payout of shares of PARS may potentially be "performance accelerated." Restrictions may lapse any time after 3 years (i.e., after January 3, 2003) upon achievement of favorable stock price performance goals. In the absence of such favorable performance or accelerated vesting under the terms of Conectiv's LTIP, restrictions lapse after 7 years (i.e., January 3, 2007) provided that at least a defined level of average, total return to stockholders is achieved. As of December 31, 2000, Mr. Cosgrove's 16,600 PARS were valued at $333,038, Mr. Shaw's 7,000 PARS were valued at $140,438, Mr. Rigby's 1,400 PARS were valued at $28,088, Mr. van Roden's 4,700 PARS were valued at $94,294; Mr. Weller's 1,300 PARS were valued at $26,081, Mr. Wathen's and Mr. Castaldi's 800 PARS were valued at $16,050. These values are based on the December 29, 2000 closing Conectiv common stock price of $20.0625. For DEU's, one DEU is equal in value to the regular quarterly dividend paid on one share of Conectiv common stock. The DEU's shown are payable in cash for four quarters over a one-year period ending with the quarterly dividend equivalent payable January 31, 2001. At that time, the 2000 DEU award lapses.
Pension Plan The Conectiv Retirement Plan includes the Cash Balance Pension Plan and certain "grandfathering" provi sions relating to the Delmarva Retirement Plan and the Atlantic Retirement Plan that apply to employees who had attained either 20 years of service or age 50 on the effective date of the Cash Balance Pension Plan (January 1, 1999). Certain executives whose benefits from the Conectiv Retirement Plan are limited by the application of federal tax laws also receive benefits from the Supplemental Executive Retirement Plan.
Cash Balance Pension Plan The named executive officers participate in the Conectiv Retirement Plan and earn benefits that generally become vested after five years of service. Annually, a record-keeping account in a participant's name is credited with an amount equal to a percentage of the participant's total pay, including base pay, overtime and bonuses, depending on the participant's age at the end of the plan year, as follows: Age at end of Plan Year % of Pay Under 30 ...... 5 30 to 34 ...... 6 35 to 39 ...... 7 40 to 44 ...... 8 45 to 49 ...... 9 50 and over ...... 10
111-5 These accounts also receive interest credits based on average U.S. Treasury Bill rates for the year. in addition, certain annuity benefits earned by participants under the former Delmarva and Atlantic Energy Retire ment Plans are fully protected as of December 31, 1998, and were converted to an equivalent cash amount and included in each participant's initial cash balance account. When a participant terminates employment, the amount credited to his or her account is converted into an annuity or paid in a lump sum.
Supplemental Retirement Benefits Under federal tax laws and regulations, benefits payable under the Conectiv Retirement Plan are limited. Supplemental retirement benefits are provided to employees to whom these limitations apply (including executive officers), so that they receive the retirement benefits for which they would be eligible in the absence of these limitations.
Estimated Retirement Benefits Payable to Named Executive Officers
The following table shows the estimated retirement benefits, including supplemental retirement benefits under the plans applicable to the named executives, that would be payable if he or she were to retire at normal retirement age (65), expressed in the form of a lump sum payment. Years of service credited to each named executive officer as of his or her normal retirement date are as follows: Mr. Rigby--43, Mr. van Roden-15, Mr. Weller-2 1, Mr. Castaldi-42, and Mr. Wathen-27.
Name Year of 65th Birthday Lump Sum Value J.M. Rigby ...... 2021 $1,090,000(1) J.C. van Roden ...... 2014 $ 522,000(1) J.C. W eller ...... 2014 $ 454,000(1) J.M . Castaldi ...... 2012 $1,080,000(l) J.M. W athen ...... 2020 $ 599,000(1) (1) Amounts include (i) interest credits for cash balances projected to be 5.80% per annum on annual salary credits and prior service balances, if any, and (ii) accrued benefits as of December 31, 2000, under retire ment plans then applicable to the named executive officer. Benefits are not subject to any offset for Social Security payments or other offset amounts and assume no future increases in base pay or total pay.
Under the Conectiv Retirement Plan's grandfathering provisions, employees who participated in the Delmarva or Atlantic Retirement Plans and who met certain age and service requirements as of January 1, 1999, will have retirement benefits for all years of service up to the earlier of December 31, 2008 or retirement calculated according to their original benefit formula. This benefit will be compared to the cash balance account and the employee will receive whichever is greater. For years after December 31, 2008, all participants' benefits will be calculated under the cash balance plan. Current actuarial estimates and assumptions indicate that all five of the above executives will receive retirement benefits based on the Cash Balance Pension Plan.
Change in Control Severance Agreements and Other Provisions Relating to Possible Change Control For the executive officers of ACE, Conectiv has entered into change in control severance agreements with Messrs. Rigby and van Roden. The agreements are intended to encourage the continued dedication of Conectiv's senior management team. The agreements provide potential benefits for these executives upon actual or construc tive termination of employment (other than for cause) following a change in control of Conectiv, as defined in the agreements. Each affected executive would receive a severance payment equal to three times base salary and bonus, medical, dental, vision, group life and disability benefits for three years after termination of employment. and a cash payment equal to the actuarial equivalent of accrued pension credits equal to 36 months of additional service.
111-6 In the event of a change in control, the Variable Compensation Plan provides that outstanding options become exercisable in full immediately, all conditions to the vesting of PARS are deemed satisfied and shares will be fully vested and nonforfeitable, DEU's will become fully vested and be immediately payable, variable compensation deferred under the Management Stock Purchase Program will be immediately distributed, and payment of variable compensation, if any, for the current year will be decided by the Personnel and Compensa tion Committee. For the Deferred Compensation Plan, this Committee may decide to distribute all deferrals in cash immediately or continue the deferral elections of participants, in which case Conectiv will fully fund a "springing rabbi trust" to satisfy the obligations. An independent institutional trustee will maintain any trust established by reason of this provision.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT All shares of ACE's common stock are owned by Conectiv, ACE's parent company
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS None
111-7 PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) Documents filed as part of this report.
1. Financial Statements
The following financial statements are contained in Item 8 of Part 1I. Pae No. Report of Independent Accountant, PricewaterhouseCoopers LLP ...... 11-15 Consolidated Statements of Income for the years ended December 31, 2000, 1999, and 1998 ...... 11-16 Consolidated Statements of Cash Flows for the years ended December 31, 2000, 1999, and 1998.... 11-17 Consolidated Balance Sheets as of December 31, 2000 and 1999 ...... 11-18 Consolidated Statements of Changes in Common Stockholder's Equity for the years ended December 31, 2000, 1999, and 1998 ...... 11-20 Notes to Consolidated Financial Statements ...... 11-21
2. Financial Statement Schedules Schedule II-Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2000, is presented below. No other financial statement schedules have been filed since the required information is not present in amounts sufficient to require submission of the schedule or because the information required is included in the respective financial statements or the notes thereto.
Schedule iH-Valuation and Qualifying Accounts Years Ended December 31, 2000, 1999, 1998 (Dollars in thousands) Column B Column C Column D Column E Additions Balance at Charged to Balance at beginning cost and Charged to end of Description of period expenses other accounts Deductions period 2000 Allowance for doubtful accounts .... $3,500 $4,248 $3,325(a) $4,423 1999 Allowance for doubtful accounts 3,500 5,590 5,590(a) 3,500 1998 Allowance for doubtful accounts .... 3,500 5,003 5,003(a) 3,500 (a) Accounts receivable written-off.
IV- I 3. Exhibits Exhibit Number 2 Amended and Restated Agreement and Plan of Merger, dated as of December 26, 1996, between DPL, Atlantic Energy, Inc., Conectiv, Inc. and DS Sub, Inc. (Filed with Registration Statement No. 333-18843) 3-A Certificate of Merger of Atlantic Energy, Inc. with and into Conectiv, Inc. filed with Delaware Secretary of State, effective as of March 1, 1998 (Filed with 1998 Form 10-K, file no. 1-3559) 3-B Certificate of Merger of Atlantic Energy, Inc. with and into Conectiv, Inc. filed with New Jersey Department of State, effective as of March 1, 1998 (Filed with 1998 Form 10-K, file no. 1-3559) 3-C Certificate to change name from Conectiv, Inc. to Conectiv filed with the Delaware Secretary of State pursuant to Section 102(a) of the Delaware General Corporation Law (Filed with 1998 Form 10-K, file no. 1-3559) 3-G By-Laws of Atlantic City Electric Company, as amended April 24, 1989 (File No. 1-3559, Form 10 Q for the quarter ended September 31, 1989-Exhibit No. 3) 4-A Mortgage and Deed of Trust, dated January 15, 1937, between Atlantic City Electric Company and The Bank of New York (formerly Irving Trust Company) and Supplemental Indentures through November 1, 1994 (File No. 2-66280--Exhibit No. 2(b); File No. 1- 3559, Form 10-K for year ended December 31, 1980-Exhibit No. 4(d); Form 10-Q for quarter ended June 30, 1981-Exhibit No. 4(a); Form 10-K for year ended December 31, 1983-Exhibit No. 4(d); Form 10-Q for quarter ended March 31, 1984-Exhibit No. 4(a); Form IO-Q for quarter ended June 30, 1984-Exhibit 4(a); Form 10-Q for quarter ended September 30, 1985-Exhibit 4; Form 10-Q for quarter ended March 31, 1986-Exhibit No. 4; Form 10-K for year ended December 31, 1987-Exhibit No. 4(d); Form 10-Q for quarter ended September 30, 1989-Exhibit No. 4(a); Form 10-K for year ended December 31, 1990--Exhibit No. 4(c); File No. 33-49279-Exhibit No. 4(b); File No. 1-3559, Form 10-Q for the quarter ended September 30, 1993-Exhibits 4(a) & 4(b); Form 10-K for the year ended December 31, 1993-Exhibit 4c(i); File no. 1-3559, Form 10-Q for the quarter ended June 30, 1994-Exhibit 4(a); File No. 1-3559, Form 10-Q for the quarter ended September 30, 1994 -Exhibit 4(a); Form 10-K for year ended December 31, 1994-Exhibit 4(c)(1) 4-B Indenture dated as of March 1, 1997 between Atlantic City Electric Company and The Bank of New York filed on Form 8-K, dated March 24, 1997, File No. 1-3559-Exhibit 4(e) 4-C Indenture Supplemental dated as of March 1. 1997 to Mortgage and Deed of Trust dated January 15, 1937 between Atlantic City Electric Company and The Bank of New York filed on Form 8-K dated March 24, 1997, File No 1-3559, Exhibit 4(b) 4-D Amended and Restated Trust Agreement, dated as of October 1, 1996, by and among Atlantic City Electric Company, as Depositor, The Bank of New York, as Property Trustee, The Bank of New York (Delaware) as Delaware Trustee and the Administrative Trustees Named Therein, (File No. I 9760, Form 10-K for year ended December 31, 1996-Exhibit No. 4f(7)) 4-E Junior Subordinated Indenture, dated as of October 1, 1996, by and between Atlantic City Electric Company and The Bank of New York, as Trustee, (File No. 1-9760, Form 10-K for year ended December 31, 1996--Exhibit No. 4f(8)) 4-F Guarantee Agreement, dated as of October 1, 1996, by and between Atlantic City Electric Company as Guarantor, and The Bank of New York as Guarantee Trustee, (File No. 1-9760, Form 10-K for year ended December 31, 1996-Exhibit No. 4f(9)) 4-G Amended and Restated Trust Agreement, dated as of October 1, 1998, by and among Atlantic City Electric Company, as Depositor, The Bank of New York, as Property Trustee, The Bank of New York (Delaware) as Delaware Trustee and the Administrative Trustees Named Therein (Filed with 1998 Form 10-K, file no. 1-3559)
IV-2 Exhibit Number 4-H Junior Subordinated Indenture, dated as of October 1, 1998, by and between Atlantic City Electric Company and The Bank of New York, as Trustee (Filed with 1998 Form 10-K. file no. 1-3559) 4-I Guarantee Agreement, dated as of October 1, 1998, by and between Atlantic City Electric Company as Guarantor, and The Bank of New York as Guarantee Trustee (Filed with 1998 Form 10-K, file no. 1-3559) 10-A Termination Agreement dated August 14, 1997 between Atlantic Energy, Inc. and Michael J. Chesser. (Filed with 1997 Form 10-K, file No. 1-3559) 10-B Purchase And Sale Agreement By And Between Atlantic City Electric Company and NRG Energy Inc. (wholly owned electric generating plantsXfiled herewith). 10-C Purchase And Sale Agreement By And Between Atlantic City Electric Company and NRG Energy Inc. (jointly owned electric generating plants)(filed herewith). 12-A Ratio of earnings to fixed charges, filed herewith 12-B Ratio of earnings to fixed charges and preferred dividends, filed herewith 99 Pro Forma Financial Statements-Generation Asset Sale and Transfer, filed herewith.
(b) Reports on Form 8-K The following Reports on Form 8-K were filed in the fourth quarter of 2000:
On October 20, 2000, ACE filed a Current Report on Form 8-K dated October 3, 2000, reporting on Item 5, Other Events.
IV-3 SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934 the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on April 2, 2001.
ATLANTIC CITY ELECTRIC COMPANY (Registrant)
By: /s/ JOHN C. VAN RODEN (John C. van Roden, Chief Financial Officer)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities indicated, on April 2, 2001.
Signature Title
/s/ HOWARD E. COSGROVE Chairman of the Board (Howard E. Cosgrove)
/S/ JOSEPH M. RIGBY President (Joseph Mv.Rigby)
/S/ JOHN C. VAN RODEN Director and Chief Financial (John C. van Roden) Officer
/s/ JAMES P. LAVIN Controller and Chief (James P. Lavin) Accounting Officer
/s/ THOMAS S. SHAW Director (Thomas S. Shaw)
/s/ BARBARA S. GRAHAM Director (Barbara S. Graham)
IV-4