Item 1. Business
General
Enterprise
Public Service Enterprise Group Incorporated (Enterprise), incorporated under the laws of the State of New Jersey with its principal executive offices located at 80 Park Plaza, Newark, New Jersey 07101, is a public utility holding company that neither owns nor operates any physical properties. Enterprise has two direct, wholly-owned subsidiaries, Public Service Electric and Gas Company (PSE&G) and Enterprise Diversified Holdings Incorporated (EDHI). Enterprise's principal subsidiary, PSE&G, is an operating public utility providing electric and gas service in certain areas of the State of New Jersey. EDHI is the parent of Enterprise's non-utility businesses: Community Energy Alternatives Incorporated (CEA), Public Service Resources Corporation (PSRC), Energis Resources Incorporated (Energis), Enterprise Group Development Corporation (EGDC), PSEG Capital Corporation (Capital) and Enterprise Capital Funding Corporation (Funding). For additional information on EDHI and its subsidiaries, see EDHI. EDHI sold Energy Development Corporation (EDC) in 1996, see Note 16. Discontinued Operations of Notes to Consolidated Financial Statements (Notes).
PSE&G
PSE&G, a New Jersey corporation with its principal executive offices at 80 Park Plaza, Newark, New Jersey 07101, is an operating public utility company engaged principally in the generation, transmission, distribution and sale of electric energy service and in the transmission, distribution and sale of gas service in New Jersey. 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 parts are served with electricity only and other parts with gas only. This heavily populated, commercialized and industrialized territory encompasses most of New Jersey's largest municipalities, including its six largest cities--Newark, Jersey City, Paterson, Elizabeth, Trenton and Camden--in addition to 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 believes that it has all the franchises (including consents) necessary for its electric and gas operations in the territory it serves. Such franchise rights are not exclusive.
Under the general laws of New Jersey, PSE&G has the right to use the public highways, streets and alleys in New Jersey for erecting, laying and maintaining poles, conduits and wires necessary for its electric operations. PSE&G must, however, first obtain the consent in writing of the owners of the soil for the purpose of erecting poles. PSE&G's rights are also subject to regulation by municipal authorities with respect to street openings and the use of streets for erecting poles in incorporated cities and towns. Concerning gas distribution, PSE&G has the right to use the roads, streets, highways and public grounds in New Jersey for pipes and conduits.
Industry Issues
The electric and gas industries in the State of New Jersey and across the country are undergoing a major transformation. Enterprise and PSE&G are affected by many issues that are generic to the electric and gas industries such as: deregulation and the unbundling of energy supplies and services and establishment of a competitive energy marketplace (see Competitive Environment); sales retention and growth potential in a mature service territory; the need to reduce costs; the ability to obtain adequate and timely rate relief, cost recovery and other necessary regulatory approvals (see Note 2. Rate Matters of Notes); the ability to economically operate nuclear facilities safely in accordance with regulatory requirements (see Nuclear Operations); increased capital investments attributable to environmental regulations (see Construction and Capital Requirements and Environmental Controls); nuclear decommissioning and the availability of reprocessing and storage facilities for spent nuclear fuel (see Electric Fuel Supply and Disposal); and credit market concerns associated with these issues.
Segment Information
Financial information with respect to business segments of PSE&G and Enterprise is set forth in Note 15. Financial Information by Business Segments of Notes.
Competitive Environment
Overview
The regulatory structure which has historically governed the electric and gas industries in the United States is in transition. Legislative and regulatory initiatives, at both the Federal and State levels, are designed to promote competition and will continue to impose additional pressures on PSE&G's ability to retain customers. In addition, new technology and interest in self generation and cogeneration have provided customers with alternative sources and supplies of energy. Retention of existing customers and potential sales growth will depend upon the ability of PSE&G to reduce costs, meet customer expectations and respond to changing economic conditions and regulation. For further information on regulatory changes, see Competitive Environment of MD&A and Note 2. Rate Matters of Notes.
Enterprise's non-utility businesses are subject to substantial competition as well. Energis competes with other providers of energy services, including utilities and their affiliates. Some of the power generation projects in which CEA invests compete with other independent power providers as well as utility generators both domestically and internationally. CEA's distribution businesses in Argentina and Brazil operate pursuant to franchise arrangements and are generally not subject to competition. For additional information see EDHI and MD&A.
Federal Regulatory Bodies
PSE&G is subject to regulation by the Federal Energy Regulatory Commission (FERC) with respect to certain matters, including interstate sales and exchanges of electric transmission, capacity and energy. Enterprise is not subject to regulation by FERC. Enterprise 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) thereof, which relates to the acquisition of 5% or more of the voting securities of an electric or gas utility company. Construction and operation of nuclear generating facilities are regulated by the Nuclear Regulatory Commission (NRC). For additional information relating to regulation by the NRC, see Nuclear Operations. 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. For information on environmental regulation, see Environmental Controls.
Federal Regulation
Electric
The electric industry is currently undergoing restructuring as a result of Federal legislation and regulatory initiatives. The National Energy Policy Act of 1992 (EPAct) eased restrictions on independent power producers (IPP) in an effort to increase competition in the wholesale electric generation market. As the barriers to entry in the power production business have been lowered, the construction of cogeneration facilities and independent power production facilities has grown, resulting in lower cost alternatives for large commercial and industrial customers.
For further discussion of Federal regulation of the electric industry, including a discussion of the Pennsylvania--New Jersey--Maryland Interconnection (PJM) responses to FERC orders related to FERC Order No. 888 (Order No. 888), see Competitive Environment of Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A). For a discussion of PSE&G's actions related to the potential environmental impact of Order No. 888, see Environmental Controls.
Gas
Over the last decade, the natural gas industry has experienced a dramatic transformation as several FERC initiatives have opened the industry to competitive market forces. On the interstate level, the pipeline suppliers that serve PSE&G have unbundled gas supply and transportation services and now offer transportation services that move gas purchased from numerous natural gas producers and marketers to PSE&G's service territory.
State Regulatory Bodies
As a New Jersey public utility, PSE&G is subject to comprehensive regulation by the New Jersey Board of Public Utilities (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 generation and 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. Enterprise is not subject to direct regulation by the BPU, except potentially with respect to certain transfers of control and reporting requirements. The BPU may also impose certain requirements with respect to affiliate transactions between and among PSE&G, Enterprise and Enterprise's non-utility subsidiaries (see EDHI).
State Regulation
Electric
EPAct prevents FERC from ordering retail wheeling and preserves any existing state authority to mandate retail wheeling. In April 1997 in its Energy Master Plan proceedings, the BPU issued its final report on wholesale and retail electric competition in New Jersey. For further discussion of the Energy Master Plan proceedings regarding deregulation and unbundling of the electric utility industry in New Jersey, including PSE&G's proposal in response, see MD&A and Note 2. Rate Matters of Notes.
In 1995, the BPU initiated a generic proceeding that would eventually lead to New Jersey electric utilities having the ability to offer "off-tariff" negotiated rates to customers. Although these Off-Tariff Rate Agreements (OTRAs) are offered at PSE&G's sole discretion, they are subject to BPU approval of minimum price, confidentiality of information, contract duration, regulatory filing requirements and other reporting requirements. These negotiated OTRAs form part of PSE&G's overall strategy to retain customers in its service territory and maintain long-term electric sales. To date, ten OTRAs have been filed with and approved by the BPU and PSE&G is currently in negotiations with several other customers. PSE&G does not expect the impact of OTRAs to have a material effect on its financial position, results of operations and net cash flows.
The New Jersey Public Utility Accident Fault Determination Act (Fault Act) requires the BPU to make a determination of fault with regard to any accident at any electric generating or transmission facility prior to granting a request by any utility for a rate increase to cover accident-related costs in excess of $10 million. Fault, as defined in the Fault Act, means any negligent action or omission of any party which either contributed substantially to causing the accident or failed to mitigate its severity. If such an accident were to occur at a PSE&G facility, the Fault Act could have a material adverse effect on Enterprise's and PSE&G's financial position if it were ultimately determined that the accident was due to the fault of PSE&G and if the BPU were to deny recovery of all or a portion of the costs related thereto.
The Fault Act allows the affected utility to file for non-accident related rate increases during such fault determination hearings and to recover contributions to Federally mandated or voluntary cost-sharing plans and allows the BPU to authorize the recovery of certain fault-related repair, clean-up, power replacement and damage costs if substantiated by the evidence presented and if authorized in writing by the BPU. The applicability of the Fault Act may be significantly affected as a result of the Energy Master Plan proceedings (see Note 2. Rate Matters of Notes).
Gas
PSE&G's unbundled gas transportation tariffs, which have been in place since 1994, allow any nonresidential customer, regardless of size, to purchase its own gas, transport it to PSE&G and require PSE&G to deliver such gas to the customer's facility. For further discussion of gas unbundling, see Note 2. Rate Matters of Notes.
On October 10, 1997, PSE&G filed a Petition for Expedited Approvals with the BPU seeking approval, pursuant to a FERC authorized capacity release mechanism, to transfer to its subsidiary Public Service Energy Trading Company (PSETC), all of PSE&G's rights and obligations under its transportation and storage contracts with interstate pipelines. PSETC, in turn, would supply all of the natural gas requirements of PSE&G pursuant to a Requirement Contract between the two parties. The proposed transaction would transfer to PSETC all future contractual liabilities under these agreements and protect the regulatory status of certain off-system sales transactions currently being performed. On December 3, 1997, one of the interstate pipeline companies from which PSE&G obtains service filed a declaratory judgment action with FERC challenging PSE&G's interpretation of the capacity release rules. Under the interpretation proposed by the interstate pipeline company, PSE&G would be required to guarantee the performance of PSETC under the transferred agreements. PSE&G disagreed with these claims and filed a protest challenging the December 3, 1997 filing. On February 11, 1998, FERC ruled in favor of the interstate pipeline company finding that it was not unreasonable for the pipeline company to refuse to discharge PSE&G under the circumstances addressed in the order. PSE&G is currently evaluating its alternatives in response to that ruling, which could include seeking a rehearing of that order. PSE&G cannot predict the ultimate resolution of this matter at this time.
General
The issue of Enterprise sharing the benefits of consolidated tax savings with PSE&G or its ratepayers was addressed by the BPU in 1995 in a letter which informed PSE&G that the issue of consolidated tax savings can be discussed in the context of its next base rate case or plan for an alternative form of regulation. Enterprise believes that PSE&G's taxes 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 Enterprise nor PSE&G is able to predict what action, if any, the BPU may take concerning consolidation of tax benefits in future proceedings.
Under New Jersey law, the BPU is required to audit all or a portion of the operating procedures and other internal workings of every gas or electric utility subject to its jurisdiction, including PSE&G, at least once every six years. The BPU may, upon completion of the audit and after notice and hearing, order the utility to adopt such new practices and procedures that it shall find reasonable and necessary to promote efficient and adequate service to meet public convenience and necessity.
In an Order dated June 25, 1997, the BPU commenced management audits of all New Jersey electric utilities, with the assistance of one or more consulting firms, under the direction of its own audit staff. The audit process included, but was not limited to, focused reviews of electric utility filings in response to the Energy Master Plan. The management audit process for PSE&G was concluded in December 1997 with a report filed by the management consulting firms which performed the audit on behalf of the BPU. The report was approved by the BPU on January 29, 1998. A second report on restructuring has yet to be filed. For additional information regarding the management audit report, see Note 2. Rate Matters of Notes. For a discussion of the BPU's previous focused audit of the non-utility businesses of Enterprise and its potential effects, see Liquidity and Capital Resources of MD&A.
The BPU can adopt, reject or modify the audit report's results in its decision on PSE&G's proposal in the Energy Master Plan proceedings. PSE&G cannot predict to what extent the BPU will rely on the results of the audit report nor what the ultimate outcome of the Energy Master Plan proceedings will be; however, the decision of the BPU will fundamentally change the rules for the sale of electricity in New Jersey and therefore could have a material adverse effect on Enterprise's and PSE&G's financial condition, results of operations and net cash flows.
Construction and Capital Requirements
For information concerning investments, construction and capital requirements see Construction and Capital Requirements of MD&A, Note 7. Schedule of Consolidated Debt, Note 4. Long-Term Investments and Note 10. Commitments and Contingent Liabilities of Notes.
Financing Activities
For a discussion of issuance, repurchase, book value and market value of Enterprise's Common Stock and external financing activities of Enterprise, PSE&G and EDHI for the year 1997, see Item 5. Market for Registrant's Common Equity and Related Stockholder Matters and Liquidity and Capital Resources of MD&A.
For a discussion of Capital and Funding, see EDHI--Capital and EDHI--Funding. For further discussion of long-term debt and short-term debt, see Note 7. Schedule of Consolidated Debt of Notes.
Federal Income Taxes
For information regarding Federal income taxes, see Note 1. Organization and Summary of Significant Accounting Policies, Note 2. Rate Matters and Note 12. Federal Income Taxes of Notes.
Credit Ratings
The current ratings of securities of Enterprise and its subsidiaries are shown below and reflect the respective views of the rating agencies, from whom an explanation of the significance of their ratings may be obtained. There is no assurance that these ratings will continue for any given period of time or that they will not be revised or withdrawn entirely by the rating agencies, if, in their respective judgments, circumstances so warrant. Any downward revision or withdrawal may adversely effect the market price of Enterprise's, EDHI's and PSE&G's securities and serve to increase their cost of capital.
Standard Duff & Moody's & Poor's Phelps ------- -------- ------ Enterprise Preferred Securities............................ Baa2 BBB BBB
PSE&G Mortgage Bonds.................................. A3 A- A Debenture Bonds................................. Baa1 BBB+ A- Preferred Securities............................ Baa1 BBB+ A- Commercial Paper (including PSE&G Fuel Corp.)... P2 A2 Duff 1
EDHI Senior Debt (Capital)........................... Baa2 BBB BBB+
As a component of PSE&G's ratings, each rating agency issues its opinion of the credit trend or outlook. Each of the three rating agencies currently evaluate that credit trend or outlook as negative.
PSE&G
Rate Matters
For information concerning the Energy Master Plan, PSE&G's rate matters and environmental remediation and fuel adjustment clauses, see Competitive Environment--State Regulation (Electric), Note 1. Organization and Summary of Significant Accounting Policies and Note 2. Rate Matters of Notes. For information concerning PSE&G's under (over) recovered electric energy and gas fuel costs, see Note 3. Regulatory Assets and Liabilities of Notes.
Customers
As of December 31, 1997, PSE&G provided service to approximately 1.9 million electric customers and 1.5 million gas customers. PSE&G is not dependent on a single customer or a few customers for its electric or gas sales. For the year ended December 31, 1997, PSE&G's operating revenues aggregated $6.1 billion, of which 68% was from its electric operations and 32% from its gas operations. PSE&G's business is seasonal in that sales of electricity are higher during the summer months because of air conditioning requirements and sales of gas are greater in the winter months due to the use of gas for space-heating purposes.
1997 Revenues were derived as follows:
Revenues --------------------------- Electric Gas -------- ---------- (Millions of Dollars) Residential................................. $1,260 $953 Commercial.................................. 1,845 362 Industrial.................................. 649 295 Transportation Service--Gas................. -- 168 Other....................................... 434 159 --------- ---------- Total................................... $4,188 $1,937 ========= ==========
For information on the impact of competition on PSE&G's customer and revenue base, see Competitive Environment of MD&A.
Resource Plan
PSE&G periodically reevaluates its forecasted customer load and peak growth and the sources of electric generating capacity and Demand Side Management (DSM) to meet such projected growth (see DSM below and Note 2. Rate Matters of Notes). The Resource Plan takes into account assumptions concerning future customer demand, future cost trends, especially fuel and purchased power expenses, the impacts of conservation and load management activities, the long-term condition of and projected additions to PSE&G's plants and capacity available from other electric utilities and non-utility suppliers. The forecast for electric system peak demand over the period 1998-2002 has been developed based on an assumed compound annual rate of growth of 0.9%.
Power Purchases
A component of PSE&G's Resource Plan consists of expected capacity additions from PJM and non-utility generators (NUGs). NUG projects are expected to comprise approximately 6.5% of capacity resources by 2005. The availability of NUG generation reduces the need for PSE&G to build or acquire additional generation. For further information on PJM, NUGs and Stranded Costs, see Competitive Environment of MD&A and Note 2. Rate Matters of Notes.
Demand Side Management (DSM)
The BPU adopted rules in 1991 to encourage utilities to offer DSM related load management and conservation services. These rules were re-adopted in 1996 and are designed to place DSM on equal regulatory footing with supply side or energy production investments. In the Energy Master Plan proceedings, the BPU proposed that during the transition to a restructured industry, DSM programs continue to be implemented by utilities and funded through rates. Initially, the existing DSM rules would apply. For the longer term, the rules would be modified to reflect increasing reliance on market forces to drive DSM (see Competitive Environment--State Regulation and Note 2. Rate Matters of Notes).
PSE&G's current DSM Resource Plan was approved by the BPU in 1995 and is designed to encourage investment in energy-saving DSM activities. These activities involve energy saving techniques and technologies, such as high-efficiency lighting and motors, which help reduce customer demand for energy. The DSM Resource Plan consists of two major program areas for both electric and gas: (1) a core program which includes many specialized programs such as energy audits, seal-ups and rebates for high efficiency heating and cooling equipment; and (2) a standard offer program which is performance based and provides payment for measurable energy savings resulting from the installation of qualified measures that improve the energy efficiency of end-uses.
PSE&G's Resource Plan calls for PSE&G to utilize DSM to meet most of its incremental resource needs for the next decade. PSE&G projects 233 Megawatts (MW) of passive DSM and 455 MW of active DSM by 2002.
Electric Generating Capacity
The following table sets forth certain information as to PSE&G's installed generating capacity as of December 31, 1997:
Installed Source Capacity (A)(MW) Percentage ------ ---------------- ---------- Conventional Steam Electric: Oil-fired (B).......................... 1,531 15% Coal-fired New Jersey (C).............. 1,248 12% Coal-fired Pennsylvania (mine mouth)(D) 770 7% Combustion Turbine (E)..................... 2,724 27% Combined Cycle............................. 922 9% Diesel (D)................................. 5 0% Nuclear (D): New Jersey............................. 1,921 19% Pennsylvania........................... 930 9% Pumped Storage (D) (E)..................... 200 2% ------ ---- Total............................. 10,251 100% ====== ====
(A) Excludes 687 MW of non-utility generation, 352 MW of capacity sales to Delmarva Power & Light Company (DP&L), Allegheny Power System and GPU, Inc. and 50 MW of capacity purchases from GPU, Inc.
(B) Units with aggregate capacity of 836 MW can also burn gas.
(C) Can also burn gas.
(D) PSE&G share of jointly owned facilities.
(E) Primarily used for peaking purposes.
For additional information, see Item 2.
Item 2. Properties
PSE&G
The statements under this Item as to ownership of properties are made without regard to leases, tax and assessment liens, judgments, easements, rights of way, contracts, reservations, exceptions, conditions, immaterial liens and encumbrances and other outstanding rights affecting such properties, none of which is considered to be significant in the operations of PSE&G, except that PSE&G's First and Refunding Mortgage (Mortgage), securing the bonds issued thereunder, constitutes a direct first mortgage lien on substantially all of such property.
PSE&G 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.
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. Generally, where payments are minor in amount, no examinations of underlying titles as to the rights of way for transmission or distribution lines or mains have been made.
Electric Properties
As of December 31, 1997, PSE&G's share of installed generating capacity was 10,251 MW, as shown in the following table:
Installed Principal Name and Location Capacity (MW) Fuel Used ----------------- ------------ --------- Steam: Hudson, Jersey City, NJ......................... 983 Coal Mercer, Hamilton, NJ............................ 648 Coal Sewaren, Woodbridge Twp., NJ.................... 453 Gas Linden, Linden, NJ.............................. 415 Oil Keystone, Shelocta, PA--22.84%(B)............... 388 Coal Conemaugh, New Florence, PA--22.50%(B).......... 382 Coal Kearny, Kearny, NJ.............................. 280 Oil ------ Total Steam................................ 3,549 ------ Nuclear: (Capacity factor calculated in accordance with industry maximum dependable capability standards) Hope Creek, Lower Alloways Creek, NJ 95%(B)..... 979 Nuclear Salem 1, Lower Alloways Creek, NJ 42.59%(B)..... 471 Nuclear Salem 2, Lower Alloways Creek, NJ 42.59%(B)..... 471 Nuclear Peach Bottom 2, Peach Bottom, PA 42.49%(B)...... 465 Nuclear Peach Bottom 3, Peach Bottom, PA 42.49%(B)...... 465 Nuclear ------ Total Nuclear.............................. 2,851 ------ Combined Cycle: Bergen, Ridgefield, NJ.......................... 682 Gas Burlington, Burlington, NJ...................... 240 Gas ------ Total Combined Cycle............................ 922 ------ Combustion Turbine: Essex, Newark, NJ............................... 617 Gas Edison, Edison Township, NJ..................... 504 Gas Kearny, Kearny, NJ.............................. 504 Gas Burlington, Burlington, NJ...................... 389 Oil Linden, Linden, NJ.............................. 223 Gas Hudson, Jersey City, NJ......................... 129 Oil Mercer, Hamilton, NJ............................ 129 Oil Sewaren, Woodbridge Township, NJ................ 129 Oil Bayonne, Bayonne, NJ............................ 42 Oil Bergen, Ridgefield, NJ.......................... 21 Gas National Park, National Park, NJ................ 21 Oil Salem, Lower Alloways Creek, NJ 42.59%(B)....... 16 Oil ------ Total Combustion Turbine........................ 2,724 ------ Internal Combustion: Conemaugh, New Florence, PA--22.50%(B).......... 3 Oil Keystone, Shelocta, PA--22.84%(B)............... 2 Oil ------ Total Internal Combustion.................. 5 ------ Pumped Storage: Yards Creek, Blairstown, NJ--50%(B)(C).......... 200 ------ Total PSE&G................................ 10,251 (A) ======
(A) Excludes 687 MW of non-utility generation and 302 MW of temporary capacity sales.
(B) PSE&G's share of jointly owned facility.
(C) Excludes energy for pumping and synchronous condensers.
For information regarding construction see MD&A--Construction and Capital Expenditures.
In addition to the generating facilities in New Jersey and Pennsylvania as indicated in the table above, as of December 31, 1997, PSE&G owned 41 switching and/or generating stations with an aggregate installed capacity of 30,255,000 kilovolt-amperes, and 222 substations with an aggregate installed capacity of 7,295,000 kilovolt-amperes. In addition, seven substations having an aggregate installed capacity of 115,250 kilovolt-amperes were operated on leased property. All of these facilities are located in New Jersey.
As of December 31, 1997, PSE&G's transmission and distribution system included 153,238 circuit miles, of which 37,694 miles were underground, and 801,811 poles, of which 537,208 poles were jointly owned. Approximately 99% of this property is located in New Jersey.
In addition, as of December 31, 1997, PSE&G owned four electric distribution headquarters and five subheadquarters in four operating divisions all located in New Jersey.
Gas Properties
As of December 31, 1997, 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 2,973,000 therms (approximately 288,600,000 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 280,000 Central LPG....................... Edison Twp., NJ 960,000 Harrison LPG...................... Harrison, NJ 960,000 --------- Total........................... 2,973,000 =========
As of December 31, 1997, PSE&G owned and operated approximately 16,000 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, portions of the metering and regulating facilities were owned by the pipeline companies.
Office Buildings and Facilities
PSE&G
PSE&G leases substantially all of a 26-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.
EDHI
EDHI owns no real property. EDHI leases its corporate headquarters at 80 Park Plaza, Newark, New Jersey. For a brief general description of the properties of the subsidiaries of EDHI, see Item 1. Business--EDHI.
Item 3.
Item 3. Legal Proceedings
In October 1995, Enterprise received a letter from a representative of a purported shareholder demanding that it commence legal action against certain of its officers and directors with regard to nuclear operations of Salem and Hope Creek. The Board of Directors promptly commenced an investigation and advised the purported shareholder thereof. While the investigation was pending, the purported shareholder nevertheless commenced, by complaint filed in December 1995, a shareholder derivative action on behalf of Enterprise shareholders against the then incumbent directors, except Dr. Remick. Similar derivative complaints were filed by two profit sharing plans and one individual in February and March 1996 against Messrs. Ferland, Codey, Eliason and others. On March 19, 1996, the Board's investigation was concluded, and the Board determined that this litigation should not have been instituted and should be terminated. On July 3, 1996, another individual purported shareholder filed a similar complaint naming the same defendants as the first derivative lawsuit. On August 21, 1996, all defendants filed motions to dismiss all four derivative actions, which motions were denied and attempts to appeal were unsuccessful. Pursuant to Court Order, the defendants have filed motions for summary judgment to dismiss two of the cases, which motions are pending. In the other two cases, one of the plaintiffs has sold her shares and is seeking to withdraw from the litigation. Another of the plaintiffs (a profit sharing plan) has been dissolved and one of the individual participants in the plan is seeking to maintain the litigation is his individual name. Discovery in these latter two cases is continuing. The four complaints generally seek recovery of damages for alleged losses purportedly arising out of PSE&G's operation of Salem and Hope Creek, together with certain other relief, including removal of certain executive officers of PSE&G and Enterprise and certain changes in the composition of Enterprise's Board of Directors. Enterprise cannot predict the outcome of these matters.
PSE&G and the three other co-owners of Salem filed suit in February 1996 in the U.S. District Court for the District of New Jersey against Westinghouse Electric Corporation (Westinghouse) seeking damages to recover the cost of replacing the steam generators at Salem 1 and 2. The suit alleges fraud and breach of contract by Westinghouse in the sale, installation and maintenance of the generators. In April 1996, Westinghouse filed an answer and $2.5 million counterclaim for unpaid work related to services at Salem. Westinghouse has filed a motion for summary judgment on the grounds that the claim of the plaintiffs is barred by the statute of limitations and oral arguments on this motion were held in February 1998. A decision is anticipated within approximately 30 days. PSE&G cannot predict the outcome of this proceeding.
PECO Energy and DP&L as co-owners of Salem filed a lawsuit in 1996 against Enterprise and PSE&G in the U.S. District Court for the Eastern District of Pennsylvania alleging mismanagement by PSE&G in its operation of Salem and seeking unspecified compensatory and punitive damages. On May 12, 1997, the parties settled the lawsuit. This settlement, which required a payment in December 1997 to the plaintiffs totaling $82 million, resulted in an after-tax charge to earnings, recorded in the first quarter of 1997, of $53 million or $.23 per share of Enterprise Common Stock. PSE&G is also obligated to pay $1.4 million for each reactor month that the outage continues beyond an aggregate outage of 64 reactor months, up to a maximum payment under this provision of $17 million. As of January 31, 1998, an aggregate of 59 reactor months had accumulated due to Salem outages. PSE&G does not expect to make any payments under this provision. Salem 2 returned to service on August 30, 1997. Salem 1 is expected to return to service around the end of the first quarter of 1998.
PECO Energy, DP&L and PSE&G have also agreed to an operating performance standard through December 31, 2011 for Salem and through December 31, 2007 for Peach Bottom. Under this standard, the operator of each respective station would be required to make payments to the non-operating owners if the three-year capacity factor, determined annually, of such station falls below 40 percent, subject to a maximum of $25 million per year. The initial three-year period begins on January 1, 1998 for Peach Bottom and on the date the later of the two Salem units (Salem 1) returns to service for Salem. The parties have further agreed to forego litigation in the future, except for limited cases in which the operator would be responsible for damages of no more than $5 million per year.
ACE also filed a similar suit alleging mismanagement in the operation of Salem by PSE&G in 1996 against Enterprise and PSE&G in the New Jersey Superior Court. PSE&G and ACE entered into an agreement (Agreement) to dismiss this lawsuit. Under the Agreement, ACE pays a portion of its share of the 1997 operation and maintenance expenses based on the amount of generation of the Salem units. PSE&G incurred approximately $13 million of ACE's share of 1997 operation and maintenance expenses since Salem 2 did not operate for the first eight months of 1997 and Salem 1 did not return to service during 1997.
The Agreement applied only to calendar year 1997 and does not apply to any damages which may be alleged by ACE to continue beyond or be incurred after December 31, 1997; and did not apply to ACE's rights under the Salem Owners Agreement to review and approve capital projects; which, in each instance, continue to be governed by the terms and conditions of that agreement and the rights and obligations of ACE and PSE&G at law or in equity.
In addition, see the following at the pages indicated:
(1) Pages 2 and 43 through 44. Proceedings before FERC relating to competition and electric wholesale power markets. (Inquiry Concerning the Pricing Policy for Transmission Services Provided by Utilities Under the Federal Power Act, Docket No. RM93-19.)
(2) Pages 2 and 44. Proceeding before FERC relating to the development by PSE&G and other regional transmission owners in PJM of a new transmission service tariff and an Independent System Operator, FERC Docket Nos. OA97-261-000, et al.
(3) Page 3. Generic proceedings before the BPU relating to standards for "off tariff" negotiated rate agreement programs, Docket No. EX95070320.
(4) Page 3. Proceedings before the BPU relating to PSE&G's first Off Tariff Rate Agreement (OTRA), Docket No. OTRA-96-1.
(5) Pages 3, 43 and 64. 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, EO97070462 and EO97070463.
(6) Page 3. Proceedings before the BPU relating to PSE&G's request to transfer its rights and obligations under its transportation and storage contracts with interstate pipelines to PSETC, Docket No. GM97100758.
(7) Page 3. Proceedings before FERC relating to a declaratory judgment action challenging PSE&G's interpretation of the capacity release rules, Texas Eastern Transmission Corporation, FERC Docket No. RP98-83-000.
(8) Pages 12 and 84. Proceedings before the United States Court of Appeals, District of Columbia Circuit, in the matter of the DOE's unconditional obligation to begin spent fuel acceptance by January 31, 1998, Northern States Power v. Department of Energy, Docket No. 97-1064.
(9) Page 15. Notice of Violation issued by EPA against Eagle Point Cogeneration Partnership regarding alleged violations of air permit.
(10) Page 15. Administrative proceedings before the NJDEP under Section 316 of the FWPCA for certain electric generating stations.
(11) Pages 18 through 21 and 83 through 84. Various administrative actions, claims, litigation and requests for information by Federal and/or state agencies, and/or private parties, under CERCLA, RCRA and state environmental laws to compel PRPs, which may include PSE&G, to provide information with respect to transportation and disposal of hazardous substances and wastes and/or to undertake or contribute to the costs of investigative and/or cleanup actions at various locations because of actual or threatened releases of one or more potentially hazardous substances and/or wastes.
(12) Page 26. Derivative actions related to nuclear operations and Salem Station shutdown, Public Service Enterprise Group Inc. by G. E. Stricklin, derivatively v. E. James Ferland, et. al., Docket No. L1068395, Superior Court of New Jersey, Law Division, Camden County. Dr. Steven Fink and Dr. David Friedman, P.C. Profit Sharing Plan, derivatively, et. al. v. Lawrence R. Codey, et. al., Superior Court of New Jersey, Chancery Division, Essex County, Docket No. C-65-96. A. Harold Datz Pension and Profit Sharing Plan derivatively, et. al., v. Lawrence R. Codey, et. al., Superior Court of New Jersey, Chancery Division, Essex County, Docket No. C-68-96. Tillie Greenberg, derivatively v. E. James Ferland, et. al., Superior Court of New Jersey, Chancery Division, Essex County, Docket No. C-188-96.
(13) Page 26. Suit filed by co-owners of Salem against Westinghouse. Public Service Electric and Gas Company, et. al., v. Westinghouse Electric Corporation, United States District Court for the District of New Jersey, Civil Action No. CB-96-925.
(14) Pages 26 and 81. Lawsuits by the co-owners of Salem against Public Service Electric and Gas Company. PECO Energy Company, Delmarva Power & Light Company v. Public Service Electric and Gas Company, United States District Court for the Eastern District of Pennsylvania Civil Action No. 96-CU7705. Atlantic City Electric Company v. Public Service Electric and Gas Company, New Jersey Superior Court, Law Division, Atlantic County, Docket No. L-773-96.
(15) Page 44. Complaint before FERC regarding Old Dominion Electric Cooperative v. PSE&G challenging as unjust and unreasonable the rates in a negotiated contract under which ODEC purchases generation capacity and associated energy and generation reserves from PSE&G, FERC Docket No. EL98-6-000.
(16) Pages 45 and 70. Implementation of P.L.1997,C.162, an Act Revising the Taxation of Electric and Gas Utilities, Docket Nos. ER97090661 and GR97090672.
(17) Page 67. Proceedings before the BPU relating to recovery of replacement power costs in connection with the April 1994 Salem 1 shutdown, Docket No. ER94070293.
(18) Page 67. Generic proceeding before the BPU relating to recovery of capacity costs associated with power purchases from cogenerators, Docket No. EX93060255.
(19) Page 68. Proceedings before the BPU relating to PSE&G's Levelized Gas Adjustment Clause (LGAC) filed November 14, 1997, Docket No. GR97110839.
(20) Page 68. Proceeding before the BPU related to the Electric Levelized Energy Adjustment Clause (LEAC) rate increase to recover DSM costs, Docket No. ER97020101.
(21) Page 69. Proceedings before the BPU relating to PSE&G's RAC filed August 1, 1997, Docket No. GR97080573.
(22) Page 69. Generic proceeding before the BPU relating to the matter of an inquiry into methods of implementation of SFAS-106, Docket No. AX96070530.
(23) Page 70. Proceedings before the BPU relating to PSE&G's proposed CTC filed September 19, 1996, Docket No. ET96090669.
Item 4.
Item 4. Submission of Matters to a Vote of Security Holders
Enterprise and PSE&G, inapplicable.
PART II
Item 5.
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters
Enterprise's Common Stock is listed on the New York Stock Exchange, Inc. and the Philadelphia Stock Exchange, Inc. All of PSE&G's common stock is owned by Enterprise, its parent company. As of December 31, 1997, there were 154,478 holders of record of Enterprise Common Stock.
The following table indicates the high and low sale prices for Enterprise's Common Stock, as reported in The Wall Street Journal as Composite Transactions and dividends paid for the periods indicated:
Dividend Common Stock High Low Per Share ------------ ---- --- --------- 1997: First Quarter......................... $29 1/4 $26 1/8 $.54 Second Quarter........................ 26 1/2 22 7/8 .54 Third Quarter......................... 26 3/16 24 1/16 .54 Fourth Quarter........................ 31 13/16 24 3/4 .54 1996: First Quarter......................... $32 1/8 $25 1/4 $.54 Second Quarter........................ 27 7/8 25 1/8 .54 Third Quarter......................... 27 7/8 25 5/8 .54 Fourth Quarter........................ 29 26 3/8 .54
For additional information concerning dividend history, policy and potential preferred voting rights and restrictions on payment, see Liquidity and Capital Resources and External Financings of MD&A and Note 6.Schedule of Consolidated Capital Stock and Other Securities of Notes.
Item 6.
Item 6. Selected Financial Data
Enterprise
The information presented below should be read in conjunction with Enterprise's Consolidated Financial Statements and Notes thereto.
PSE&G
The information presented below should be read in conjunction with PSE&G's Consolidated Financial Statements and Notes thereto.
Item 7.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Enterprise
This discussion refers to the Consolidated Financial Statements and related Notes of Public Service Enterprise Group Incorporated (Enterprise) and should be read in conjunction with such statements and notes.
Corporate Structure
Enterprise has two direct wholly owned subsidiaries, Public Service Electric and Gas Company (PSE&G) and Enterprise Diversified Holdings Incorporated (EDHI). Enterprise's principal subsidiary, PSE&G, is an operating public utility providing electric and gas service in certain areas within the State of New Jersey.
EDHI is the parent of Enterprise's non-utility businesses: Community Energy Alternatives Incorporated (CEA), an investor in and developer and operator of projects in the generation, transmission and distribution of energy, including cogeneration and independent power production (IPP) facilities, electric distribution companies, exempt wholesale generators (EWGs) and foreign utility companies (FUCOs); Public Service Resources Corporation (PSRC), which has made primarily passive investments; Energis Resources Incorporated (Energis) which provides a variety of energy related services to industrial and commercial customers both within and outside of PSE&G's traditional service territory (see Competitive Environment) and Enterprise Group Development Corporation (EGDC), a nonresidential real estate development and investment business. EDHI also has two finance subsidiaries: PSEG Capital Corporation (Capital), which provides privately-placed debt financing to EDHI's operating subsidiaries, except Energis, on the basis of a minimum net worth maintenance agreement with Enterprise and Enterprise Capital Funding Corporation (Funding), which provides privately-placed debt financing to PSRC, CEA and their subsidiaries, which debt is guaranteed by EDHI, but without direct support from Enterprise. EGDC has been conducting a controlled exit from its real estate business since 1993. In July 1996, EDHI sold Energy Development Corporation (EDC), an oil and gas subsidiary.
As of December 31, 1997 and 1996, PSE&G comprised 83% and 88%, respectively, of Enterprise's assets. For each of the years 1997, 1996 and 1995, PSE&G revenues were approximately 96%, 96%, and 97%, respectively, of Enterprise's revenues and PSE&G's earnings available to Enterprise for such years were 92%, 87% and 88%, respectively, of Enterprise's net income.
Overview of 1997
A major event which will impact Enterprise and PSE&G in the future occurred in April 1997 when the New Jersey Board of Public Utilities (BPU) unveiled its final report regarding Phase II of the New Jersey Energy Master Plan (Energy Master Plan) (final Phase II report) addressing wholesale and retail electric competition in New Jersey. The final Phase II report required PSE&G and other New Jersey electric utilities to develop rate and service plans to give customers a choice of suppliers. PSE&G filed its proposal in July 1997 and hearings before the BPU are in progress (see Note 2. Rate Matters of Notes to Consolidated Financial Statements (Notes)). PSE&G cannot predict the outcome of the Energy Master Plan proceedings. The outcome of these proceedings could have a material adverse impact on Enterprise's and PSE&G's financial condition, results of operations and net cash flows.
Another significant event in 1997 was the progress made at the Salem Nuclear Generating Station (Salem). As previously reported, Salem Units 1 and 2 (Salem 1 and 2) were taken out of service in mid-1995. During these outages, PSE&G made significant changes and improvements related to the people, processes and equipment at Salem to improve the long-term reliability of the units. Salem 2 returned to service in August 1997. Salem 1 is scheduled to restart, subject to Nuclear Regulatory Commission (NRC) approval, during the first quarter of 1998 (see Nuclear Operations).
To further Enterprise's strategy to develop its non-utility business through international expansion, CEA established strategic partnerships with other companies, expanding as a developer and operator of electric generation projects and an operator of distribution systems. CEA was successful in expanding operations in its various targeted regions in South America, particularly Brazil and Argentina. In 1997, CEA's assets quadrupled to about $1.2 billion, bringing the level of its portfolio at December 31, 1997 to 26 generation projects and two distribution ventures around the world (see Liquidity and Capital Resources).
Results of Operations
Earnings per share of Enterprise common stock (Common Stock) was $2.41 in 1997, representing a decrease of $0.11 per share or 4% from 1996. Earnings per share was $2.52 in 1996, a decrease of $0.19 per share or 7% from 1995.
PSE&G's contribution to earnings per share in 1997 decreased $0.07 compared to 1996 due to higher administrative costs attributable to systems modifications for Year 2000 readiness, legal fees associated with the settlement of the Salem co-owner litigation and a gain recorded in the second quarter of 1996 from the repurchase of a portion of PSE&G's outstanding cumulative preferred stock at discounts to par. These decreases were partially offset by lower operation and maintenance expenses at Salem and the Hudson generating station. Salem's refueling outage expenses and restart activities declined while Hudson's expenses benefited from a decrease in the workforce as well as a reduction of outage work performed in 1997. Earnings per share in 1997 and 1996 were each negatively impacted by charges related to the shutdown of Salem 1 and 2 which began in 1995. The settlement of the lawsuits filed by the co-owners of Salem negatively impacted 1997 earnings by $0.27 per share and refunds required by the BPU's December 31, 1996 Order (December 31st Order) which resolved Salem and other outstanding regulatory issues negatively impacted 1996 earnings by $0.25 per share (see Note 2. Rate Matters of Notes).
EDHI's contribution to earnings per share in 1997 decreased $0.14 compared to 1996 primarily due to the absence of 1996 earnings of $0.10 per share related to the discontinued operations of EDC and higher operating expenses of Energis as it continued to grow.
As a result of Enterprise's stock repurchase program which began in July 1996, earnings per share of Common Stock for 1997 increased $0.10 from 1996. A total of 12.7 million shares were repurchased at a cost of $350 million under this program which concluded in January 1997.
In 1996, PSE&G's contribution to earnings per share decreased $0.22 compared to 1995 due to the refunds required by the December 31st Order (see Note 2. Rate Matters of Notes). Other factors that decreased earnings per share in 1996 were increased operation and maintenance expenses related to the outages at Salem and Hope Creek Nuclear Generating Station (Hope Creek) and increased depreciation due to additional plant in service. The earnings per share decrease was partially offset by higher gas sales in early 1996 due to favorable weather conditions and the gain on the repurchase of certain of PSE&G's outstanding cumulative preferred stock at a discount to par.
EDHI's contribution to earnings per share in 1996 increased $0.01 compared to 1995 principally due to increased investment income from PSRC.
Earnings per share of Common Stock in 1996 increased $0.02 as a result of Enterprise's stock repurchase program, described above.
PSE&G--Revenues
Electric
Revenues increased $244 million or 6% in 1997 and decreased $77 million or 2% in 1996. The increase in 1997 was primarily due to an increase in energy sales to wholesale customers and 1996 refunds required by the December 31st Order, partially offset by lower kilowatt sales from unfavorable weather.
Gas
Revenues increased $56 million or 3% and $195 million or 12% in 1997 and 1996, respectively. The 1996 increase was primarily due to a higher recovery of fuel costs and favorable weather conditions in early 1996.
PSE&G--Expenses
Fuel for Electric Generation and Interchanged Power
Fuel for Electric Generation and Interchanged Power increased $260 million or 28% in 1997 and $27 million or 3% in 1996. The increases in both years were primarily due to increases in energy sales to wholesale customers. To the extent fuel revenue and expense flow through the Electric Levelized Energy Adjustment Clause (LEAC) mechanism, variances in fuel revenues and expenses offset and thus have no direct effect on earnings. For a discussion of fuel related revenue and expense included in the LEAC, see Note 1. Organization and Summary of Significant Accounting Policies of Notes.
Gas Purchased
Gas purchased decreased $17 million or 2% in 1997 and increased $156 million or 16% in 1996. The 1996 increase was due to an increase in energy sales to wholesale customers. Due to the operation of the Levelized Gas Adjustment Clause (LGAC) mechanism, variances in fuel revenues and expenses offset, and have no direct effect on earnings.
Federal Income Taxes
Federal income taxes increased $42 million or 16% in 1997 and decreased $56 million or 17% in 1996. The 1997 taxes were higher due to an increase in pre-tax operating income while 1996 taxes were lower due to a decrease in pre-tax operating income (see Note 12. Federal Income Taxes of PSE&G Notes).
Net Loss (Gain) on Preferred Stock Redemptions
Net Loss (Gain) on Preferred Stock Redemptions decreased $21 million in 1997 from the comparable 1996 period. The decrease was primarily due to an $18 million net gain on the repurchase of certain of PSE&G's outstanding cumulative preferred stock at discounts to par in the second quarter of 1996 (see External Financings--PSE&G).
Year 2000 Expenses--Enterprise and PSE&G
Many of Enterprise's and PSE&G's systems must be modified due to computer program limitations in recognizing dates beyond 1999. If not corrected, the systems could fail or cause erroneous results by, at or after January 1, 2000. Substantial changes to, and some replacements of, Enterprise's and PSE&G's present systems are being made in an effort to mitigate potential Year 2000 issues. Costs are being expensed as incurred in accordance with Emerging Issues Task Force (EITF) Issue No. 96-14, "Accounting for the Costs Associated with Modifying Computer Software for the Year 2000." During 1997, $8 million of costs related to Year 2000 readiness were incurred. Management estimates the total cost of this effort to be about $92 million to be incurred from 1997 through 2001, of which $41 million is expected to be incurred in 1998.
Enterprise and PSE&G have assembled a cross-functional team to inventory, assess and identify and implement solutions for Enterprise's and PSE&G's systems. Plans provide for 80% of critical systems to be Year 2000 ready in 1998, with the remaining critical systems to be ready by July 1999. By the end of 1999, plans call for 80% of non-critical systems to be Year 2000 ready with the remainder of those systems to be Year 2000 ready in 2000.
Additionally, the team has surveyed Enterprise's and PSE&G's top 3000 vendors to assess their plans for Year 2000 readiness. The team has also been working with critical suppliers and the Pennsylvania--New Jersey--Maryland Interconnection (PJM) on their plans for Year 2000 readiness.
An inability of Enterprise, PSE&G, their subsidiaries, members of PJM or Enterprise's or PSE&G's critical suppliers to meet the Year 2000 deadline could have a material adverse impact on Enterprise's and PSE&G's operations, financial condition, results of operations and net cash flows. For a discussion of the NRC proposal regarding Year 2000 readiness, see Note 10. Commitments and Contingent Liabilities.
EDHI--Net Income
Increase or (Decrease) ---------------------------------------------- 1997 vs. 1996 1996 vs. 1995 ---------------------- ---------------------- Per Per Amount Share Amount Share ---------- ----------- ----------- --------- (Millions of Dollars, except Per Share Data) CEA.......................... $4 $.02 $(2) $(.01) PSRC......................... 3 .01 22 .09 EGDC......................... (5) (.02) (1) -- Energis...................... (12) (.05) (6) (.02) ---------- ----------- ----------- --------- Continuing Operations........ (10) (.04) 13 .06 Discontinued Operations--EDC Income from Operations...... (11) (.04) (24) (.11) Gain on Sale................ (13) (.06) 13 .06 ---------- ----------- ----------- --------- Total.................. $(34) $(.14) $2 $.01 ========== =========== =========== =========
Continuing Operations
EDHI's income from continuing operations was $47 million for 1997, a $10 million decrease from 1996. The loss for Energis increased due to higher selling, general and administrative expenditures as Energis continued to grow. PSRC's income increased primarily due to income from new lease investments, partially offset by lower income from partnership investments. CEA's income increased due to improved financial performance of several projects.
EDHI's income from continuing operations was $57 million in 1996, a $13 million increase over 1995. The 1996 increase was due to PSRC's increased income from partnership investments. Energis' income decreased due to increased administrative and general expenditures (startup costs) and lower margins related to retail gas marketing. Energis was formed on December 31, 1996 by consolidating the operations of two former PSRC subsidiaries, U.S. Energy Partners and Enterprise Strategic Energy Solutions.
Discontinued Operations
EDC was sold on July 31, 1996. Income related to EDC operations was $11 million in 1996, a $24 million decrease from 1995. The 1996 decrease was due to the inclusion of only seven months of earnings for 1996 and a $23 million after-tax gain realized in 1995 related to the settlement of a take-or-pay sales contract.
Liquidity and Capital Resources
Enterprise
Enterprise is a public utility holding company and as such, has no operations of its own. The following discussion of Enterprise's liquidity and capital resources is on a consolidated basis, noting the uses and contributions of Enterprise's two direct subsidiaries, PSE&G and EDHI.
Cash generated from PSE&G's operations is expected to provide the major source of funds for PSE&G's business. EDHI's growth will be funded through external financings, cash generated from its operations, and equity capital. Cash and cash equivalents totaled $83 million at the end of 1997 compared with $279 million at the end of 1996.
During 1996, Enterprise repurchased 11.2 million shares of its Common Stock at an aggregate cost of $307 million. The Common Stock repurchase program concluded on January 17, 1997. A total of 12.7 million shares were repurchased under the program at a cost of $350 million.
Dividend payments on Common Stock were $2.16 per share and totaled $501 million for the year ended December 31, 1997. Since 1986, PSE&G has made regular cash payments to Enterprise in the form of dividends on outstanding shares of PSE&G's common stock. PSE&G has paid quarterly dividends on its common stock in each year commencing in 1948, the year of the distribution of PSE&G's common stock by Public Service Corporation of New Jersey, the former parent of PSE&G. From 1992 through 1996, EDHI made regular cash payments to Enterprise in the form of dividends on outstanding shares of EDHI's common stock. Due to the growth in EDHI investment activities, no dividends on EDHI's common stock were paid in 1997 or are anticipated for 1998.
Enterprise has paid quarterly dividends in each year commencing with the corporate restructuring of PSE&G when Enterprise became the owner of all the outstanding common stock of PSE&G. While a key objective of the Board of Directors of Enterprise is to keep the Common Stock dividend secure, amounts and dates of such dividends as may be declared will necessarily be dependent upon Enterprise's future earnings, financial requirements and other factors including the receipt of dividend payments from its subsidiaries.
Enterprise and PSE&G have issued Deferrable Interest Subordinated Debentures in connection with the issuance of tax deferred preferred securities. If and for as long as payments on those Deferrable Interest Subordinated Debentures have been deferred, or Enterprise or PSE&G has defaulted on the indenture related thereto or its guarantee thereof, neither Enterprise nor PSE&G may pay any dividends on their common and preferred stock (see Note 6. Schedule of Consolidated Capital Stock and Other Securities of Notes).
PSE&G paid dividends of $523 million and $524 million to Enterprise during the years ended December 31, 1997 and 1996, respectively. EDHI paid dividends of $369 million during the year ended December 31, 1996 primarily from proceeds of the sale of EDC.
Cash provided by operating activities totaled $1.095 billion in 1997, down from $1.470 billion in 1996. The major contributor in 1997 was net income of $560 million, which included $630 million of non-cash deductions for depreciation and amortization (see Results of Operations).
Cash provided by operating activities totaled $1.470 billion in 1996, down from $1.518 billion in 1995. The major contributor in 1996 was net income of $612 million, which included $607 million of non-cash deductions for depreciation and amortization (see Results of Operations).
Cash used in investing activities totaled $1.614 billion in 1997, up from $9 million in 1996. The primary use of cash in 1997 was a net increase in long-term investments of $914 million, including CEA's investments in distribution and generation companies of $852 million, PSRC's net increase in investments of $97 million and utility plant additions, excluding Allowance for Funds Used During Construction (AFDC), of $542 million at PSE&G (see Capital Requirements--PSE&G).
Cash used in investing activities totaled $9 million in 1996, down from $935 million in 1995. The proceeds from the sale of EDC were almost fully offset by PSE&G's additions to utility plant (see Capital Requirements -- PSE&G). Net proceeds from the EDC sale were $704 million.
Cash provided by financing activities was $323 million in 1997 as compared to $1.244 billion of cash used in financing activities in 1996. Major contributors in 1997 were an increase in short-term debt by PSE&G of $468 million, EDHI of $267 million and Enterprise of $75 million, primarily used to fund certain scheduled long-term debt maturities, CEA's investments and a net increase in long-term debt of $85 million, partially offset by the payment of dividends on Common Stock of $501 million. PSE&G's long-term debt decreased $287 million in 1997 while EDHI's long-term debt increased $372 million.
Cash used in financing activities was $1.244 billion in 1996, up from $586 million in 1995. The primary use of cash in 1996 was the payment of dividends on Common Stock of $523 million, the retirement of Common Stock of $307 million, and a net decrease in long-term debt $434 million.
As of December 31, 1997, Enterprise's capital structure consisted of 48.4% common equity, 45.3% long-term debt and 6.3% preferred securities. The capital structure as of December 31, 1996 consisted of 49.8% common equity, 43.7% long-term debt and 6.5% preferred securities.
As a result of the 1992 focused audit of Enterprise's non-utility businesses (Focused Audit), the BPU approved a plan which, among other things, provides that: (1) Enterprise will not permit EDHI's non-utility investments to exceed 20% of Enterprise's consolidated assets without prior notice to the BPU (such investments at December 31, 1997 were approximately 16% of assets); (2) the PSE&G Board of Directors include non-employee Enterprise directors, with an annual certification by such Board that the business and financing plans of EDHI will not adversely affect PSE&G; (3) Enterprise agree to (a) limit debt supported by the minimum net worth maintenance agreement between Enterprise and Capital to $750 million and (b) make a good-faith effort to eliminate such support over a six to ten year period from April 1993; and (4) EDHI pay PSE&G an affiliation fee of up to $2 million a year to be applied by PSE&G through its LGAC and its LEAC to reduce utility rates. Beginning in 1995, the debt supported by the minimum net worth maintenance agreement was limited to $650 million and the affiliation fee has been proportionately reduced as such supported debt is reduced. Enterprise and EDHI and its subsidiaries continue to reimburse PSE&G for the costs of all services provided to them by employees of PSE&G.
As a result of Enterprise's intent that EDHI and its subsidiaries provide the primary growth vehicles for Enterprise, financing requirements connected with continued growth of EDHI, changes to the utility industry resulting from the final outcome of the Energy Master Plan proceedings and potential accounting impacts resulting from the deregulation of the generation of electricity, modifications will be required to certain of the restrictions agreed to by Enterprise with the BPU in response to the Focused Audit. Enterprise expects that these modifications will be addressed in conjunction with the Energy Master Plan proceedings. The resolution of these matters could impact the future relative size and financing of the non-utility businesses and may affect Enterprise's future financial position, results of operations and net cash flows (see Note 2. Rate Matters of Notes).
EDHI
CEA, PSRC and Energis are expected to be the growth vehicles for EDHI and Enterprise. During the next five years, EDHI's capital requirements are expected to be provided from additional debt financing, operational cash flows and equity capital. A significant portion of CEA's growth is expected to occur in the international arena due to the current and anticipated growth in electric capacity required in certain regions of the world. PSRC will continue its focus on investments related to the energy business. Energis is expected to expand upon the current energy related services being provided to industrial and commercial customers.
EDHI's cash provided by (used in) operating, investing and financing activities was as follows:
For a discussion of the source of EDHI's funds, see External Financings. Over the next several years, EDHI and its subsidiaries will be required to refinance their maturing debt and provide additional debt and equity financing for growth. Any inability to obtain required additional external capital or to extend or replace maturing debt and/or existing agreements at current levels and interest rates may affect future earnings. As of December 31, 1997 and 1996, EDHI's embedded cost of debt of its finance subsidiaries was approximately 8.2% and 8.9%, respectively. During 1997, EDHI's finance subsidiaries provided additional long-term debt financing of $265 million at an average interest rate of 6.8%.
CEA
During 1997, CEA's investment activities included:
Acquisition of approximately 30% of a Brazilian electric distribution company serving customers in the State of Rio Grande Do Sul, located in Southern Brazil. The total purchase price was $1.49 billion of which CEA's share was $498 million. This investment is an exempt FUCO.
Acquisition of a 50% interest in a 200 Megawatt (MW) natural gas-fired power plant located in Colombia, South America which is expected to become operational in the first quarter of 1998. This investment is a foreign EWG.
Acquisition with a partner of a 90% interest in two Argentine electric distribution companies serving the Buenos Aires Province for $565 million. CEA's indirect ownership of the two companies is 30%. Each of these investments is an exempt FUCO.
Acquisition of a 49% interest in an operating 180 MW oil-fired cogeneration plant located on the island of Oahu in Hawaii. This investment is a U.S. domestic QF.
Acquisition of an 80% interest in a 30 MW coal-fired cogeneration plant in the Jiangsu Province of China which is currently under construction. This investment is a foreign EWG.
Acquisition of 27% and 50% ownership interests in energy development companies located in the Philippines and Thailand, respectively. The project in the Philippines is a foreign EWG and the Thai investment is a power development company.
The aggregate investment made in 1997 was approximately $852 million, of which $233 million was financed with non-recourse debt.
PSRC
During 1997, PSRC entered into leveraged leases of four power plants: one located in the United Kingdom and three in the Netherlands. The aggregate of these investments was approximately $145 million.
During 1997, PSRC's investments in certain collateralized bond obligation securities and its equity investment in the underlying limited partnership were liquidated. Also in 1997, PSRC sold a DC10 aircraft, which was subject to a direct financing lease. The aggregate proceeds from these asset sales was approximately $62 million, which approximated the book cost of the assets sold.
On January 2, 1998, the lessee of one of PSRC's leveraged leases exercised an early buyout option contained in the lease. As a result, in 1998, PSRC received approximately $59 million of proceeds resulting in an after-tax gain of approximately $6 million.
Energis
Energis continued to expand its customer base to more than 5,000 businesses and increased its capabilities in providing energy services to customers, including:
Securing over 800 new business customers during a Pennsylvania Electric Pilot Program.
Acquiring, in January 1998, a diversified mechanical service contractor which provides services to commercial and industrial clients in Pennsylvania, New Jersey and Delaware.
Entering into a strategic alliance to market and service compact, portable generators.
Capital Requirements--PSE&G
PSE&G had utility plant additions of $557 million, $603 million and $686 million, for 1997, 1996 and 1995, respectively, including AFDC of $15 million, $17 million and $36 million, respectively. Construction expenditures were related to improvements in PSE&G's existing power plants (including acquisition of nuclear fuel), transmission and distribution system, gas system and common facilities. PSE&G also expended $28 million, $34 million and $30 million for the cost of plant removal (net of salvage) in 1997, 1996 and 1995, respectively. Construction expenditures from 1998 through 2002 are expected to aggregate $3.1 billion, including AFDC. Forecasted construction expenditures are related to improvements in PSE&G's transmission and distribution system, existing power plants (including acquisition of nuclear fuel), gas system and common facilities. (See Construction and Capital Requirements Forecast below.) The decision to make these improvements will depend, in part, upon the outcome of the Energy Master Plan proceeding.
PSE&G expects that it will be able to internally generate all of its construction and capital requirements over the next five years, assuming adequate and timely recovery of costs, as to which no assurances can be given (see Note 2. Rate Matters and Note 10. Commitments and Contingent Liabilities of Notes).
Construction and Capital Requirements Forecast
The projected effect of securitization, as included in PSE&G's Energy Master Plan proposal, is not included in the above forecast (see Note 2. Rate Matters of Notes).
External Financings
Enterprise
At December 31, 1997 and 1996, Enterprise had a $75 million and a $25 million uncommitted line of credit, respectively, with a bank. At December 31, 1997, Enterprise had $75 million outstanding under this line of credit. At December 31, 1997, Enterprise had a committed $150 million revolving credit facility which expires in December 2002. At December 31, 1997, Enterprise had no debt outstanding under this revolving credit facility.
In January 1998, Enterprise Capital Trust I, a special purpose statutory business trust controlled by Enterprise, issued $225 million of 7.44% Trust Originated Preferred Securities (Guaranteed Preferred Beneficial Interest in Enterprise's Debentures). Proceeds were lent to Enterprise and are evidenced by deferrable interest subordinated debenture. Enterprise used the proceeds to make a $218 million equity investment in EDHI. The debentures and their related indenture constitute a full and unconditional guarantee by Enterprise of the Preferred Securities issued by the trust. If and for as long as payments on Enterprise's debentures have been deferred, or Enterprise has defaulted on the indenture related thereto or its guarantee thereof, Enterprise may not pay any dividends on its Common Stock. Also in January 1998, Enterprise paid off the $75 million outstanding under its line of credit.
PSE&G
PSE&G has obtained BPU approval through December 31, 1998 to opportunistically refinance essentially all of its long-term debt and to refund up to $250 million of matured debt. Under its Mortgage, PSE&G may issue new First and Refunding Mortgage Bonds (Bonds) against previous additions and improvements and/or retired Bonds provided that its ratio of earnings to fixed charges is at least 2:1. As of December 31, 1997, the Mortgage would permit up to $3.3 billion aggregate principal amount of new Bonds to be issued against previous additions and improvements. At December 31, 1997, the coverage ratio under PSE&G's Mortgage was 3.45:1.
In February 1997, PSE&G Capital Trust II, a special purpose statutory business trust controlled by PSE&G, issued $95 million of 8.125% Quarterly Income Preferred Securities (Quarterly Guaranteed Preferred Beneficial Interest in PSE&G's Subordinated Debentures). PSE&G used the proceeds to fund the redemption of all 188,684 shares of its 6.80% Cumulative Preferred Stock $100 par value at $102 per share on January 31, 1997 and redeemed all 750,000 shares of its 7.44% Cumulative Preferred Stock $100 par value at $103.72 per share in June 1997.
In April 1997, PSE&G issued $25 million of Variable Rate Pollution Control Bonds, Series X, due 2031. PSE&G also issued $19 million of Variable Rate Pollution Control Notes due 2027 in June 1997. The proceeds of each of these issuances were used to redeem prior debt related to pollution control facilities of PSE&G.
In June 1997, PSE&G issued $235 million of 6.50% Bonds, Series XX, due 2000. The proceeds were used primarily to refund $117 million of its 8.50% Bonds, Series LL, due 2022 and to reimburse its treasury for the purchase of other Bonds in the open market. Also in June 1997, PSE&G's 6.875% Bonds, Series KK, of $150 million matured.
On November 1, 1997, $150 million of PSE&G's 7.125% Bonds, Series GG, matured. The redemption of these bonds was funded by the issuance of commercial paper. Also in November 1997, PSE&G issued $9 million of Secured MTNs, Series A at 7.04% and redeemed $9 million of its 9.25% Bonds, Series CC.
In January 1998, $100 million of PSE&G's 6.00% Bonds, Series NN, matured.
To provide liquidity for its commercial paper program, PSE&G has a $650 million revolving credit agreement expiring in June 1998 and a $650 million revolving credit agreement expiring in June 2002 with a group of commercial banks, which provide for borrowings of up to one year. On December 31, 1997, there were no borrowings outstanding under these credit agreements.
The BPU has authorized PSE&G to issue and have outstanding at any one time through January 2, 1999, not more than $1.3 billion of short-term obligations, consisting of commercial paper and other unsecured borrowings from banks and other lenders. On December 31, 1997, PSE&G had $1.026 billion of short-term debt outstanding, including $74 million borrowed against its uncommitted bank lines of credit which lines of credit totaled $174 million as of December 31, 1997.
PSE&G Fuel Corporation (Fuelco) has a $125 million commercial paper program to finance a 42.49% share of Peach Bottom nuclear fuel, supported by a $125 million revolving credit facility with a group of banks, which expires on June 28, 2001. PSE&G has guaranteed repayment of Fuelco's respective obligations under this program. As of December 31, 1997, Fuelco had commercial paper of $80 million outstanding under the program.
EDHI
The minimum net worth maintenance agreement between Capital and Enterprise provides, among other things, that Enterprise (1) maintain its ownership, directly or indirectly, of all outstanding common stock of Capital, (2) cause Capital to have at all times a positive tangible net worth of at least $100,000 and (3) make sufficient contributions of liquid assets to Capital in order to permit it to pay its debt obligations. In 1993, Enterprise agreed with the BPU to make a good-faith effort to eliminate such Enterprise support within six to ten years. Effective January 31, 1995, Capital notified the BPU of its intention not to have more than $650 million of debt outstanding at any time. Capital's assets consist principally of demand notes of CEA and PSRC. Intercompany borrowing rates are established based upon Capital's cost of funds. At December 31, 1997, Capital had total debt outstanding of $611 million, including $573 million of MTNs. In October 1997, Capital issued $165 million of MTNs with an average interest rate of 6.75%, which was used to fund CEA's investments.
As of December 31, 1997, Funding had $300 million and $150 million revolving credit facilities with two groups of banks and had $128 million of Senior Notes outstanding. Funding makes short-term investments only if the funds cannot be employed in intercompany loans. Intercompany borrowing rates are established based upon Funding's cost of funds. Funding is providing both long and short-term capital for PSRC and CEA and their subsidiaries on the basis of an unconditional guaranty from EDHI, but without direct support from Enterprise. As of December 31, 1997, Funding had $395 million of total debt outstanding.
EDHI, CEA and PSRC are subject to restrictive business and financial covenants contained in existing debt agreements. EDHI is required to maintain a debt to equity ratio of no more than 2.0:1 and a twelve-months earnings before interest and taxes to interest (EBIT) coverage ratio of at least 1.50:1. As of December 31, 1997 and 1996, EDHI had consolidated debt to equity ratios of 1.80:1 and 1.05:1 respectively, and for the years ended December 31, 1997, 1996 and 1995, EBIT coverage ratios, as defined to exclude the effects of EGDC and the gain on the sale of EDC, of 2.20:1, 2.45:1 and 2.47:1, respectively. Compliance with applicable financial covenants will depend upon future financial position and levels of earnings, as to which no assurance can be given. In addition, EDHI's ability to continue to grow its business will depend upon Enterprise's and EDHI's ability to obtain additional financing beyond current levels.
Qualitative and Quantitative Disclosures about Market Risk
The market risk inherent in Enterprise's market risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, equity security prices, interest rates and foreign currency exchange rates as discussed below. Enterprise's policy is to use physical forward and options contracts, and to a lesser extent, financial derivatives for the purpose of managing risk consistent with its business plans and prudent practices. Enterprise has a Risk Management Committee made up of executive officers and an independent risk oversight function to enhance its risk management practices.
Enterprise is exposed to credit losses in the event of non-performance or non-payment by counterparties. Enterprise has a credit management process which is used to assess, monitor and mitigate counterparty exposure for PSE&G and EDHI. Management does not expect counterparty defaults to materially impact the financial condition, results of operations and net cash flows of Enterprise and PSE&G.
Commodities--PSE&G
The availability and price of energy commodities are subject to fluctuations from factors such as weather, environmental policies, changes in demand and state and Federal regulatory policies. To reduce price risk caused by market fluctuations, PSE&G enters into physical forward and options contracts and, to a lesser extent, financial derivatives including forwards, futures, swaps and options with approved counterparties to hedge its anticipated demand. These contracts, in conjunction with owned electric generating capacity, are designed to cover estimated electric and gas customer commitments. Gains and losses resulting from physical forward and options contracts and financial derivatives are recognized as a component of fuel revenue and expense upon maturity of these contracts. Additionally, PSE&G enters into physical forward and options contracts that are speculative in nature which are immaterial to PSE&G's market portfolio and do not have a material impact on PSE&G's financial condition, results of operations and net cash flows (see Note 1. Organization and Summary of Significant Accounting Policies of Notes).
PSE&G uses a value-at-risk model to assess the market risk of its commodity business. This model includes fixed price sales commitments, owned generation, native load requirements, physical contracts and financial derivative instruments. Value-at-risk represents the potential gains or losses for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. PSE&G estimates value-at-risk across its commodity business using a model with historical volatilities and correlations. The measured value-at-risk using a variance/co-variance model with a 97.5 percent confidence level and assuming a one week horizon at December 31, 1997 was approximately $7 million. PSE&G's calculated value-at-risk exposure represents an estimate of potential net losses that could be recognized on its portfolio of physical and financial derivative instruments assuming historical movements in future market rates. These estimates, however, are not necessarily indicative of actual results which may occur, since actual future gains and losses will differ from those historical estimates, based upon actual fluctuations in market rates, operating exposures, and the timing thereof, and changes in PSE&G's portfolio of hedging instruments during the year.
Commodities--EDHI
During 1997, Energis entered into futures contracts to buy natural gas related to fixed-price natural gas sales commitments. Such contracts hedged approximately 97% of its fixed price sales commitments at December 31, 1997. As of December 31, 1997, Energis had a net unrealized hedge loss of $2 million.
During 1997, Energis entered into fixed price electricity sales commitments. Physical purchase contracts hedged approximately 10% of such fixed price sales commitments at December 31, 1997.
Energis estimates value-at-risk across its electric and natural gas commodities using a model with historical volatilities and correlations. The measured value-at-risk using a variance/co-variance model with a 97.5 percent confidence level and assuming a one-week horizon at December 31, 1997 was approximately $0.2 million. Energis' calculated value-at-risk exposure represents an estimate of potential losses that could be recognized on its portfolio of physical and financial derivative instruments assuming historical movements in future market prices. These estimates, however, are not necessarily indicative of actual results which may occur, since actual future gains and losses will differ from those historical estimates, based upon actual fluctuations in market rates, operating exposures, and the timing thereof, and changes in Energis' portfolio of hedging instruments during the year.
Nuclear Decommissioning Trust Funds--PSE&G
Contributions made into the Nuclear Decommissioning Trust Funds are invested in debt and equity securities. These marketable debt and equity securities are recorded at a fair value of $458 million at December 31, 1997 and have exposure to price risk. The potential change in fair value resulting from a hypothetical 10% change in quoted market prices of these securities amounts to $46 million. All realized gains on Nuclear Decommissioning Trust Fund investments are recorded as a component of accumulated depreciation while unrealized gains are recorded as deferred credits and neither affects earnings.
Equity Securities--EDHI
PSRC has investments in equity securities and partnerships which invest in equity securities. The aggregate amount of such investments which have available market prices at December 31, 1997 are recorded at fair value of $185 million and have exposure to price risk. A sensitivity analysis has been prepared to estimate EDHI's exposure to market sensitivity of these investments. The potential change in fair value resulting from a hypothetical 10% change in quoted market prices of these investments amounts to $15 million.
Interest Rates--PSE&G
PSE&G is subject to the risk of fluctuating interest rates in the normal course of business. PSE&G's policy is to manage interest rates through the use of fixed and, to a lesser extent, floating rate debt. PSE&G's interest rate risk related to existing fixed, long-term debt is not significant as PSE&G has BPU approval to issue long-term debt for opportunistic refinancing purposes. As of December 31, 1997, a hypothetical 10% change in interest rates would result in a $8 million change in interest costs related to short-term and floating rate debt.
Interest Rates--EDHI
EDHI is subject to the risk of fluctuating interest rates in the normal course of business. EDHI's policy is to manage interest rates through the use of fixed rate debt, floating rate debt and interest rate swaps. As of December 31, 1997, a hypothetical 10% change in interest rates would result in a $2 million change in interest costs related to short-term and floating rate debt.
In June 1997, an indirect subsidiary of CEA entered into an agreement to swap floating rate borrowings into fixed rate borrowings. The interest differential to be received or paid under the interest rate swap agreement is recorded over the life of the agreement as an adjustment to the interest expense of the related borrowing. The swap terminates on May 28, 1999.
The notional amounts and interest rates are as follows:
Pay-Fixed Swap -------------- Notional amount........................ $43.5 million Pay rate............................... 6.65% Average receive rate................... 5.73% Year-end receive rate.................. 5.91%
Foreign Currencies--EDHI
CEA has non-recourse debt of $135 million which is denominated in Brazilian Reals that is indexed to a basket of currencies including U.S. dollars. As a result, it is subject to foreign currency exchange rate risk due to the effect of exchange rate movements between the indexed foreign currencies and the Brazilian Real. Exchange rate changes ultimately impact the debt level outstanding in the denominated currency and result in foreign currency transactions in accordance with current accounting guidance. Any related transaction gains or losses resulting from such exchange rate changes are included in determining net income for the period. The potential change in non-recourse debt resulting from a hypothetical 10% change in exchange rates amounts to approximately $9 million.
Nuclear Operations
As previously reported, Salem 1 and 2 were taken out of service by PSE&G in the second quarter of 1995. In June 1995, the Nuclear Regulatory Commission (NRC) issued a Confirmatory Action Letter (CAL) which documented commitments of PSE&G to keep each unit off line until it is satisfied that the unit is ready to return to service and to operate reliably over the long term and until the NRC agrees that the unit is sufficiently prepared to restart. Salem 2 returned to service on August 30, 1997. The NRC amended the CAL to require a final assessment of Salem 2 after approximately two months of full power operation. A meeting was held with the NRC on December 4, 1997 which satisfied this final CAL requirement for Salem 2.
Installation of Salem 1 steam generators has been completed and that unit is expected to return to service around the end of the first quarter of 1998. Restart of Salem 1 is subject to completion of the requirements of the restart plan to the satisfaction of PSE&G and the NRC. The cost of the steam generator replacement, including installation, was approximately $170 million (PSE&G's share was $72 million). In addition, the cost of disposal of the four old steam generators was $16 million (PSE&G's share was $7 million). Restart of Salem 1 is also subject to completion of the requirements of the restart plan to the satisfaction of PSE&G and the NRC. The NRC's Readiness Assessment Team Inspection (RATI) of Salem 1 (a requirement for restart) commenced on February 10, 1998. PSE&G expects that the NRC will complete its inspection in February 1998. The inability to successfully return Salem 1 to operation could have a material adverse impact on the financial condition, results of operations and net cash flows of Enterprise and PSE&G (see Forward Looking Statements).
PSE&G's share of total operating and maintenance expenses for both Salem units for 1997 was $115 million and capital costs were $65 million, which includes $19 million for steam generator replacement and excludes $13 million related to the ACE settlement described below. The outage of a Salem unit causes PSE&G to incur replacement power costs of approximately $4 to $5 million per month. Such amounts vary, however, depending on the availability of other generation, the cost of purchased energy and other factors, including modifications to maintenance schedules of other units.
PSE&G and ACE entered into an operating agreement which resulted in the dismissal of a lawsuit initiated by ACE related to Salem performance. Under the agreement, ACE paid a portion of its share of the 1997 operation and maintenance expenses based on the amount of generation of the Salem units. PSE&G incurred approximately $13 million of ACE's share of 1997 operation and maintenance expenses since Salem 2 did not operate for the first eight months of 1997 and Salem 1 did not return to service during 1997.
At the January 1997 semi-annual NRC Senior Management Meeting, the NRC placed Salem 1 and 2 on the NRC Watch List and designated them as Category 2 facilities (i.e., a plant that is authorized to operate, but one that the NRC will monitor closely), noting that this action was not due to any performance problems or decline during its current evaluation period but rather that Salem should have been placed on the NRC Watch List earlier. The letter stated that the NRC staff was satisfied with the overall approach being taken by PSE&G to return the Salem units to service. Salem 1 and 2 remain on the NRC Watch List as a Category 2 plant.
For information on Salem litigation, see Note 10. Commitments and Contingent Liabilities of Notes.
Competitive Environment
Many forces are reshaping how the utility industry meets the needs and expectations of its customers and shareholders. Profound changes in the way the industry is regulated will affect how Enterprise conducts business and its financial prospects in the future. Competitive changes in the utility industry continued to occur in 1997 and early 1998. See Note 2. Rate Matters of Notes for information on the final Phase II report and the Energy Master Plan proceedings.
FERC Order No. 888 (Order No. 888)
Order No. 888 became effective in July 1996 and requires all public utilities owning, controlling or operating transmission lines to file nondiscriminatory open access tariffs that offer others the same transmission service which they provide to themselves. Intra-pool transactions for power pools were also required to be under a nondiscriminatory, pool-wide open access tariff by March 1, 1997. Numerous parties, including PSE&G, filed requests seeking rehearing and clarification of various aspects of Order No. 888. As a result of those requests, FERC issued Orders No. 888-A and 888-B. Orders No.888-A and 888-B clarified and largely reaffirmed the legal and policy bases on which Order No. 888 was grounded. Orders No.888-A and 888-B also provided clarifications and modifications to the FERC's original pro forma open access transmission tariff and process for recovery of stranded costs from wholesale customers ordered as a result of Order No. 888. Numerous parties, including PSE&G, have filed petitions for judicial review of these orders and these petitions are currently pending before the United States Courts of Appeals for the District of Columbia and the Second Circuits (see PJM).
As a result of open access mandated by Order No. 888, PSE&G and other New Jersey utilities are facing increased competition from older, dirtier coal-fired plants in the Midwest that are subject to less restrictive pollution control requirements than utilities in Northeastern states and consequently, are able to produce lower cost energy. These facilities, by increasing their power production in order to sell into the Northeast market, will, in turn, increase the release of pollutants that eventually make their way to New Jersey and other Northeastern states due to the prevailing westerly winds. PSE&G, which has to comply with strict New Jersey environmental laws, will be at a competitive disadvantage if Order No. 888 is not modified to recognize this issue.
On October 27, 1997, Old Dominion Electric Cooperative (ODEC) filed a Complaint at FERC seeking to modify its 1992 Agreement with PSE&G for a ten-year sale of 150 MW of capacity and energy. ODEC's Complaint argues that given the restructuring of PJM, particularly PJM's new regional rate design which effectively eliminates rate "pancaking" for transmission that traverses more than one transmission system, it is unreasonable to leave intact existing bilateral agreements that have the same effect. It therefore urges FERC to reduce ODEC's contract capacity rate with PSE&G (reducing PSE&G's revenue by $3-$5 million per year) to eliminate the imputed transmission charge. In an answer filed December 1, 1997, PSE&G responded that the contract rates were negotiated at arm's length, are fully cost justified and cannot legally be modified absent an overriding public interest. Although it has not yet acted on these filings, FERC appears to have summarily decided the issue in ODEC's favor in its November 25, 1997 PJM Restructuring Order (November 25th Order) (see discussion below). PSE&G has requested rehearing and clarification of the November 25th Order.
Pennsylvania--New Jersey--Maryland Interconnection (PJM)
PSE&G is a member of PJM which integrates the bulk power generation and transmission supply operations of 11 utilities in Pennsylvania, New Jersey, Delaware, Maryland, Virginia and the District of Columbia, and, in turn, is interconnected with other major electric utility companies in the northeastern part of the United States. PJM is operated as one system and provides for the purchase and sale of power among members on the basis of reliability of service and operating economy. As a result, the most economical mix of generating capability available is used to meet PJM hourly load requirements. PSE&G's output, as shown under Electric Fuel Supply and Disposal, reflects significant amounts of purchased power because at times it is more economical for PSE&G to purchase power from PJM and others than to produce it. As of December 31, 1997, the aggregate installed generating capacity of the PJM companies was 57,216 MW. The all time record peak one-hour demand experienced by PJM was 49,406 MW which occurred on July 15, 1997. PSE&G's capacity obligations to the PJM system vary from year to year due to changes in system characteristics. PSE&G expects to have sufficient installed capacity to meet its obligations during the 1998-2002 period.
PSE&G is also a party to the Mid-Atlantic Area Reliability Council which provides for review and evaluation of plans for generation and transmission facilities and other matters relevant to reliability of the bulk electric supply systems in the Mid-Atlantic area.
In July 1996, the member companies of PJM, including PSE&G but excluding PECO Energy, filed a proposal to reorganize PJM into an Independent System Operator (ISO) to administer a pool-wide open-access transmission tariff and to operate a centrally dispatched bid-based energy market in response to Order No. 888. PECO Energy filed a separate proposal with FERC. On November 13, 1996, FERC announced that it was rejecting the restructuring proposals of both PECO Energy and the other PJM companies (the PJM Supporting Companies) due to concerns regarding the independence of the proposed ISO and directed PJM to submit a single consensus pool restructuring proposal by December 31, 1996. On December 31, 1996, PJM submitted a pool-wide open-access transmission tariff and a reformed pooling agreement. FERC issued an order on February 28, 1997, accepting most of the PJM Supporting Companies' proposal on an interim basis, effective April 1, 1997.
On June 2, 1997, the PJM member companies, except for PECO Energy, filed a revised proposal with the FERC to reorganize PJM into an ISO. On June 9, 1997, PECO Energy filed a competing proposal that continued to advocate a different design of the energy market and transmission tariffs.
In its November 25th Order, FERC conditionally approved, effective January 1, 1998, the PJM Supporting Companies' proposal to restructure the PJM power pool and establish an ISO consistent with the requirements of Order No. 888. The November 25th Order specifically approved a two-tier governance structure under which an independent 7-member Board of Managers (PJM Board) would be responsible for supervision and oversight of the day-to-day operations of PJM; while a Members Committee, consisting of five sectors representing generation owners, other suppliers, transmission owners, electric distribution and end-use customers would elect, and provide advice to, the PJM Board. The order also accepted the proposed zonal rate design, subject to its being replaced by a more uniform, regional rate design within five years. FERC also accepted the proposed locational marginal pricing (LMP) methodology for recovery of transmission congestion costs, but acknowledged that the lack of price certainty is a limitation of LMP and ordered the ISO to initiate a process to address this concern. FERC subsequently approved the ISO's request to defer implementation of LMP until April 1, 1998.
The November 25th Order also introduced a new issue that could have an impact of approximately $3 to $5 million annually on PSE&G. FERC ordered that all existing power sales and wheeling agreements, such as between PSE&G and ODEC, be modified to eliminate multiple transmission charges to be consistent with the restructured PJM. PSE&G separately, and along with the other PJM Supporting Companies, has requested rehearing and clarification regarding this issue and is vigorously contesting this issue. PSE&G cannot predict the final outcome of these proceedings.
A further potential impact of PJM restructuring relates to the operation of the Keystone-Conemaugh coal-fired electric power plants which are owned by a joint venture consisting of PSE&G and nine other utilities. In order to assure that the joint venture's proposed operation of these plants in the context of the new PJM energy exchange would be consistent with antitrust law requirements, the Antitrust Division of the DOJ was requested to indicate that it has no present intention of taking enforcement action with respect to the joint venture's proposed plan of operation. The DOJ responded on January 30, 1998 indicating no antitrust concerns.
New Jersey Gross Receipts and Franchise Tax (NJGRT) Reform
For a discussion of NJGRT Reform, see Note 2. Rate Matters of Notes.
Gas Unbundling
For a discussion of Gas Unbundling, see Note 2. Rate Matters of Notes.
Energy Resources and Trading
PSE&G has established an energy resources and trading organization to engage in wholesale transactions in electricity and gas. For additional information, see Qualitative and Quantitative Disclosures About Market Risk.
Energis
Energis has been formed to better position Enterprise to enter the rapidly deregulating energy market by marketing a variety of energy related products and services to industrial and commercial customers throughout the Northeast and Mid-Atlantic states. Energis offers a variety of services: sales of natural gas and electricity; energy consulting; engineering, equipment installation and repair; inspection and diagnostic services for motors, generators and other energy conversion and use equipment; and up-front financing. Energis' customers include small businesses, department stores, schools, hospitals and manufacturers from Maine to Maryland. For additional information, see Qualitative and Quantitative Disclosures About Market Risk.
Bond Ratings
The changes in the utility industry are attracting increased attention of bond rating agencies which regularly assess business and financial matters including how utility companies are meeting competition and competitive initiatives, especially as they affect potential stranded costs. Bond ratings affect the cost of capital and the ability to obtain external financing. PSE&G continually updates the rating agencies on all corporate matters in order to minimize surprises and give the rating agencies time to comprehend the information. Given the uncertainty of the industry, attention and scrutiny of PSE&G's competitive strategies by rating agencies will likely continue. This could result in changes to Enterprise's and PSE&G's bond ratings (see Item 1. General--Credit Ratings).
Rate Matters
For discussions of the Energy Master Plan, Stranded Costs, Securitization, Depreciation, NJGRT Reform, Settlement of Certain Regulatory Issues, the LGAC, the LEAC, the Demand Side Adjustment Factor, the Remediation Adjustment Charge, Consolidated Tax Benefits, OPEB, and other rate matters, see Note 2. Rate Matters of Notes.
Accounting Issues
For a discussion of significant accounting policies in regard to regulation of PSE&G, including discussion of Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation," and Emerging Issues Task Force (EITF) Issue 97-4, "Deregulation for the Pricing of Electricity - Issues Related to the Application of FASB Statements No. 71 and 101," see Note 1. Organization and Summary of Significant Accounting Policies of Notes.
Impact of New Accounting Pronouncements
In June 1997, the Financial Accounting Standards Board (FASB) issued SFAS 130, "Reporting Comprehensive Income" (SFAS 130), which is effective for fiscal years beginning after December 15, 1997. SFAS 130 requires that all items required to be recognized under accounting standards as components of comprehensive income be reported in a financial statement displayed with the same prominence as other financial statements. It also requires that an enterprise classify items of other comprehensive income by their nature in a financial statement and display the accumulated balance of other comprehensive income separately from retained earnings and additional paid-in capital in the equity section of a statement of financial position.
Also in June 1997, the FASB issued SFAS 131, "Disclosures about Segments of an Enterprise and Related Information" (SFAS 131), which is effective for financial statements for periods beginning after December 15, 1997. This Statement need not be applied to interim financial statements in the initial year of its application. SFAS 131 supersedes SFAS 14, "Financial Reporting for Segments of a Business Enterprise" and requires that companies disclose segment data based on how management makes decisions about allocating resources to segments and measuring their performance.
The adoption of SFAS 130 and SFAS 131 is not expected to have a material impact on the financial condition, results of operations and net cash flows of Enterprise or PSE&G.
Site Restorations and Other Environmental Costs
It is difficult to estimate the future financial impact of environmental laws, including potential liabilities. PSE&G accrues environmental provisions when it is probable that a liability has been incurred and the amount of the liability is reasonably estimable. Provisions for estimated losses from environmental remediation are, depending on the site, based primarily on internal and third-party environmental studies, estimates as to the number and participation level of any other Potentially Responsible Parties, the extent of the contamination and the nature of required remedial and restoration actions. The cost of environmental remediation could be material to Enterprise and PSE&G's financial position, results of operations and net cash flows (see Note 10. Commitments and Contingent Liabilities of Notes).
Future Outlook
Enterprise and PSE&G will face additional challenges with the continuing emergence of competition in 1998. Depending upon the BPU's actions in the Energy Master Plan proceedings, PSE&G's customers could begin choosing their energy suppliers as early as October 1998 with their choices becoming effective January 1999. In light of this, Enterprise and PSE&G are seeking to ensure that the new rules for electric industry restructuring provide customer choice and lower cost without endangering public safety or compromising New Jersey's stringent environmental standards or the reliability of electric service.
Further expansion in the non-regulated businesses of Enterprise will be necessary to allow Enterprise to achieve its future growth objectives. To this end, Enterprise's strategy will be to rely to a large extent on CEA, PSRC and Energis. CEA will continue to focus on the international market. PSRC plans to continue to make investments in the energy sector. Energis plans to continue to market new and existing energy products and services to commercial and industrial business customers throughout the Northeast and Mid-Atlantic states.
Deregulation will also place a greater emphasis on lowering electricity prices and costs. If PSE&G's Energy Master Plan proposal is adopted, rates will be frozen for seven years. PSE&G will continue to bear the risk of changes in fuel costs. Enterprise's wholesale energy trading and resource organization will continue to develop strategies to reduce costs, increase profits and manage both commodity and financial risks. Expansion of other non-traditional utility areas, such as the appliance service business within and outside of New Jersey, will also be key to the future of Enterprise and PSE&G.
Enterprise is continuing to emphasize operational excellence as a key business objective. While Enterprise and PSE&G have improved productivity and efficiencies, efforts continue to improve response speed, reliability, employee safety, customer satisfaction, quality, cost management and cost-competitiveness.
Enterprise has paid quarterly dividends in each year commencing with the corporate restructuring of PSE&G when Enterprise became the owner of all the outstanding common stock of PSE&G. While a key objective of the Board of Directors of Enterprise is to keep the Common Stock dividend secure, amounts and dates of such dividends as may be declared will necessarily be dependent upon Enterprise's future earnings, financial requirements and other factors including the receipt of dividend payments from its subsidiaries.
Enterprise and PSE&G cannot predict the ultimate outcome of the ongoing changes in the utility industry. Decisions in the Energy Master Plan proceedings including those which will impact PSE&G's recovery of stranded costs and ability to use securitization could have a material adverse impact on Enterprise's and PSE&G's financial condition, results of operations and net cash flows. Enterprise and PSE&G believe that the end result will involve a fundamental change in the way their businesses are conducted. These changes may impact financial operating trends and could result in earnings volatility. PSE&G is actively seeking regulatory and operational changes that will allow it to provide energy services in a safe and reliable manner at competitive prices while achieving strong financial performance (see Note 1. Organization and Summary of Significant Accounting Policies and Note 2. Rate Matters of Notes).
PSE&G
The information required by this item is incorporated herein by reference to the following portions of Enterprise's Management's Discussion and Analysis of Financial Condition and Results of Operations, insofar as they relate to PSE&G and its subsidiaries: Corporate Structure; Overview of 1997; Results of Operations; Liquidity and Capital Resources; External Financings; Qualitative and Quantitative Disclosures About Market Risk; Nuclear Operations; Competitive Environment; Rate Matters; Accounting Issues; Impact of New Accounting Pronouncements; Site Restorations and Other Environmental Costs and Future Outlook.
Forward Looking Statements
The Private Securities Litigation Reform Act of 1995 (the Act) provides a "safe harbor" for forward-looking statements to encourage such disclosures without the threat of litigation providing those statements are identified as forward-looking and are accompanied by meaningful, cautionary statements identifying important factors that could cause the actual results to differ materially from those projected in the statement. Forward-looking statements have been made in this report. Such statements are based on management's beliefs as well as assumptions made by and information currently available to management. When used herein, the words "will", "anticipate", "estimate", "expect", "objective", "hypothetical", "potential" and similar expressions are intended to identify forward-looking statements. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following: deregulation and the unbundling of energy supplies and services; an increasingly competitive energy marketplace; sales retention and growth potential in a mature service territory and a need to contain costs; ability to obtain adequate and timely rate relief, cost recovery, including the potential impact of stranded costs, and other necessary regulatory approvals; Federal and state regulatory actions; costs of construction; operating restrictions, increased cost and construction delays attributable to environmental regulations; nuclear decommissioning and the availability of reprocessing and storage facilities for spent nuclear fuel; licensing and regulatory approval necessary for nuclear and other operating stations; and credit market concerns. Enterprise and PSE&G undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors pursuant to the Act should not be construed as exhaustive or as any admission regarding the adequacy of disclosures made by Enterprise and PSE&G prior to the effective date of the Act.
Item 7A.
Item 7A. Qualitative and Quantitative Disclosures About Market Risk
Information relating to quantitative and qualitative disclosure about market risk is set forth under the caption "Qualitative and Quantitative Disclosures about Market Risk" in Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and "Financial Instruments" in Note 1. Organization and Summary of Significant Accounting Policies of the Notes to Consolidated Financial Statements. Such information is incorporated herein by reference. For PSE&G, the information required by this item is incorporated herein by reference insofar as it relates to PSE&G and its subsidiaries.
Item 8.
Item 8. Financial Statements and Supplementary Data
[THIS PAGE INTENTIONALLY LEFT BLANK]
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization and Summary of Significant Accounting Policies
Organization
Public Service Enterprise Group Incorporated (Enterprise) has two direct wholly owned subsidiaries, Public Service Electric and Gas Company (PSE&G) and Enterprise Diversified Holdings Incorporated (EDHI). Enterprise's principal subsidiary, PSE&G, is an operating public utility providing electric and gas service within certain areas in the State of New Jersey.
EDHI is the parent of Enterprise's non-utility businesses: Community Energy Alternatives Incorporated (CEA), an investor in and developer and operator of projects in the generation, transmission and distribution of energy, including cogeneration and independent power production (IPP) facilities, electric distribution companies, exempt wholesale generators (EWGs) and foreign utility companies (FUCOs); Public Service Resources Corporation (PSRC), which has made primarily passive investments; Energis Resources Incorporated (Energis), which provides a variety of energy related services to industrial and commercial customers both within and outside of PSE&G's traditional service territory and Enterprise Group Development Corporation (EGDC), a nonresidential real estate development and investment business. EDHI also has two finance subsidiaries: PSEG Capital Corporation (Capital), which provides privately-placed debt financing to EDHI's operating subsidiaries, except Energis, on the basis of a minimum net worth maintenance agreement with Enterprise and Enterprise Capital Funding Corporation (Funding), which provides privately-placed debt financing to PSRC, CEA and their subsidiaries, which debt is guaranteed by EDHI, but without direct support from Enterprise. EGDC has been conducting a controlled exit from the real estate business since 1993. In July 1996, EDHI sold Energy Development Corporation (EDC), an oil and gas subsidiary.
Summary of Significant Accounting Policies
Regulation--PSE&G
The accounting and rates of PSE&G are subject, in certain respects, to the requirements of the New Jersey Board of Public Utilities (BPU) and the Federal Energy Regulatory Commission (FERC). As a result, PSE&G maintains its accounts in accordance with their prescribed Uniform Systems of Accounts, which are the same. The application of Generally Accepted Accounting Principles (GAAP) by PSE&G differs in certain respects from applications by non-regulated businesses. PSE&G prepares its financial statements in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71). In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect the relationship of costs and revenues. As a result, a regulated utility may defer recognition of costs (a regulatory asset) or recognize obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in revenues. Accordingly, PSE&G has deferred certain costs, which will be amortized over various periods. To the extent that collection of such costs or payment of liabilities is no longer probable as a result of changes in regulation and/or PSE&G's competitive position, the associated regulatory asset or liability will be charged or credited to income (see Note 3. Regulatory Assets and Liabilities). PSE&G continues to meet the requirements for application of SFAS 71.
The regulatory changes proposed in the New Jersey Energy Master Plan (Energy Master Plan) will create a shift from regulated pricing to competitive market pricing for electric generation. Assuming enactment of the required enabling legislation, these proposed changes will limit Enterprise's and PSE&G's ability to continue to meet the applicable criteria of SFAS 71 for the generation portion of PSE&G's business. If PSE&G were to discontinue the application of SFAS 71, there could be an extraordinary, non-cash charge to operations that could be material to the financial position and results of operations of Enterprise and PSE&G. However, if PSE&G's proposal in response to the Energy Master Plan is approved by the BPU as filed, PSE&G does not expect such a charge to occur.
In response to the continuing deregulation of the electric utility industry, the Financial Accounting Standards Board (FASB), through its Emerging Issues Task Force (EITF), undertook an initiative designated as EITF 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). The purpose of this initiative was to develop guidance for the application of SFAS 101, "Regulated Enterprises Accounting for the Discontinuation of Application of FASB Statement No. 71" (SFAS 101). SFAS 101 addresses how an enterprise that ceases to meet the criteria for application of SFAS 71 to all or part of its operations should report that event in its general-purpose financial statements.
The EITF's consensus on this issue is that an enterprise is required to discontinue the application of SFAS 71 for the deregulated portion of its business once legislation is passed or a rate order is issued which contains a sufficiently detailed plan to transition from regulated pricing to market pricing. In addition, the EITF concluded that an enterprise may continue to carry on its books the regulatory assets and liabilities of the portion of the business to which SFAS 101 is being applied, provided that regulators have approved a regulated cash flow stream. This also applies to costs or obligations not yet recorded as regulatory assets or liabilities regardless of when incurred. The discontinuance of SFAS 71 also requires an enterprise to reevaluate the impact of SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of" (SFAS 121). SFAS 121 requires that regulatory assets be written off once they are no longer probable of recovery and that impairment losses be recorded for long-lived assets when related future cash flows or appraised value are less than the carrying value of the assets.
The impact to Enterprise and PSE&G will be determined based on the outcome of the Energy Master Plan proceedings, including PSE&G's proposal filed in response to those proceedings. Under its proposal, PSE&G would have the opportunity, through various mechanisms, to recover its electric generation related potentially stranded costs. Management cannot predict the outcome of the Energy Master Plan proceeding, its related legislative process or the related impact of EITF 97-4 on Enterprise's and PSE&G's future financial condition, results of operations and net cash flows. However, depending on legislative and regulatory actions taken in New Jersey with respect to electric utility deregulation, there could be a material adverse effect on such results (see Note 2. Rate Matters).
PSE&G has certain regulatory assets resulting from the use of a level of depreciation expense in the ratemaking process that differs from the amount that is recorded under generally accepted accounting principles for non-regulated companies. PSE&G cannot presently quantify what the financial statement impact would be if depreciation expense were required to be determined absent regulation, but the impact on the financial position, results of operations and net cash flows of Enterprise and PSE&G could be material (see Note 2. Rate Matters).
Statement of Position 96-1 "Environmental Remediation Liabilities" (SOP 96-1) issued by the American Institute of Certified Public Accountants is effective for the fiscal years that begin after December 15, 1996. SOP 96-1 provides guidance where remediation is required because of the threat of litigation, a claim or an assessment. This Statement does not provide guidance on accounting for pollution control costs as it applies to current operations, costs of future site restoration or closure that are required upon the cessation of operations or sale of facilities or for remediation obligations undertaken at the sole discretion of management. The adoption of SOP 96-1 did not have a material impact on the financial condition, results of operations and net cash flows of Enterprise and PSE&G. For additional information concerning certain of PSE&G's Environmental Remediation Liabilities, see Note 2. Rate Matters and Note 10. Commitments and Contingent Liabilities.
Consolidation Policy
The consolidated financial statements include the accounts of Enterprise and its subsidiaries. Enterprise and its subsidiaries consolidate those entities in which they have a controlling interest. All significant intercompany accounts and transactions are eliminated in consolidation. Those entities in which Enterprise does not have a controlling interest are being accounted for under the equity method of accounting. For investments in which significant influence does not exist, the cost method of accounting is applied. Certain reclassifications of prior year data have been made to conform with the current presentation.
Unamortized Debt Expense
Gains, losses and the costs of issuing and redeeming long-term debt are deferred and amortized over the life of the applicable debt.
Utility Plant--PSE&G
Additions to utility plant and replacements of units of property 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.
Depreciation and Amortization
Depreciation is computed under the straight-line method. Depreciation is 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. Depreciation rates stated in percentages of original cost of depreciable property were 3.53% in 1997 and 1996 and 3.52% in 1995 (see Note 2. Rate Matters).
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 mill per kilowatt-hour (KWH) of nuclear generation for spent fuel disposal costs (see Note 11. PSE&G Nuclear Decommissioning).
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.
Decontamination and Decommissioning--PSE&G
In 1993, FERC issued Order No. 557 regarding the accounting and rate-making treatment of special assessments levied under the National Energy Policy Act of 1992 (EPAct). Order No. 557 provides that special assessments are a necessary and reasonable current cost of fuel and shall be fully recoverable in rates in the same manner as other fuel costs (see Note 2. Rate Matters and Note 11. PSE&G Nuclear Decommissioning).
Allowance for Funds Used During Construction (AFDC)--PSE&G
AFDC represents the cost of debt and equity funds used to finance the construction of new 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 1997, 1996 and 1995 were 5.71%, 5.83% and 6.98%, respectively.
Revenues and Fuel Costs--PSE&G
Revenues are recorded based on services rendered to customers during each accounting period. PSE&G records unbilled revenues representing 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. Rates include projected fuel costs for electric generation, purchased and interchanged power and gas purchased. The fuel component of the LEAC rate was frozen for 1997 and 1998 as part of the December 31st Order and PSE&G bears all risks associated with fuel prices (see Note 2. Rate Matters).
Any Electric Levelized Energy Adjustment Clause (LEAC) and Levelized Gas Adjustment Clause (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. Effective January 1, 1998, the amount included for LEAC under/overrecovery represents the difference between fuel related revenues and fuel related expenses which are comprised of the cost of generation and interchanged power at the Pennsylvania--New Jersey--Maryland Interconnection (PJM) market clearing price (see Note 2. Rate Matters).
Financial Instruments--PSE&G
Under its commodity hedging program, PSE&G may enter into certain contracts with counterparties to manage exposure to electric and natural gas price volatility. These contracts, in conjunction with owned electric generating capacity, are designed to cover estimated electric and gas customer commitments. PSE&G's accounting policy for physical instruments is to recognize gains and losses in income upon settlement of the contracts. PSE&G's accounting policy for financial instruments is to mark-to-market and record unrealized gains and losses on hedged transactions as a component of stockholder's equity while unrealized gains and losses on speculative transactions are recorded in results of operations. These financial instruments and the effect of marking to market do not have a material impact on PSE&G's financial condition, results of operations and net cash flows. PSE&G does not hold any financial instruments of a leveraged nature.
Financial Instruments--EDHI
Gains and losses on hedges of existing assets or liabilities are included in the carrying amounts of those assets and liabilities and are ultimately recognized in income as part of those carrying amounts. Gains and losses related to qualifying hedges of firm commitments or anticipated transactions also are deferred and recognized in income or as adjustments of carrying amounts when the hedged transaction occurs (see Note 8. Financial Instruments).
Foreign Currency Translation--EDHI
The assets and liabilities of EDHI's 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 transactions denominated in a currency other than the functional currency, except those transactions which operate as a hedge of an identifiable foreign currency commitment or as a hedge of a foreign currency investment position, are included in the results of operations as incurred.
Income Taxes
Enterprise and its subsidiaries file a consolidated Federal income tax return and income taxes are allocated to Enterprise's subsidiaries based on the taxable income or loss of each subsidiary. Investment tax credits were deferred in prior years and are being amortized over the useful lives of the related property, including nuclear fuel.
Benefit Plans
Non-represented employees of PSE&G commencing service before January 1, 1996, represented employees of PSE&G commencing employment before January 1, 1997 and certain employees of PSE&G's affiliated companies are covered by a noncontributory trusteed pension plan (Pension Plan) from the date of hire. Non-represented employees of PSE&G who commenced service after January 1, 1996, represented employees of PSE&G who commenced employment after January 1, 1997 and certain employees of PSE&G's affiliated companies are covered by a cash balance pension plan. The policy is to fund pension costs accrued. The funding policy for the plan year 1997 was modified to provide annual funding not to exceed the maximum tax deductible amount. Contributions will be made each year based on targeted funding levels for the plan (see Note 13. Pension Plan).
In 1993, Enterprise and PSE&G adopted SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS 106), which requires that the expected cost of employees' postretirement health care and life insurance benefits be charged to income during the years in which employees render service (see Note 2. Rate Matters and Note 14. Postretirement Benefits Other Than Pensions).
Impairment of Long-Lived Assets
On January 1, 1996, Enterprise and PSE&G adopted SFAS 121, which requires review for possible impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The adoption of SFAS 121 did not have an impact on the results of operations, financial condition and net cash flows of Enterprise and PSE&G. However, future developments in the electric industry and utility regulation could jeopardize the full recovery of the carrying cost of certain investments.
Stock-Based Compensation
SFAS No. 123 "Accounting for Stock-Based Compensation" (SFAS 123) was effective for fiscal years commencing after December 15, 1995. SFAS 123 establishes financial accounting and reporting standards for stock based compensation plans and includes all arrangements by which employees receive shares of stock or other equity instruments of the employer or by which the employer incurs liabilities to employees in amounts based on the price of the employer's stock. SFAS 123 provides an entity the option to either adopt the new method or to continue to measure compensation cost as prescribed by Accounting Principles Board Opinion No. 25 (APB 25) "Accounting for Stock Issued to Employees" and provide pro forma disclosure of the effect of adopting SFAS 123. Enterprise has elected to continue its current accounting treatment for stock compensation under APB 25. If stock based compensation costs for Enterprise had been determined based on the methodology prescribed in SFAS 123, there would have been a charge to earnings of approximately $0.1 million with no impact on earnings per share.
Earnings Per Share
In February 1997, the FASB issued SFAS No. 128, "Earnings per Share", which is effective for financial statements issued after December 15, 1997. Under the new standard, basic earnings per share is computed as earnings available to common stockholders divided by weighted average shares outstanding excluding the dilutive effect of potential common shares. Diluted earnings per share includes the dilutive effect of potential common shares. Enterprise has an existing stock option plan which allows for options to be granted on a periodic basis. These potential common shares had no impact on diluted earnings per share for the years ended December 31, 1997, 1996 and 1995.
Note 2. Rate Matters
New Jersey Energy Master Plan (Energy Master Plan)
On April 30, 1997, the BPU issued its final report regarding Phase II (final Phase II report) of the Energy Master Plan addressing wholesale and retail electric competition in New Jersey. The final Phase II report was approved by the Governor and Legislature in July 1997. In accordance with the final Phase II report, PSE&G filed a proposal regarding competition and rates with the BPU on July 15, 1997. The BPU is in the process of reviewing the filing and holding public hearings. The hearings on PSE&G's proposal commenced in early February 1998 and are expected to conclude during the second quarter of 1998, with a decision expected by July 1998. Legislation providing the BPU with requisite authority to implement such competition is necessary.
The final Phase II report included the following key provisions:
Beginning January 1, 1999, the rates for bundled electricity services, consisting of power generation, transmission, distribution and auxiliary customer services, such as metering and billing, would be unbundled. Each electric utility, including PSE&G, would continue to be responsible for providing distribution service to all customers, with price and service quality for distribution service continuing to be regulated by the BPU. Other customer services would also continue to be offered by each electric utility for a monthly fee, including metering, billing and account administration, which would also continue to be regulated by the BPU.
The phase-in period for customers' choice of energy suppliers is to include 10% in October 1998, 20% by January 1999, 35% by April 1999, 50% by October 1999, 75% by April 2000, and 100% by July 2000.
Transmission service would be provided by an Independent System Operator (ISO) which would be responsible for maintaining the reliability of the regional power grid and would be regulated by FERC. Utilities would continue to pass through the cost of transmission to customers in regulated rates.
Metering and billing would also be reviewed in order to make recommendations for the introduction of competition into the customer services area. A distribution utility would be permitted to offer customer services, such as equipment repair and service contracts, in a competitive marketplace.
A fully competitive marketplace must exist before the BPU will act to end economic regulation of power supply. This will require, at a minimum, utility generating assets and activities to be functionally separated and operated at arms length from the transmission, distribution and customer service activities of the electric utilities. The BPU would reserve final judgment on the issue of requiring divestiture of utility generating assets until detailed analyses of the potential for market power abuses by utilities have been performed. In addition, the BPU indicated its belief that it is necessary to have a fully independent and operating ISO prior to the implementation of customer choice. The BPU proposed that retail competition in New Jersey be introduced approximately 12 to 18 months after the implementation of full wholesale competition as provided by FERC Order No. 888.
Customer protections will include: maintaining the electric utility as a universal service or "basic generation service" provider; continued funding of social programs now provided by electric utilities; registration of all third party power suppliers with the BPU; establishment of standards of conduct for third party power suppliers; and continued funding for energy efficiency programs.
Utilities will have an opportunity for a limited number of years to recover through rates stranded costs associated with generating capacity investment and independent power contract costs made prior to the advent of competition. Utilities are obligated to take all reasonably available measures to mitigate stranded costs caused by the introduction of retail competition. A market transition charge is to be established for a limited time of 4-8 years to provide for the recovery of non-mitigated stranded costs and would be a separate component of a customer's electric bill.
The issue of securitization of stranded costs is to be explored.
There is a need for Federal action in a number of areas as an integral part of electric restructuring. Of particular concern is the transport of nitrogen oxides (NOx) and other pollutants to New Jersey from power plants located in the Midwest and Southeast.
Near-term rate reductions in retail electric rates of 5-10% are required.
A rate unbundling plan, stranded cost status report and restructuring plan to be filed by each utility by July 15, 1997.
The final Phase II report endorsed environmental disclosure by power suppliers to provide consumers with information necessary to choose cleaner sources of power available in the marketplace. The information will enable verification of claimed emission rates, which will be explored by a Consumer Protection Task Force.
PSE&G's proposal in response to the final Phase II report of the Energy Master Plan included the following key elements:
A rate decrease of between 5% and 10%, effective January 1, 1999, dependent upon BPU approval of several key elements of the proposal.
Allowing all customers in all classes to register for their choice of energy supplier beginning October 1, 1998. Those customers choosing a supplier other than PSE&G would be permitted to switch effective January 1, 1999.
A transition period of seven years with basic tariff rates capped during that period. During the transition period, PSE&G would maintain responsibility for system reliability of energy and capacity supply.
Recovery of transition costs through asset securitization, restructuring of certain non-utility generation contracts and depreciation accounting changes (see Stranded Costs, Securitization and Depreciation below).
Recovery of mandated societal costs, such as nuclear decommissioning and Demand Side Management (DSM), would be adjusted based on changes in these costs.
Discontinuation of PSE&G's LEAC effective December 31, 1998. PSE&G would be responsible for all risks associated with fuel prices, changes in operation and maintenance expenses and mitigation of the transition costs of non-securitized generation production assets within the price capped rates.
Transfer of PSE&G's nuclear and fossil generation assets, at net book value, to a separate entity functionally independent of PSE&G at the conclusion of the transition period.
PSE&G would file a rate case or a plan for a form of alternative regulation for its electric distribution delivery service functions one year prior to the end of the transition period.
At the end of the transition period, responsibility for generation reliability would shift to the marketplace and PSE&G would retain its obligation to connect and deliver energy and would offer basic generation service.
Pursuant to actions taken by the BPU under its Energy Master Plan proceeding, various BPU-sponsored working groups have been created to address and recommend solutions regarding certain issues regarding restructuring. PSE&G is participating in these working groups including the Consumer Protection Task Force, Phase-In Mechanisms Working Group, Customer Services Working Group and DSM and Renewables Working Group. In addition, PSE&G is participating in BPU proceedings dealing with certain generic issues, including exit fees, market power, affiliate relationships, mechanics of customer phase-in and fair competition. The working groups and the generic issues proceedings are running concurrently with the Energy Master Plan proceedings.
In an Order dated June 25, 1997, the BPU commenced management audits of all New Jersey electric utilities, with the assistance of one or more consulting firms, under the direction of its own audit staff. The audit process included, but was not limited to, focused reviews of electric utility filings in response to the Energy Master Plan. The management audit process for PSE&G was concluded in December 1997 with a report filed by the management consulting firms which performed the audit on behalf of the BPU. A second report on restructuring is yet to be filed. The audit report, which was approved by the BPU on January 29, 1998, among other things:
Supported a consumer rate reduction target of 8.4% to 11.7% and the use of an energy and capacity credit mechanism on customers' bills.
Substantiated $2.9 billion of PSE&G's $3.9 billion stranded cost estimate, challenging certain assumptions as well as $230 million of capital additions incurred since 1992.
Agreed with the use of securitization as a means of financing stranded costs in order to obtain rate reductions, recommending $2.2 billion (compared to the $2.5 billion requested by PSE&G) of securitization.
Noted that an incentive or true-up mechanism may be appropriate to reduce the risk of significant overrecovery of stranded costs given the uncertainty surrounding load, market prices and the potential for mitigation.
The BPU can adopt, reject or modify the audit report's results in its decision on PSE&G's proposal. PSE&G cannot predict to what extent the BPU will rely on the results of the audit report nor what the ultimate outcome of the Energy Master Plan proceedings will be. The decision of the BPU in the Energy Master Plan proceeding and the legislation to be adopted by the New Jersey Legislature required to implement certain aspects of electric restructuring in the State will establish the industry rules for the future. These actions are expected to fundamentally change the electric industry in the State by introducing retail competition to replace the utilities' former monopoly position and potentially requiring or resulting in the separation or sale of generation assets. Depending upon the outcome of these proceedings, these fundamental industry changes could have a material adverse effect on Enterprise's and PSE&G's financial condition, results of operations and net cash flows. Enterprise and PSE&G cannot predict the outcome of this matter.
Stranded Costs
Stranded costs represent the portion of the book value of generation related assets or the portion of payments under power purchase contracts which are in excess of their value in a competitive deregulated marketplace. PSE&G has identified its potentially stranded costs associated with fossil and nuclear generating stations at $3.9 billion, based on certain assumptions, including future market prices of electricity and performance of generating units. Changes in these assumptions could materially alter the estimated amount of potentially stranded costs.
Recoverability of these costs is largely dependent on the transition rules to be established by regulators. PSE&G has proposed to securitize $2.5 billion of these costs, with the remainder to be mitigated through cost saving measures during a transition period of seven years. In addition, PSE&G is seeking to restructure certain of its BPU approved contracts with Non-utility Generators (NUGs), which are estimated to be $1.6 billion above assumed future market prices. As presently proposed, the Energy Master Plan would allow recovery of these restructuring costs in rates. Since the Energy Master Plan proceeding is still in progress, the issue of securitization and the extent of its application have not been determined; and recognizing the potential need for legislative action, management cannot predict the extent to which regulators will allow recovery of such costs. As noted above, the management audit report identified $2.9 billion of stranded costs as compared to the $3.9 billion estimated by PSE&G. The decision of the BPU in this matter could have a material adverse effect on Enterprise's and PSE&G's financial condition, results of operations and net cash flows.
Securitization
In its Energy Master Plan proposal, PSE&G has proposed to securitize $2.5 billion of its potentially stranded costs through the issuance of transition bonds with an estimated term of 15 years. Securitization is a method of refinancing potentially stranded costs with lower cost debt. The credit quality of the debt would be enhanced via enabling State legislation and approval by the BPU of an irrevocable, non-bypassable charge to service the interest and principal payments on the debt. The use of securitization as a means to reduce rates depends on enabling legislation, which the New Jersey Legislature is not expected to consider prior to the second quarter of 1998. If legislative approval is not granted, PSE&G will alter its Energy Master Plan proposal and projected rate reduction range. Since the Energy Master Plan proceeding is still in progress, the issue of securitization and the extent of its application have not been determined; and recognizing the potential need for legislative action, management cannot predict the extent to which regulators will allow the use of such securitization for recovery of stranded costs. As noted above, the management audit report recommended $2.2 billion of securitization. The decision of the BPU and/or the related legislative action required in this matter could have a material adverse effect on Enterprise's and PSE&G's financial condition, results of operations and net cash flows.
Depreciation
In its Energy Master Plan proposal, PSE&G has proposed to lengthen the depreciable lives of its electric distribution assets from 28 to 45 years. These assets are expected to remain regulated. The excess depreciation reserve, calculated based on this change in depreciable lives, would be amortized over a seven year transition period. If PSE&G's plan is adopted as proposed, it would result in a reduction of annual depreciation expense of $116 million during such transition period and $35 million thereafter over the remaining life of these assets.
Settlement of Certain Regulatory Issues
By Order dated December 31, 1996 (December 31st Order), the BPU approved a settlement among PSE&G, the staff of the BPU (Staff) and the New Jersey Division of Ratepayer Advocate (Ratepayer Advocate) addressing (1) the cost impact of the 1995 shutdown of Salem Nuclear Generating Station (Salem) Units 1 and 2 (Salem 1 and 2), including the "used and useful" issue related to the units through December 31, 1998; (2) the recovery of certain replacement power costs associated with the 1994 Salem 1 outage; and (3) the recovery of capacity costs associated with PSE&G's power purchases from cogeneration producers through December 31, 1998. Under the December 31st Order, PSE&G recorded a charge of $83.9 million for bill credits to electric customers who received credits in January and February 1997. PSE&G also agreed to forego recovery of $12 million associated with energy costs that previously had been deferred. The resulting after-tax earnings loss of $62 million or 26 cents per share of Enterprise Common Stock was previously recorded ($59 million or 25 cents per share in the third quarter of 1996 and $3 million or 1 cent per share in 1995).
Under the terms of the December 31st Order, Salem 1 and 2 will continue in base rates without being subject to further refund and PSE&G will assume all nuclear and fossil generating fuel and performance risks, including replacement power costs associated with the Salem, Hope Creek Generating Station (Hope Creek) and Peach Bottom Atomic Power Station (Peach Bottom) nuclear stations from January 1, 1997 through December 31, 1998. The BPU's nuclear performance standard (NPS) will not apply to PSE&G from January 1, 1996 through December 31, 1998 (see Note 10. Commitments and Contingent Liabilities). In addition, the energy component of PSE&G's LEAC was fixed at its existing level with no increase to customers until at least January 1999 (see Electric Levelized Energy Adjustment Clause/Demand Side Adjustment Factor below) with PSE&G responsible for all risks associated with fuel prices. Any underrecovered or overrecovered LEAC balance existing on December 31, 1998 will not be considered in any LEAC review subsequent to that date. Any overrecovery at that date will be applied to reduce any potential stranded costs and any underrecovered balance will be charged to income in the period identified.
The December 31st Order provides PSE&G the opportunity, but no guarantee, during the period January 1, 1997 through December 31, 1998, to fully recover the December 31, 1996 underrecovered LEAC energy balance of $151 million ($91 million as of December 31, 1997) without any change in the current energy component of the LEAC charge. Management believes that it will fully recover the underrecovered LEAC balance by December 31, 1998 and will continue to follow deferred accounting treatment for the LEAC (see discussion of the Energy Master Plan above).
In addition to the resolution of the Salem "used and useful" issue, the December 31st Order addressed two other separate long standing issues that PSE&G had been litigating before the BPU. The first pertains to the recovery of certain replacement power costs associated with a 58 day outage at Salem 1 in 1994. The December 31st Order required PSE&G to reduce its underrecovered LEAC balance by $7 million related to that outage. The second pertains to the recovery of capacity costs associated with electric utility power purchases from cogeneration producers through December 31, 1998. The December 31st Order required PSE&G to provide bill credits to electric customers totaling $6.4 million during January and February 1997. In addition, PSE&G reduced its underrecovered LEAC balance by $5 million related to the recovery of capacity costs.
Through separate letter agreements, PSE&G and the Ratepayer Advocate agreed on a commitment by PSE&G to provide financial assistance toward economic growth and development in New Jersey. This commitment, which runs through December 31, 1999, has four key elements. First, PSE&G created a $30 million revolving economic development fund with emphasis on stimulating jobs and developing high technology projects in urban areas. Second, PSE&G will continue to provide incentives to encourage local public housing authorities to replace up to 4,000 refrigerators a year. Third, PSE&G committed $1 million to develop a fund to provide innovative assistance to low income residents who are having difficulty paying energy bills. Finally, PSE&G will develop a computer system to assist low income residents in identifying government and community programs from which they would be eligible to receive benefits.
On February 24, 1997, an Intervenor's group filed an appeal in New Jersey Superior Court seeking an invalidation of the December 31st Order. Notices of Dismissal of Appeal were filed by the Intervenor's group on August 1, 1997 with the Superior Court of New Jersey, Appellate Division.
Levelized Gas Adjustment Clause (LGAC)
In November 1996, the BPU approved an approximate $80 million increase based upon a modified Interim Stipulation in the LGAC proceeding. The monthly pricing methodology for Large Volume Gas (LVG) and General Service Gas (GSG) customers, with minor modifications, will continue. During the months of December 1996 and January 1997, approximately $14 million was refunded through bill credits to customers that purchased LVG or GSG service (excluding off-peak service) during the period January 1, 1996 through October 31, 1996. The refund was based on an over collection of gas costs from those customer classes and was apportioned based on those customers' billed usage during that period. On April 2, 1997, the BPU approved PSE&G's LGAC stipulation. The interim residential LGAC charge, approved in November 1996, continued through December 31, 1997.
On July 30, 1997, the BPU authorized PSE&G to hedge or lock-in up to 50% of its residential natural gas portfolio, which may be accomplished using either physical or financial hedging mechanisms, beginning with the 1997-1998 heating season. Such hedges are intended to provide price stability for residential customers (see Note 8. Financial Instruments).
On November 14, 1997, PSE&G filed its 1997/98 LGAC petition with the BPU requesting a $45 million increase on an annual basis in its LGAC for the period January 1, 1998 to December 31, 1998. This increase, as filed, amounts to approximately 4.8% on a typical residential bill. Public hearings were held on February 3, 1998. On February 18, 1998, the BPU approved a Stipulation agreed to by the parties in the proceeding. The Stipulation provides for an interim increase in LGAC revenues of approximately $31 million, excluding State sales and use tax. This represents an increase of 3.5% on a typical residential bill. The parties will continue to litigate and PSE&G cannot predict the final outcome of this proceeding.
Electric Levelized Energy Adjustment Clause (LEAC)/Demand Side Adjustment Factor (DSAF)
As discussed above, the December 31st Order has fixed the energy component of the LEAC as of December 31, 1996 (see Settlement of Certain Regulatory Issues). Additionally, under PSE&G's Energy Master Plan proposal, if approved, the LEAC would be discontinued. Certain components of the LEAC would become part of the societal benefits clause under PSE&G's proposal. No assurances can be given as to the outcome of the Energy Master Plan proceedings.
On February 24, 1997, PSE&G filed with the BPU for an increase in the DSAF component of the LEAC, to become effective on or before May 1, 1997. The filing was to be effective for the period from May 1997 through December 1998 and requested an annualized increase of $151.8 million. The filing included recovery of demand side management (DSM)/conservation costs related to BPU approved programs and would raise rates to a level sufficient to recover such costs incurred through December 31, 1998. At December 31, 1997, PSE&G had an underrecovered balance, including interest, of approximately $122 million related to these programs. Such amount is included in Deferred Debits on PSE&G's balance sheet.
A hearing was held before the Office of Administrative Law (OAL) in September 1997 and on December 5, 1997, the Administrative Law Judge recommended in his initial decision that the BPU approve $150.1 million of the $151.8 million requested. On January 19, 1998, the BPU extended its period of review to accept, reject or modify the Judge's decision. Approval of this filing by the BPU would result in recovery of this balance, as well as the costs of these programs through 2000. PSE&G cannot predict the outcome of this matter.
Remediation Adjustment Charge (RAC)
In 1992, the BPU approved a mechanism for recovery of PSE&G's costs associated with its Manufactured Gas Plant Remediation Program (Remediation Program) allowing the recovery of actual costs plus carrying charges, net of insurance recoveries, over a seven-year period through PSE&G's LGAC and LEAC, with 60% charged to gas customers and 40% charged to electric customers. In November 1996, the BPU approved an Interim LGAC Stipulation regarding costs incurred during the period August 1, 1995 through July 31, 1996. On July 30, 1997, the BPU approved the recovery of remediation program costs incurred during the period August 1, 1995 through July 31, 1996 on a final basis.
On August 1, 1997, PSE&G requested that the BPU approve recovery of $6.8 million through PSE&G's RAC for manufactured gas plant remediation costs. This represents an increase in the amount of PSE&G's recovery of such costs by approximately $2 million over current rate levels. On October 9, 1997, this matter was transferred to the OAL. PSE&G cannot predict the outcome of this proceeding.
Consolidated Tax Benefits
In a case affecting another utility in which neither Enterprise nor PSE&G were parties, the BPU considered the extent to which tax savings generated by non-utility affiliates included in the consolidated tax return of that utility's holding company should be considered in setting that utility's rates. In 1992, the BPU approved an order in such case treating certain consolidated tax savings generated after June 30, 1990 by that utility's non-utility affiliates as a reduction of its rate base. Also in 1992, the BPU issued an order resolving PSE&G's 1992 base rate proceeding without separate quantification of the consolidated tax issue. Such order did not provide final resolution of the consolidated tax issue for any subsequent base rate filing. While Enterprise continues to account for its two wholly-owned subsidiaries on a stand-alone basis, resulting in a realization of tax benefits by the entity generating the benefit, an ultimate unfavorable resolution of the consolidated tax issue could reduce PSE&G's and Enterprise's revenues, net income or net cash flows. In addition, an unfavorable resolution may adversely impact Enterprise's non-utility investment strategy. Enterprise believes that PSE&G's taxes should be treated on a stand-alone basis for rate-making purposes, based on the separate nature of the utility and non-utility businesses. The issue of Enterprise sharing the benefits of consolidated tax savings with PSE&G or its ratepayers was addressed by the BPU in its July 28, 1996 letter which informed PSE&G that the issue of consolidated tax savings can be discussed in the context of PSE&G's next base rate case or plan for an alternative form of regulation. However, neither Enterprise nor PSE&G is able to predict what action, if any, the BPU may take concerning consolidation of tax benefits in future rate proceedings (see Note 12. Federal Income Taxes).
Postretirement Benefits Other Than Pensions (OPEB)
In August 1996, the BPU initiated a generic proceeding to resolve the regulatory and rate issues associated with SFAS 106. On January 8, 1997, the BPU issued its Order adopting a stipulation of the parties to the proceeding regarding SFAS 106 cost recovery mechanisms and initiating a second phase of the generic proceeding requiring each utility's individual filing to obtain SFAS 106 accrual rate recognition under one of the rate mechanisms established in the BPU Order (see Note 3. Regulatory Assets and Liabilities and Note 14. Postretirement Benefits Other Than Pensions).
Other Rate Matters
Interim Competitive Transition Charge (ICTC)
In September 1996, PSE&G filed a petition with the BPU to establish an ICTC which is designed to recover stranded costs which will result from a customer leaving PSE&G's system as a full requirements customer. If approved by the BPU as filed, this charge would apply to customers who, after September 19, 1996, commit to an alternate source of electric power while remaining physically located in PSE&G's electric franchise area. On April 24, 1997, the BPU issued a generic order to investigate policy issues related to whether customers who cease to receive electric service from a utility and go to on-site generation should be charged an exit fee. PSE&G's petition and motions concerning its September 1996 ICTC filing have been placed in abeyance pending the conclusion of the separate generic proceeding on this issue. The generic ICTC matter continues to be reviewed by the BPU. PSE&G cannot predict the outcome of this proceeding.
Gas Unbundling
PSE&G's unbundled gas transportation tariffs, which have been in place since 1994, allow any nonresidential customer, regardless of size, to purchase its own gas, transport it to PSE&G pipelines and require PSE&G to deliver such gas to the customer's facility. To date, approximately 17,000 commercial and industrial customers, of approximately 180,000 such customers eligible, have elected to utilize this service. It is expected that this number will not significantly increase with the changes in the law affecting the gross receipts and franchise tax which became effective on January 1, 1998. Those changes now apply sales tax to sales by marketers, putting a similar tax burden on them as borne by PSE&G (see NJGRT Reform below).
Current transportation rate schedules produce the same non-fuel revenue per therm as existing sales tariff rate schedules. Thus, to date, PSE&G's earnings have been unaffected by whether the customers remain on sales tariffs or convert to transportation service. Enterprise's indirect subsidiary, Energis, provides non-utility gas marketing services operating in New Jersey and several other states.
In April 1997, the BPU approved PSE&G's proposal for a residential gas unbundling pilot program known as SelectGas. The pilot program allows 65,000 residential natural gas customers to participate in the competitive marketplace. To date, of the 65,000 eligible customers, none has subscribed to the program. PSE&G cannot predict the future impact of this program on its financial condition, results of operations and net cash flows.
PSE&G also participates in a retail pilot program of the New Jersey Natural Gas Company (New Jersey Natural) to provide unbundled gas transportation to former residential customers of New Jersey Natural. PSE&G has enrolled over 1,300 former residential gas customers of New Jersey Natural.
New Jersey Gross Receipts and Franchise Tax (NJGRT) Reform
On July 14, 1997, Governor Whitman signed legislation eliminating the NJGRT, effective January 1, 1998. This legislation replaces the NJGRT with a combination of the corporate business tax, the State sales and use tax and a Transitional Energy Facility Assessment (TEFA). The TEFA will be phased out over five years. While PSE&G was subject to approximately 13% tax under the NJGRT, after the phase out of the TEFA, the tax rate will be substantially reduced. The new tax structure is expected to improve the competitive position of PSE&G vis-a-vis non-utility energy providers in New Jersey who were not subject to the NJGRT. On September 15, November 18 and December 24, 1997, PSE&G filed revised tariff schedules and other pertinent information, in compliance with the legislation. On December 31, 1997, the BPU accepted PSE&G's filings with revisions for the purpose of implementing interim rates with regard to the new tax structure effective with service rendered on and after January 1, 1998. The BPU continues its administrative review of the filings of all utilities and is expected to approve permanent rates no later than April 1, 1998.
Note 3. Regulatory Assets and Liabilities
Regulatory assets and liabilities are recorded in accordance with the provisions of SFAS 71 (see Note 1. Organization and Summary of Significant Accounting Policies and Note 2. Rate Matters). At December 31, 1997 and 1996, PSE&G had deferred the following regulatory assets on the Consolidated Balance Sheet:
December 31, --------------------- 1997 1996 ------ ------- (Millions of Dollars) Unamortized Debt Expense............................ $135 $138 Deferred OPEB Costs................................. 289 226 Unrecovered Environmental Costs..................... 122 126 Underrecovered Electric Energy and Gas Costs........ 167 176 Unrecovered SFAS 109 Income Taxes................... 725 752 Deferred Demand Side Management Costs............... 116 40 Deferred Decontamination and Decommissioning Costs.. 43 47 Property Abandonments............................... 37 52 Unrecovered Plant and Regulatory Study Costs........ 34 34 Oil and Gas Property Write-Down..................... 26 31 ------ ------ Total Regulatory Assets......................... $1,694 $1,622 ====== ======
Unamortized Debt Expense: Represents bond issuance costs, premiums, discounts and losses on reacquired long-term debt. Bond issuance costs and associated premiums and discounts are generally amortized over the life of the debt issuance. In accordance with FERC regulations, costs to reacquire debt are amortized over the remaining original life of the retired debt. When refinancing debt, the unamortized portion of the original debt issuance costs of the debt being retired must be amortized over the life of the replacement debt.
Deferred OPEB Costs: Includes costs associated with adoption of SFAS 106 which are deferred in accordance with EITF Issue 92-12. For a discussion of OPEB Costs, see Note 14. Postretirement Benefits Other Than Pensions and Note 2. Rate Matters.
Unrecovered Environmental Costs: Represents environmental costs which are probable of recovery in future rates. For discussion of unrecovered environmental costs, see Note 2. Rate Matters.
Underrecovered Electric Energy and Gas Costs: Recoveries of electric energy and gas costs are determined by the BPU under the LEAC and LGAC. PSE&G's deferred fuel balances as of December 31, 1997 and 1996 reflect underrecovered costs as follows: December 31, ------------------- 1997 1996 ---- ---- (Millions of Dollars) Underrecovered Electric Energy Costs............. $91 $151 Underrecovered Gas Fuel Costs.................... 76 25 ---- ---- Total.......................................... $167 $176 ==== ====
PSE&G has the opportunity, but no guarantee, during the period January 1, 1997 through December 31, 1998, to fully recover its December 31, 1996 underrecovered LEAC balance of $151 million without any change in the current energy component of the LEAC charge. Management believes that it will recover this amount by December 31, 1998 and continues to follow deferred accounting treatment for the LEAC. For additional discussion, see Note 2. Rate Matters.
Unrecovered SFAS 109 Income Taxes: Represents regulatory asset related to the implementation of SFAS 109, "Accounting for Income Taxes" in 1993 (see Note 12. Federal Income Taxes).
Deferred Demand Side Management Costs: Recoveries of DSM/conservation costs (related to BPU-approved programs) are determined by the BPU. PSE&G's deferred DSM balance as of December 31, 1997 and 1996, respectively, reflects underrecovered/(overrecovered) costs as follows: December 31, ------------------- 1997 1996 ---- ---- (Millions of Dollars) Deferred DSM (Including Interest)--Electric.......... $122 $45 Deferred DSM (Including Interest)--Gas............... (6) (5) ---- ---- Total.............................................. $116 $40 ==== ====
The increase in the electric balance is primarily due to the ongoing underrecovery of DSM costs. In February 1997, PSE&G filed for an increase in the DSAF, which is a component of the LEAC. Approval of the filing would result in recovery of the existing deferred DSM balance as well as the estimated costs of these programs through December 1998 (see Note 2. Rate Matters).
Deferred Decontamination and Decommissioning Costs: Represents amounts related to decontamination and decommissioning which are probable of recovery in future rates. For discussion of decontamination and decommissioning costs, see Note 11. PSE&G Nuclear Decommissioning.
Property Abandonments: The BPU has authorized PSE&G to recover after-tax property abandonment costs from its customers. The table of Regulatory Assets above reflects property abandonments, and related tax effects, for which no return is earned. The net-of-tax discount rate used was between 4.868% and 5.292%.
Unrecovered Plant and Regulatory Study Costs: Amounts shown in the consolidated balance sheets consist of costs associated with developing, consolidating and documenting the specific design basis of PSE&G's jointly owned nuclear generating stations, as well as PSE&G's share of costs associated with the cancellation of the Hydrogen Water Chemistry System Project (HWCS Project) at Peach Bottom. PSE&G has received both BPU and FERC approval to defer and amortize, over the remaining lives of the Salem, Hope Creek and Peach Bottom nuclear units, costs associated with configuration baseline documentation and the canceled HWCS Project.
Oil and Gas Property Write-Down: On December 31, 1992, the BPU approved the recovery of PSE&G's deferral of an EDC write-down through PSE&G's LGAC over a ten-year period beginning January 1, 1993.
Note 4. Long-Term Investments
Long-Term Investments are primarily those of EDHI.
December 31, ----------------------- 1997 1996 ----------- ----------- (Millions of Dollars) Lease Agreements (see Note 5. Leasing Activities): Leveraged Leases......................... $1,143 $932 Direct-Financing Leases.................. 2 33 Other Leases............................. 2 3 ----------- ----------- Total................................ 1,147 968 ----------- ----------- Partnerships: General Partnerships..................... 142 138 Limited Partnerships..................... 534 495 ----------- ----------- Total................................ 676 633 ----------- -----------
Corporate Joint Ventures..................... 885 75 Securities................................... 28 48 Other Investments............................ 137 130 ----------- ----------- Total Long-Term Investments.......... $2,873 $1,854 =========== ===========
PSRC's 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 PSRC, EGDC and CEA.
Other Investments, above, relate primarily to Public Service Conservation Resources Corporation (PSCRC), a wholly-owned subsidiary of PSE&G. PSCRC's investment in DSM projects had balances at December 31, 1997 and 1996 of approximately $84 million and $98 million, respectively.
Note 5. Leasing Activities
As Lessor
PSRC's net investments in leveraged and direct financing leases are composed of the following elements:
PSRC's other capital leases are with various regional, state and city authorities for transportation equipment and aggregated $2 million and $3 million as of December 31, 1997 and 1996, respectively.
As Lessee
The Consolidated Balance Sheets include assets and related obligations applicable to capital leases under which PSE&G 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 and other capital equipment. Certain of the leases contain renewal and purchase options as well as escalation clauses. Enterprise and its other subsidiaries are not lessees in any capitalized leases.
Utility plant includes $52 million for capital leases net of accumulated amortization at December 31, 1997 and 1996. Rent expense included in Operating Expenses for 1997, 1996 and 1995 was $34 million, $32 million and $34 million, respectively.
Note 6. Schedule of Consolidated Capital Stock and Other Securities
(A) PSE&G's Mortgage, securing the Bonds, constitutes a direct first mortgage lien on substantially all PSE&G's property and franchises.
During the year, PSE&G reacquired on the open market $117 million of its 8.50% Series LL First and Refunding Mortgage Bonds (Bonds). In April 1997, PSE&G issued $25 million of Variable Rate Pollution Control Bonds, Series X, due 2031. In June 1997, PSE&G issued $235 million of its 6.50% Series XX Bonds due 2000 and in November 1997, PSE&G issued $9 million of 7.04% Medium Term Notes. Also in November 1997, PSE&G redeemed $9 million of its 9.25% Series CC Bonds.
(B) PSE&G issued $19 million of Variable Rate Pollution Control Notes due 2027 in June 1997.
(C) For information concerning fair value of financial instruments, see Note 8. Financial Instruments.
(D) The aggregate principal amounts of mandatory requirements for sinking funds and maturities for each of the five years following December 31, 1997 are as follows:
(E) At December 31, 1997 and 1996, PSE&G's annual interest requirement on long-term debt was $291 million and $317 million, of which $283 million and $302 million, respectively, was the requirement for Bonds. The embedded interest cost on long-term debt on such dates was 7.44% and 7.45%, respectively. The embedded interest cost on long-term debt due within one year at December 31, 1997 was 7.14%.
(F) Capital has provided up to $750 million debt financing for EDHI's businesses, except Energis, on the basis of a net worth maintenance agreement with Enterprise. Effective January 31, 1995, Capital has limited its borrowings to no more than $650 million.
(G) Funding provides debt financing for PSRC, CEA and their subsidiaries on the basis of an unconditional guarantee from EDHI.
(H) At December 31, 1997 and 1996, the annual interest requirement on long-term debt was $378 million and $370 million, of which $283 million and $302 million, respectively, was the requirement for Bonds. The embedded interest cost on long-term debt on such dates was 7.64% and 7.62%, respectively.
SHORT-TERM (Commercial Paper and Bank Loans)
Commercial paper represents unsecured bearer promissory notes sold through dealers at a discount with a term of nine months or less.
Bank loans represent PSE&G's unsecured promissory notes issued under informal credit arrangements with various banks and have a term of eleven months or less.
ENTERPRISE
At December 31, 1997, Enterprise had a committed $150 million revolving credit facility which expires in December 2002. At December 31, 1997 and 1996, Enterprise had a $75 million and a $25 million uncommitted line of credit, respectively, with a bank. At December 31, 1997, Enterprise had $75 million outstanding under this line of credit with an interest rate of 6.2%. The consolidated weighted-average, short-term debt rate of Enterprise was 6.2%, 5.7% and 6.0% for the years ended December 31, 1997, 1996 and 1995, respectively.
PSE&G
PSE&G has authorization from the BPU to issue and have outstanding not more than $1.3 billion of its short-term obligations at any one time, consisting of commercial paper and other unsecured borrowings from banks and other lenders. This authorization expires January 2, 1999.
The $1.3 billion commercial paper program (Program) is supported by a $650 million revolving credit agreement expiring in June 1998 and a $650 million revolving credit agreement expiring in June 2002 with a group of commercial banks. As of December 31, 1997 and 1996, PSE&G had $952 million and $443 million, respectively, outstanding under the Program, which amounts are included in the table above. As of December 31, 1997, there was no debt outstanding under the revolving credit agreements.
PSE&G has $174 million in uncommitted lines of credit facilities extended by a number of banks to primarily support short-term borrowings, of which $74 million was outstanding on December 31, 1997 and is included in the table above.
PSE&G had various lines of credit facilities extended by banks to primarily support the issuance of letters of credit. As of December 31, 1997, letters of credit were issued in the amount of $21 million.
PSE&G Fuel Corporation (Fuelco) has a $125 million commercial paper program to finance a 42.49% share of Peach Bottom nuclear fuel, supported by a $125 million revolving credit facility with a group of banks, which expires on June 28, 2001. PSE&G has guaranteed repayment of Fuelco's respective obligations. As of December 31, 1997 and 1996, Fuelco had commercial paper of $80 million and $83 million, respectively, outstanding under the commercial paper program, which amounts are included in the table above. As of December 31, 1997, there was no debt outstanding under the revolving credit facility.
PSE&G has entered into standby financing arrangements with banks totaling $124 million. These facilities support long-term tax-exempt multi-mode mortgage bond financings done through the New Jersey Economic Development Authority, The Pollution Control Financing Authority of Salem County (New Jersey), the York County (Pennsylvania) Industrial Development Authority and the Indiana County (Pennsylvania) Industrial Development Authority. As of December 31, 1997, no amounts were outstanding under such arrangements.
EDHI
On July 31, 1996, Funding amended and restated its commercial paper program and revolving credit facility in conjunction with the sale of EDC, reducing the total amount from $450 million to $300 million and extending the maturity from March 1998 to July 1999. In November 1997, Funding entered into an additional $150 million revolving credit agreement with a group of banks. Such agreement terminates in November 1998.
Note 8. Financial Instruments
Fair Value of Financial Instruments
The estimated fair value was determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions at the end of 1997 and 1996, respectively.
Natural Gas Hedging--EDHI
As of December 31, 1997 and 1996, Energis had outstanding futures contracts to buy natural gas related to fixed-price natural gas sales commitments. Such contracts hedged approximately 97% and 95% of its fixed price sales commitments at December 31, 1997 and 1996, respectively. As of December 31, 1997, Energis had a net unrealized hedge loss of $2 million and as of December 31, 1996, Energis had a net unrealized hedge gain of $4 million.
Nuclear Decommissioning Trust Funds
Contributions made into the Nuclear Decommissioning Trust Funds are invested in debt and equity securities. The carrying value of these funds approximates the fair market value of $458 million and $375 million as of December 31, 1997 and 1996, respectively.
Equity Securities--EDHI
PSRC has investments in equity securities and partnerships which invest in equity securities. The aggregate carrying value approximates the fair market value of $185 million and $131 million as of December 31, 1997 and 1996, respectively.
Note 9. Cash and Cash Equivalents
The December 31, 1997 and 1996 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.
Note 10. Commitments and Contingent Liabilities
Nuclear Performance Standard (NPS)
The BPU has established its NPS for nuclear generating stations owned by New Jersey electric utilities, including the five nuclear units in which PSE&G has an ownership interest. Under the NPS, an aggregate capacity factor is calculated annually using maximum dependable capability of each of the five nuclear units. This method takes into account actual operating conditions of the units. Failure to attain a satisfactory capacity factor percentage results in penalties.
While the NPS does not specifically have a gross negligence provision, the BPU has indicated that it would consider allegations of gross negligence brought upon a sufficient factual basis. A finding of gross negligence could result in penalties other than those prescribed under the NPS. The December 31st Order provides that the NPS will not apply to PSE&G for the period January 1, 1996 through December 31, 1998 (see Note 2. Rate Matters).
Nuclear Insurance Coverages and Assessments
PSE&G's insurance coverages and maximum retrospective assessments for its nuclear operations are as follows:
PSE&G Maximum Total Assessments Site for a Single Type and Source of Coverages Coverages Incident - ---------------------------- --------- ------------- (Millions of Dollars) Public Liability (Primary Layer): American Nuclear Insurers....................... $ 200.0 N/A Nuclear Liability (Excess Layer): Price-Anderson Act.............................. 8,720.3 (A) $210.2 -------- ------ Nuclear Liability Total..................... $8,920.3 (B) $210.2 ======== ====== Nuclear Worker Liability (Primary Layer): American Nuclear Insurers....................... $200.0 (C) $8.0
Property Damage (Primary Layer): American Nuclear Insurers (Peach Bottom)........ $500.0 N/A Nuclear Mutual Limited (Salem/Hope Creek)....... 500.0 $9.7 Property Damage (Excess Layer): Nuclear Electric Insurance Limited (NEIL II).... 2,250.0 13.7 -------- ----- Property Damage Total (Per Site)............ $2,750.0 $23.4 ======== =====
Replacement Power: Nuclear Mutual Limited (NML).................... $21.0 (D) N/A Nuclear Electric Insurance Limited (NEIL I)..... 473.2 (E) $11.3 ------ ----- Replacement Power Total (Salem/Hope Creek).. $494.2 (F) $11.3 ====== =====
(A) Retrospective premium program under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. PSE&G 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, 1993. This retrospective program is excess over the Public and Nuclear Worker Liability primary layers.
(B) Limit of liability under the Price-Anderson Act for each nuclear incident.
(C) Industry aggregate limit representing the potential liability from workers claiming exposure to the hazard of nuclear radiation. This policy includes automatic reinstatements up to an aggregate of $200 million, thereby providing total coverage of $400 million.
(D) After a waiting period, NML insured sites may receive a weekly indemnity of $3.5 million for six weeks.
(E) Aggregate indemnity limit for a weekly indemnity of $3.5 million for 52 weeks followed by 80% of the weekly indemnity for 104 weeks. Also, represents limit of coverage for Peach Bottom which does not purchase insurance from NML.
(F) Combined aggregate limit of NML and NEIL I coverages available to co-owners of Salem and Hope Creek for each plant. Of this limit, PSE&G is covered for its percent ownership in each plant.
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 $8.9 billion. All utilities owning a nuclear reactor, including PSE&G, 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 $79.3 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. PSE&G's maximum aggregate assessment per incident is $210.2 million (based on PSE&G's ownership interests in Hope Creek, Peach Bottom and Salem) and its maximum aggregate annual assessment per incident is $26.5 million. This does not include the $8.0 million that could be assessed under the nuclear worker policies.
Further, a recent decision by the U.S. Supreme Court, not involving PSE&G, held that the Price-Anderson Act did not preclude awards based on state law claims for punitive damage.
PSE&G is a member of an industry mutual insurance company, NEIL, which, as of January 1, 1998, was consolidated with NML. NEIL provides all the coverages formerly provided by NML, including the primary property insurance at Salem and Hope Creek. Also, NEIL continues to provide excess property insurance through its NEIL II policy and replacement power coverage through its NEIL I policy. Both NEIL and NML policies may make retrospective premium assessments in case of adverse loss experience. PSE&G'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.
Settlement of Salem Litigation
On May 12, 1997, PSE&G settled the lawsuit brought against it by PECO Energy Company (PECO Energy) and Delmarva Power & Light Company (DP&L), two co-owners of the Salem Units, related to alleged damages resulting from the outage of the facility. This settlement, which totaled $82 million, resulted in an after-tax charge to earnings, recorded in the first quarter of 1997, of $53 million or $0.23 per share of Enterprise Common Stock and was paid in December 1997. This settlement also obligates PSE&G to pay $1.4 million for each reactor month that the outage continues beyond an aggregate outage of 64 reactor months, up to a maximum payment under this provision of $17 million. As of January 31, 1998, an aggregate of 59 reactor months had accumulated due to Salem outages. PSE&G does not expect to make any payments under this provision. Salem 2 returned to service on August 30, 1997. Salem 1 is expected to return to service around the end of the first quarter of 1998.
PECO Energy, DP&L and PSE&G have also agreed to an operating performance standard through December 31, 2011 for Salem and through December 31, 2007 for Peach Bottom which is operated by PECO Energy. Under this standard, the operator of each respective station would be required to make payments to the non-operating owners if the three-year capacity factor, determined annually, of such station falls below 40 percent, subject to a maximum of $25 million per year. The initial three-year period begins on January 1, 1998 for Peach Bottom and on the date the later of the two Salem units (Salem 1) returns to service for Salem. The parties have further agreed to forego litigation in the future, except for limited cases in which the operator would be responsible for damages of no more than $5 million per year.
Year 2000
Many of Enterprise's and PSE&G's systems must be modified due to computer program limitations in recognizing dates beyond 1999. If not corrected, the systems could fail or cause erroneous results by, at or after January 1, 2000. Substantial changes to, and some replacements of, Enterprise's and PSE&G's present systems are being made in an effort to mitigate potential Year 2000 issues. Costs are being expensed as incurred in accordance with EITF 96-14, "Accounting for the Costs Associated with Modifying Computer Software for the Year 2000." During 1997, $8 million of costs related to Year 2000 readiness were incurred. Management estimates the total cost of this effort to be about $92 million to be incurred from 1997 through 2001, of which $41 million is expected to be incurred in 1998.
Enterprise and PSE&G have assembled a cross-functional team to inventory, assess and identify and implement solutions for Enterprise's and PSE&G's systems. Plans provide for 80% of critical systems to be Year 2000 ready in 1998, with the remaining critical systems to be ready by July 1999. By the end of 1999, plans call for 80% of non-critical systems to be Year 2000 ready with the remainder of those systems to be Year 2000 ready in 2000.
Additionally, the team has surveyed Enterprise's and PSE&G's top 3000 vendors to assess their plans for Year 2000 readiness. The team has also been working with critical suppliers and Pennsylvania--New Jersey--Maryland Interconnection (PJM) on their plans for Year 2000 readiness.
On January 29, 1998, the NRC proposed to issue a generic letter which would require all nuclear plant operators to provide the agency with information concerning their programs, planned or implemented, to address Year 2000 computer and systems issues at their facilities. In particular, operators would be asked to provide confirmation of implementation of their programs and certification that their facilities are Year 2000 ready and in compliance with the terms and conditions of their licenses and NRC regulations. Licensees would be required to submit a written response indicating the status of their Year 2000 readiness program including scope, assessment process and plans for corrective action. Further, upon completion of their Year 2000 readiness program and no later than July 1, 1999, licensees would be required to confirm to the NRC that their facility is Year 2000 ready, together with a status report of work necessary to be Year 2000 compliant. Year 2000 ready means computer systems and applications are suitable for continued use into 2000. Year 2000 compliant means that such systems and applications accurately process date/time data beyond 2000. PSE&G cannot predict if this or any proposal will be adopted by the NRC.
An inability of Enterprise, PSE&G, their subsidiaries, members of PJM or Enterprise's or PSE&G's critical suppliers to meet the Year 2000 deadline could have a material adverse impact on Enterprise's and PSE&G's operations, financial condition, results of operations and net cash flows.
Construction and Fuel Supplies
PSE&G has substantial commitments as part of its ongoing construction program, which include capital requirements for nuclear fuel. PSE&G's construction program is continuously reviewed and periodically revised as a result of changes in economic conditions, revised load forecasts, scheduled retirement dates of existing facilities, business strategies, site changes, cost escalations under construction contracts, requirements of regulatory authorities and laws, the timing of and amount of electric and gas rate changes and the ability of PSE&G to raise necessary capital. Pursuant to an electric resource plan (Resource Plan), PSE&G periodically reevaluates its forecasts of future customers, load and peak growth, sources of electric generating capacity and DSM to meet such projected growth, including the need to construct new electric generating capacity. The Resource Plan takes into account assumptions concerning future demands of customers, effectiveness of conservation and load management activities, the long-term condition of PSE&G's plants, capacity available from electric utilities and other suppliers and the amounts of co-generation and other non-utility capacity projected to be available.
PSE&G's construction expenditures are expected to aggregate approximately $3.1 billion during the years 1998 through 2002, which includes $457 million for nuclear fuel and excludes AFDC. The estimate of construction requirements is based on expected project completion dates and includes anticipated escalation due to inflation of approximately 3% annually. Therefore, construction delays or higher inflation levels could cause significant increases in these amounts. PSE&G expects to internally generate the funds necessary to satisfy its construction expenditures over this period, assuming adequate and timely recovery of costs, as to which no assurances can be given. In addition, PSE&G does not presently anticipate any difficulties in obtaining sufficient sources of fuel for electric generation or adequate gas supplies during the years 1998 through 2002.
Hazardous Waste
Certain Federal and state laws authorize the U.S. Environmental Protection Agency (EPA) and the New Jersey Department of Environmental Protection (NJDEP), among other agencies, to issue orders and bring enforcement actions to compel responsible parties to investigate and take remedial actions at any site that is determined to present an actual or potential threat to human health or the environment because of an actual or threatened release of one or more hazardous substances. Because of the nature of PSE&G's business, including the production of electricity, the distribution of gas and, formerly, the manufacture of gas, various by-products and substances are or were produced or handled which contain constituents classified as hazardous. PSE&G generally provides for the disposal or processing of such substances through licensed independent contractors. However, these statutory provisions impose joint and several responsibility without regard to fault on all responsible parties, including the generators of the hazardous substances, for certain investigative and remediation costs at sites where these substances were disposed of or processed. PSE&G has been notified with respect to a number of such sites and the investigation and remediation of these potentially hazardous sites is receiving attention from the government agencies involved. Generally, actions directed at funding such site investigations and remediation include all suspected or known responsible parties. Except as discussed below with respect to its Remediation Program, Enterprise and PSE&G do not expect its expenditures for any such site to have a material effect on financial condition, results of operations and net cash flows.
The NJDEP has recently revised regulations concerning site investigation and remediation. These regulations will require an ecological evaluation of potential injuries to natural resources in connection with a remedial investigation of contaminated sites. The NJDEP is presently working with the utility industry to develop procedures for implementing these regulations. These regulations may substantially increase the costs of remedial investigations and remediations, where necessary, particularly at sites situate on surface water bodies. PSE&G and predecessor companies owned and/or operated certain facilities situate on surface water bodies, certain of which are currently the subject of remedial activities. The financial impact of these regulations on these projects is not currently estimable. PSE&G does not anticipate that the compliance with these regulations will have material adverse effect on its financial position, results of operations or net cash flows.
PSE&G Manufactured Gas Plant Remediation Program
In 1988, NJDEP notified PSE&G that it had identified the need for PSE&G, pursuant to a formal arrangement, to systematically investigate and, if necessary, resolve environmental concerns extant at PSE&G's former manufactured gas plant sites. To date, NJDEP and PSE&G have identified 38 former manufactured gas plant sites. PSE&G is currently working with NJDEP under a program to assess, investigate and, if necessary, remediate environmental concerns at these sites. The Remediation Program is periodically reviewed and revised by PSE&G based on regulatory requirements, experience with the Remediation Program and available remediation technologies. The cost of the Remediation Program cannot be reasonably estimated, but experience to date indicates that costs of approximately $20 million per year could be incurred over a period of about 30 years and that the overall cost could be material to Enterprise's and PSE&G's financial condition, results of operations and net cash flows.
Costs incurred through December 31, 1997 for the Remediation Program amounted to $122 million. In addition, at December 31, 1997, PSE&G's estimated liability for remediation costs through 2000 aggregated $73 million. Expenditures beyond 2000 cannot be reasonably estimated (see Note 1. Organization and Summary of Significant Accounting Policies and Note 2. Rate Matters).
Note 11. PSE&G Nuclear Decommissioning
The BPU decision in PSE&G's most recent base rate case utilized studies based on the prompt removal/dismantlement method of decommissioning for all of PSE&G's nuclear generating stations. This method consists of removing fuel, source material and all other radioactive materials with activity levels above accepted release limits from the nuclear sites. PSE&G has an ownership interest in five nuclear units: Salem 1 and Salem 2--42.59% each, Hope Creek--95% and Peach Bottom 2 and 3--42.49% each. In accordance with rate orders received from the BPU, PSE&G has established an external master nuclear decommissioning trust for all its nuclear units. This trust contains two separate funds: a qualified fund and a non-qualified fund, due to an Internal Revenue Service (IRS) ruling. 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. PSE&G estimated the total cost of decommissioning its share of these five nuclear units at $986 million in year end 1995 dollars (the year that the most recent site specific estimates were prepared), excluding contingencies. On December 23, 1996, PSE&G filed its 1995 nuclear plant decommissioning cost update with the BPU. On December 17, 1997, the BPU accepted PSE&G's decommissioning cost updates and found that the current funding requirements as presented in PSE&G's 1996 Nuclear Decommissioning Trust Fund Report, dated May 15, 1997, appear adequate.
The most recent base rate decision provided that $15.6 million of such costs are to be collected through base rates and an additional annual amount of $7 million in 1993 and $14 million each year thereafter are to be recovered through PSE&G's LEAC. Although PSE&G's Energy Master Plan proposal continues this treatment, no assurances can be given as to the outcome of the Energy Master Plan proceedings (see Note 2. Rate Matters). At December 31, 1997 and 1996, the accumulated provision for depreciation and amortization included reserves for nuclear decommissioning for PSE&G's nuclear units of $428 million and $338 million, respectively. As of December 31, 1997 and 1996, PSE&G had contributed $279 million and $249 million, respectively, into independent, external, qualified and non-qualified nuclear decommissioning trust funds. The fair market value of these funds as of December 31, 1997 and 1996 was $458 million and $375 million, respectively.
The staff of the SEC has questioned certain of the current accounting practices of the electric utility industry, including PSE&G, regarding the recognition, measurement and classification of nuclear decommissioning costs in their financial statements. In response to these questions, the Financial Accounting Standards Board (FASB) has agreed to review the accounting for removal costs, including decommissioning. If current electric utility industry accounting practices for decommissioning are changed: (1) annual provisions for decommissioning could materially increase, (2) the estimated cost for decommissioning could be recorded as a liability rather than as accumulated depreciation and (3) trust fund income from the external decommissioning trusts could be reported as investment income rather than as a reduction to decommissioning expense all, or any of which, could have a material adverse effect on Enterprise's and PSE&G's financial condition, results of operations and net cash flows (see Note 2. Rate Matters).
Uranium Enrichment Decontamination and Decommissioning Fund
In accordance with EPAct, domestic utilities that own nuclear generating stations are required to pay a cumulative total of $150 million each year (adjusted for inflation) into a decontamination and decommissioning fund, based on their past purchases of U.S. government enrichment services. These amounts are being collected over a period of 15 years or until $2.25 billion (adjusted for inflation) has been collected. Under this legislation, PSE&G's obligation for the nuclear generating stations in which it has an interest is $70 million (adjusted for inflation). Since 1993, PSE&G has paid $27 million, resulting in a balance due of $43 million. PSE&G has deferred the expenditures incurred to date as part of underrecovered electric energy costs (see Note 2. Rate Matters).
Spent Nuclear Fuel Disposal Costs
In accordance with the Nuclear Waste Policy Act (NWPA), PSE&G has entered into contracts with the Department of Energy (DOE) for the disposal of spent nuclear fuel. Payments made to the DOE for disposal costs are based on nuclear generation and are included in Fuel for Electric Generation and Net Interchanged Power in the Statements of Income. These costs are being recovered through the LEAC (see Note 2. Rate Matters).
DOE construction of a permanent disposal facility has not begun and DOE has announced that it does not expect a facility to be available until 2010 at the earliest. Accordingly, legislation which would have the DOE establish a centralized interim spent fuel storage facility has been introduced in Congress. In cases brought by PSE&G, 32 other utilities and many state and local governments, the United States Court of Appeals for the District of Columbia Circuit reaffirmed DOE's unconditional obligation to begin spent fuel acceptance by January 31, 1998. In November 1997, the court ruled that the utilities had fulfilled their obligations under their respective contracts with DOE by contributing to the Nuclear Waste Fund. The court further ruled that DOE's argument of unavoidable delay to meet its obligation was without merit. However, the court did not order DOE to commence spent fuel acceptance by January 31, 1998; instead, it decided that the standard contract provided a potentially adequate remedy in the form of payment of damages if DOE failed its obligations. Consequently, PSE&G is working with the utility industry to develop a methodology for determining damages incurred as a result of DOE's failure to meet its obligation and a strategy for its implementation. PSE&G is presently studying options to recover damages from DOE. The decision of the Court of Appeals has been appealed to the U.S. Supreme Court by the U.S. Department of Justice. No assurances can be given as to the ultimate availability of a facility.
Note 12. Federal Income Taxes
A reconciliation of reported Net Income with pretax income and of Federal income tax expense with the amount computed by multiplying pretax income by the statutory Federal income tax rate of 35% is as follows:
Reconciliation between total Federal income tax provisions and tax computed at the statutory tax rate on pretax income:
(A) The provision for deferred income taxes represents the tax effects of the following items:
Between the years 1987 and 1994, Enterprise's Federal Alternative Minimum Tax (AMT) liability exceeded its regular Federal income tax liability. This excess was carried forward to offset regular income tax liability in future years. Enterprise used these AMT credits as a reduction against regular tax liability for 1995, 1996 and 1997. There were no remaining credits as of December 31, 1997.
Enterprise 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, 1997, PSE&G had a deferred tax liability and an offsetting regulatory asset of $725 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%.
The following is an analysis of deferred income taxes:
December 31, -------------------- 1997 1996 -------- ------- (Millions of Dollars) Deferred Income Taxes Assets: Current (net).................................... $25 $23 ------- ------- Non-current: Unrecovered Investment Tax Credits............. 117 123 Nuclear Decommissioning........................ 33 27 Construction Period Interest and Taxes......... 15 16 Vacation Pay................................... 7 7 AMT Credit..................................... -- 88 Real Estate Impairment......................... 6 3 Other.......................................... 33 24 ------- ------- Total Non-current......................... 211 288 ------- ------- Total Assets.............................. 236 311 ------- ------- Liabilities: Non-current: Plant Related Items............................ 2,349 2,361 Leasing Activities............................. 720 669 Conservation Costs............................. 39 12 Hope Creek O&M Costs........................... 21 22 Underrecovered Electric Energy and Gas Costs... 60 63 Unamortized Debt Expense....................... 44 40 Taxes Recoverable Through Future Rates (net)... 249 259 Other.......................................... 123 112 ------- ------- Total Non-current......................... 3,605 3,538 ------- ------- Total Liabilities......................... 3,605 3,538 ------- ------- Summary -- Accumulated Deferred Income Taxes Net Current Assets............................... 25 23 Net Non-current Liability........................ 3,394 3,250 ------- ------- Total....................................... $3,369 $3,227 ======= =======
Note 13. Pension Plan
The discount rates, expected long-term rates of return on assets and average compensation growth rates used in determining the qualified Pension Plans' funded status and net pension cost as of December 31, 1997 and 1996 were as follows:
1997 1996 ------- -------- Funded Status: Discount Rate used to Determine Benefit Obligations....................................... 7.25% 7.50% Average Compensation Growth to Determine Benefit Obligations............................... 4.50% 4.50% Net Pension Cost: Discount Rate....................................... 7.50% 8.00% Expected Long-Term Return on Assets................. 9.00% 8.50% Average Compensation Growth......................... 4.50% 4.50%
The following table shows the qualified Pension Plans' funded status:
The net pension cost for the qualified Pension Plans for the years ended December 31, 1997, 1996 and 1995, includes the following components:
The discount rates and average compensation growth rates used in determining the non-qualified Pension Plans' funded status and net pension cost as of December 31, 1997 and 1996 were as follows:
The following table shows the non-qualified Pension Plans' funded status:
The net pension cost for the non-qualified Pension Plans for the years ended December 31, 1997, 1996 and 1995, includes the following components:
(A) Beginning in 1997, SFAS 87 was applied to the non-qualified Pension Plans. Prior to that date, because the plans amounts were considered immaterial, SFAS 87 was not applied.
Note 14. Postretirement Benefits Other Than Pensions
Upon adoption of SFAS 106, PSE&G elected to amortize, over 20 years, its unfunded obligation of $609 million at January 1, 1993. The following table discloses the significant components of the net periodic postretirement benefit cost:
The discount rate used in determining the PSE&G net periodic postretirement benefit cost was 7.5% and 8.0% for 1997 and 1996, respectively.
A one percentage-point increase in the assumed health care cost trend rate for each year would increase the aggregate of the service and interest cost components of net periodic postretirement health care cost by approximately $6 million, or 10.5%, and increase the accumulated postretirement benefit obligation as of December 31, 1997 by $57 million, or 9.4%.
The assumed health care cost trend rates used in measuring the accumulated postretirement benefit obligation in 1997 were: medical costs for pre-age sixty-five retirees--11.5%, medical costs for post-age sixty-five retirees--7.5% and dental costs--5.5%; such rates are assumed to decrease by 0.5% per year until they reach 5.0% and then remain constant. The medical costs above include a provision for prescription drugs.
From January 1, 1993 through December 31, 1997, PSE&G accounted for the differences between its SFAS 106 accrual cost and the cash cost currently recovered through rates as a regulatory asset in accordance with SFAS 71 and EITF 92-12. OPEB costs expensed and capitalized during 1997 were $33 million and accrued OPEB costs deferred were $63 million. The amount of the unfunded liability, at December 31, 1997, as shown below, is $724 million.
In 1993, the FASB's EITF concluded that deferral of such costs is acceptable, provided regulators allow SFAS 106 costs in rates within approximately five years of the adoption of SFAS 106, which was December 31, 1997, for financial reporting purposes, with any cost deferrals recovered in approximately twenty years. On December 17, 1997, the BPU ruled that PSE&G's current rates are sufficient to recover both the ongoing OPEB costs and the amortization of the deferred regulatory asset created by the accounting change from the cash basis of accounting to the accrual basis of accounting in accordance with SFAS 106 and EITF 92-12. As a result of the BPU's decision, PSE&G will amortize the regulatory asset over 15 years beginning January 1, 1998. Also effective January 1, 1998, PSE&G will record the annual SFAS 106 OPEB cost.
In accordance with SFAS 106 disclosure requirements, a reconciliation of the funded status of the plan is as follows:
The discount rate used in determining the accumulated postretirement benefit obligation was 7.25% and 7.50% for 1997 and 1996, respectively.
Note 15. Financial Information by Business Segments
Information related to the segments of Enterprise's business is detailed below:
Information related to Property, Plant and Equipment of PSE&G is detailed below:
Note 16. Discontinued Operations
On July 31, 1996, EDHI sold EDC to Samedan Oil Corporation, a subsidiary of Noble Affiliates, Inc., for an aggregate purchase price of $779 million subject to various purchase price adjustments resulting in an after-tax gain of $13 million. As a result, Consolidated Financial Statements previously issued have been restated to give effect to the classification of EDC as discontinued operations.
Operating results of EDC for 1996 (7 months) and 1995 are summarized in the following table:
(7 months) 1996 1995 ---- ---- (Millions of Dollars) Revenues........................................ $128 $270 Operating income................................ 24 81 Earnings before income taxes.................... 9 53 Income taxes.................................... (2) 18 Net income...................................... 11 35
Note 17. Jointly Owned Facilities--Utility Plant
PSE&G has ownership interests in and is responsible for providing its share of the necessary financing for the following jointly owned facilities. All amounts reflect the share of PSE&G's jointly owned projects and the corresponding direct expenses are included in Consolidated Statements of Income as operating expenses (see Note 1. Organization and Summary of Significant Accounting Policies).
Note 18. Selected Quarterly Data (Unaudited)
The information shown below, in the opinion of Enterprise, 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.
PSE&G
Except as modified below, the Notes to Consolidated Financial Statements of Enterprise are incorporated herein by reference insofar as they relate to PSE&G and its subsidiaries:
Note 1. Organization and Summary of Significant Accounting Policies Note 2. Rate Matters 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 Note 10. Commitments and Contingent Liabilities Note 11. PSE&G Nuclear Decommissioning Note 13. Pension Plan Note 14. Postretirement Benefits Other Than Pensions Note 15. Financial Information by Business Segments Note 17. Jointly Owned Facilities--Utility Plant
Note 1. Organization and Summary of Significant Accounting Policies
Enterprise 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, 1997, 1996 and 1995, there were 132,450,344 shares outstanding, with an aggregate book value of $2.6 billion.
Note 9. Cash and Cash Equivalents
The December 31, 1997 and 1996 balances consist primarily of working funds.
Note 12. Federal Income Taxes
A reconciliation of reported Net Income with pretax income and of Federal income tax expense with the amount computed by multiplying pretax income by the statutory Federal income tax rate of 35% is as follows:
Reconciliation between total Federal income tax provisions and tax computed at the statutory tax rate on pretax income:
(A) The provision for deferred income taxes represents the tax effects of the following items:
SFAS 109
The following is an analysis of deferred income taxes:
The balance of Federal income tax payable by (receivable from) PSE&G to Enterprise was $5 million and $(5) million, as of December 31, 1997 and December 31, 1996, respectively.
Note 18. 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.
FINANCIAL STATEMENT RESPONSIBILITY--ENTERPRISE
Management of Enterprise is responsible for the preparation, integrity and objectivity of the consolidated financial statements and related notes of Enterprise. 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 Enterprise'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 Enterprise'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 PSE&G conducts audits and appraisals of accounting and other operations of Enterprise 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, 1997, the Corporation's system of internal accounting controls is adequate to accomplish the objectives discussed herein.
The Board of Directors of Enterprise carries out its responsibility of financial overview through its Audit Committee, which presently consists of six directors who are not employees of Enterprise 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 13, 1998
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 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, 1997, the Corporation's system of internal accounting controls is adequate to accomplish the objectives discussed herein.
The Board of Directors carries out its responsibility of financial overview through the Audit Committee of Enterprise, which presently consists of six directors who are not employees of PSE&G or any of its affiliates. The Enterprise 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 C. MURRAY Chairman of the Board and Executive Vice President--Finance Chief Executive Officer (Principal Financial Officer)
PATRICIA A. RADO Vice President and Controller (Principal Accounting Officer)
February 13, 1998
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, 1997 and 1996, 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, 1997. Our audits also included the consolidated financial statement schedule listed in the Index in Item 14(B)(1). 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 generally accepted auditing standards. Those standards require that we plan and perform the audits 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 Public Service Enterprise Group Incorporated and its subsidiaries at December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997 in conformity with generally accepted accounting principles. 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 also previously audited, in accordance with generally accepted auditing standards, the consolidated balance sheets as of December 31, 1995, 1994, and 1993, and the related consolidated statements of income, retained earnings and cash flows for the years ended December 31, 1994 and 1993 (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, 1997 for the Company, 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 13, 1998
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, 1997 and 1996, 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, 1997. Our audits also included the consolidated financial statement schedule listed in the Index in Item 14(B)(2). 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 generally accepted auditing standards. Those standards require that we plan and perform the audits 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 Public Service Electric and Gas Company and its subsidiaries at December 31, 1997 and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997 in conformity with generally accepted accounting principles. 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 also previously audited, in accordance with generally accepted auditing standards, the consolidated balance sheets as of December 31, 1995, 1994, and 1993, and the related consolidated statements of income, retained earnings and cash flows for the years ended December 31, 1994 and 1993 (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, 1997 for the Company, 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 13, 1998
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Enterprise and PSE&G, none.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrants
Directors of the Registrants
Enterprise
The information required by Item 10 of Form 10-K with respect to present directors who are nominees for election as directors at Enterprise's Annual Meeting of Stockholders to be held on April 21, 1998, and directors whose terms will continue beyond the meeting, is set forth under the heading "Election of Directors" in Enterprise'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 6, 1998 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 21, 1998, 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.
LAWRENCE R. CODEY has been a director since 1988. Age 53. Member of Executive Committee. Has been President and Chief Operating Officer of PSE&G since 1991. Director of Enterprise. Director of Sealed Air Corporation, The Trust Company of New Jersey, United Water Resources Inc. and Blue Cross & Blue Shield of New Jersey.
E. JAMES FERLAND has been a director since 1986. Age 56. Chairman of Executive Committee. Chairman of the Board, President and Chief Executive Officer of Enterprise 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 EDHI since June 1989. Director of Enterprise and of EDHI. Director of Foster Wheeler Corporation and The HSB Group, Inc.
RAYMOND V. GILMARTIN has been a director since 1993. Age 57. Director of Enterprise. Has been Chairman of the Board, President and Chief Executive Officer of Merck & Company, Inc., Whitehouse Station, New Jersey (discovers, develops, produces and markets human and animal health products) since November 1994. Was President and Chief Executive Officer from June 1994 to November 1994. Was Chairman of the Board, President and Chief Executive Officer of Becton Dickinson and Company from November 1992 to June 1994. Director of Merck & Co., Inc. and General Mills, Inc.
CONRAD K. HARPER has been a director since May 1997. Age 57. Director of Enterprise. 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 67. Member of Executive Committee. Was previously a director from 1981 to February 1988. Director of Enterprise. Was Chairman, Board of Directors from January 1993 to September 1993 and President and Chief Executive Officer from 1980 to December 1992 of Hoffmann-La Roche Inc., Nutley, New Jersey (prescription pharmaceuticals, vitamins and fine chemicals, and diagnostic products and services). Director of Humana Inc., AXYS Pharmaceuticals, Inc., Medarex, Inc. and Covance Inc.
FORREST J. REMICK has been a director since 1995. Age 67. Director of Enterprise. 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.
Executive Officers of the Registrants
The following table sets forth certain information concerning the executive officers of Enterprise and PSE&G, respectively.
Item 11.
Item 11. Executive Compensation
Enterprise
The information required by Item 11 of Form 10-K is set forth under the heading "Executive Compensation" in Enterprise's definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 21, 1998 which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 6, 1998 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, 1997 is set forth below. Amounts shown were paid or awarded for all services rendered to Enterprise and its subsidiaries and affiliates including PSE&G.
(1) Amount awarded in given year was earned under Management Incentive Compensation Plan (MICP) and determined in following year with respect to the given year based on individual performance and financial and operating performance of Enterprise and PSE&G, including comparison to other companies. For plan years prior to 1996, the award is accounted for as market-priced phantom stock with dividend reinvestment at 95% of market price, with payment made over three years beginning in second year following grant. Beginning in 1997 with respect to the 1996 and future plan years, awards are payable in one lump sum.
(2) Includes grant of options to purchase 8,000 and 10,000; 4,200 and 5,000; 3,000 and 4,000; 3,000 and 2,500; 1,800 and 2,500 shares of Enterprise Common Stock in January and December, respectively, to Messrs. Ferland, Codey, Murray, Eliason and Selover, respectively, under Long-Term Incentive Plan (LTIP) in tandem with equal number of performance units and dividend equivalents which may provide cash payments, dependent upon future financial performance of Enterprise in comparison to other companies and dividend payments by Enterprise, to assist recipients in exercising options granted. The 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. Also includes options to purchase 100,000; 50,000; 25,000; 10,000 and 10,000 shares of Enterprise Common Stock granted to Messrs. Ferland, Codey, Murray, Eliason and Selover, respectively, under LTIP not in tandem with 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, each as measured during three-year period ending the year prior to the year in which payment is made.
(4) Includes employer contribution to Thrift and Tax-Deferred Savings Plan and value of 5% discount on phantom stock dividend reinvestment under MICP:
In addition, 1997, 1996 and 1995 amounts include for Mr. Ferland $9,824, $3,983 and $2,546; for Mr. Eliason $6,986, $3,349 and $1,447 and for Mr. Selover $3,938, $1,398 and $951, respectively, representing interest on compensation deferred under PSE&G's Deferred Compensation Plan in excess of 120% of the applicable Federal long-term rate as prescribed under Section 1274(d) of the Internal Revenue Code. Under PSE&G's Deferred Compensation Plan, interest is paid at prime rate plus 1/2%, adjusted quarterly.
(5) The 1997 MICP award amount has not yet been determined. The target award is 50% of salary for Mr. Ferland, 40% for Messrs. Codey and Eliason, 35% for Mr. Murray and 30% for Mr. Selover. The target award is adjusted to reflect Enterprise's return on capital, PSE&G's comparative electric and gas costs and individual performance.
(6) Includes $25,000 paid pursuant to Mr. Murray's employment agreement.
(7) Includes $100,000 paid pursuant to Mr. Eliason's employment agreement.
(8) Includes $165,000 paid pursuant to Mr. Eliason's employment agreement.
(9) Mr. Eliason is scheduled to retire effective April 30, 1998.
(10) Amount paid pursuant to Mr. Eliason's employment agreement.
(1) Granted under LTIP in tandem with equal number of performance units and dividend equivalents which may provide cash payments, dependent on future financial performance of Enterprise in comparison to other companies and dividend payments by Enterprise, to assist recipients in exercising options, with exercisability commencing January 1, 2000. Cash payment is made, based on the value, if any, of performance units awarded and dividend equivalents accrued, if any, as measured during the three-year period ending the year prior to the year in which payment, if any, is made, only if the specified performance level is achieved, dividend equivalents have accrued and options are exercised.
(2) Granted under LTIP in tandem with equal number of performance units and dividend equivalents, as described in Note (1) above, but with exercisability commencing January 1, 2001.
(3) Granted under LTIP not in tandem with performance units and dividend equivalents, with exercisability commencing December 16, 1998, December 16, 1999 and December 16, 2000, respectively, with respect to one-third of the options at each such date.
(4) Determined using the Black-Scholes model, incorporating the following material assumptions and adjustments for the grants expiring January 3, 2007 and December 16, 2007, respectively: (a) exercise prices of $27.625 and $29.563, equal to the fair market value of the underlying Enterprise Common Stock on the dates of grant; (b) an option term of ten years on all grants; (c) interest rates of 6.58% and 5.81% that represent the interest rates on U.S. Treasury securities on the dates of grant with a maturity date corresponding to that of the option terms; (d) volatilities of 17.847% and 18.948% calculated using daily Enterprise Common Stock prices for the one-year period prior to the grant dates; (e) a dividend yield of 0% with respect to the dividend equivalent feature of the tandem grants, since dividend payments accrue while the option is held; (f) a dividend yield of 7.31% on the non-tandem grants and (g) reductions of approximately 11.51% and 7.8% for the non-tandem and tandem grants, respectively, to reflect the probability of forfeiture due to termination prior to vesting, and approximately 26.3%, 17.36% and 1.75% for the grant expiring January 3, 2007 and each of the grants expiring December 16, 2007, respectively, to reflect the probability of a shortened option term due to termination of employment prior to the option expiration date. Actual values which may be realized, if any, upon any exercise of such options, will be based on the market price of Enterprise Common Stock at the time of any such exercise and thus are dependent upon future performance of Enterprise 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.
(1) Does not reflect any options granted and/or exercised after year end (12/31/97). The net effect of any such grants and exercises is reflected in the table appearing under Security Ownership of Directors and Management.
(2) Represents difference between exercise price and market price of Enterprise Common Stock on date of exercise.
(3) Represents difference between market price of Enterprise Common Stock and the respective exercise prices of the options at fiscal year end (12/31/97). 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 Enterprise Common Stock at the time of any such exercise and thus are dependent upon future performance of Enterprise Common Stock.
Employment Contracts and Arrangements
Employment agreements were entered into with Messrs. Ferland, Murray and Eliason at the time of their employment. For Mr. Ferland, the remaining applicable provisions of the agreement provide for additional credited service for retirement benefits purposes in the amount of 22 years. The principal remaining applicable terms of the agreement with Mr. Murray, as modified in 1998, provide for additional years of credited service for retirement benefits purposes for allied work experience of five years after completion of five years of service, and up to seventeen years after completion of approximately nine years of service. The principal remaining applicable terms of the agreement with Mr. Eliason provide for a lump sum cash payment of $35,000 in 1998 to align Mr. Eliason with MICP payments for other executive officers, and additional years of credited service for retirement benefits purposes for allied work experience of 19 years at his scheduled retirement date of April 30, 1998.
Compensation Committee Interlocks and Insider Participation
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 Enterprise. Hence, during 1997 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 Directors and Certain Business Relationships
A director who is not an officer of Enterprise 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 Enterprise, PSE&G or EDHI. Each of the directors of PSE&G is also a director of Enterprise. No additional retainer is paid for service as a director of PSE&G. Fifty percent of the annual retainer is paid in Enterprise Common Stock.
Enterprise also maintains a Stock Plan for Outside Directors pursuant to which directors who are not employees of Enterprise or its subsidiaries receive 300 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 above under the heading Security Ownership of Directors and Management.
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 if Enterprise were to merge with another corporation and not be the surviving corporation or if the director were to die in office. Enterprise 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
Length of Service -------------------------------------------------------------- Average Final Compensation 30 Years 35 Years 40 Years 45 Years - ---------------- ------------- --------------- ---------------- --------------- $300,000 $180,000 $195,000 $210,000 $225,000 400,000 240,000 260,000 280,000 300,000 500,000 300,000 325,000 350,000 375,000 600,000 360,000 390,000 420,000 450,000 700,000 420,000 455,000 490,000 525,000 800,000 480,000 520,000 560,000 600,000 900,000 540,000 585,000 630,000 675,000 1,000,000 600,000 650,000 700,000 750,000 1,100,000 660,000 715,000 770,000 825,000 1,200,000 720,000 780,000 840,000 900,000
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 130% of the average annual salary for such five year period. Messrs. Ferland, Codey, Murray and Selover will have accrued approximately 48, 41, 41 and 43 years of credited service, respectively, as of age 65. Mr. Eliason is scheduled to retire at age 59 with 23 years of credited service.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Enterprise
The information required by Item 12 of Form 10-K with respect to directors and executive officers is set forth under the heading 'Security Ownership of Directors and Management' in Enterprise's definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 21, 1998 which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 6, 1998 and such information set forth under such heading is incorporated herein by this reference thereto.
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, Enterprise, 80 Park Plaza, P.O. Box 1171, Newark, New Jersey.
The following table sets forth beneficial ownership of Enterprise Common Stock, including options, by the directors and executive officers named below as of January 31, 1998. None of these amounts exceed 1% of the Enterprise 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 ---- -------------------- Lawrence R. Codey...................................... 80,811 (1) Leon R. Eliason........................................ 24,108 (2) E. James Ferland....................................... 183,057 (3) Raymond V. Gilmartin................................... 3,989 Conrad K. Harper....................................... 300 Irwin Lerner........................................... 10,367 Robert C. Murray....................................... 46,179 (4) Forrest J. Remick...................................... 2,213 R. Edwin Selover....................................... 26,891 (5) All directors and executive officers (12) as a group... 410,159 (6)
(1) Includes options to purchase 65,700 shares, 3,500 of which are currently exercisable.
(2) Includes the equivalent of 8 shares held under PSE&G Thrift and Tax-Deferred Savings Plan. Includes options to purchase 20,500 shares, 2,500 of which are currently exercisable.
(3) Includes the equivalent of 10,989 shares held under PSE&G Thrift and Tax-Deferred Savings Plan. Includes options to purchase 130,300 shares, 5,800 of which are currently exercisable.
(4) Includes the equivalent of 1,179 shares held under PSE&G Thrift and Tax-Deferred Savings Plan. Includes options to purchase 36,000 shares, 2,000 of which are currently exercisable.
(5) Includes options to purchase 19,300 shares, of which 3,600 are currently exercisable.
(6) Includes the equivalent of 12,453 shares held under PSE&G Thrift and Tax-Deferred Savings Plan. Includes options to purchase 302,400 shares, of which 18,400 are currently exercisable.
Item 13.
Item 13. Certain Relationships and Related Transactions
Enterprise
The information required by Item 13 of Form 10-K is set forth under the heading "Executive Compensation" in Enterprise's definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 21, 1998, which definitive Proxy Statement is expected to be filed with the Securities and Exchange Commission on or about March 6, 1998. Such information set forth under such heading is incorporated herein by this reference thereto.
PSE&G
None.
PART IV
Item 14.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(A) Financial Statements:
(1) Enterprise Consolidated Statements of Income for the years ended December 31, 1997, 1996, and 1995, on page 49.
Enterprise Consolidated Balance Sheets for the years ended December 31, 1997 and 1996, on pages 50 and 51.
Enterprise Consolidated Statements of Cash Flows for the years ended December 31, 1997, 1996, and 1995 on page 52.
Enterprise Statements of Common Stockholders' Equity for the years ended December 31, 1997, 1996, and 1995 on page 53.
Enterprise Notes to Consolidated Financial Statements on pages 60 through 92.
(2) PSE&G Consolidated Statements of Income for the years ended December 31, 1997, 1996, and 1995, on page 55.
PSE&G Consolidated Balance Sheets for the years ended December 31, 1997 and 1996, on pages 56 and 57.
PSE&G Consolidated Statements of Cash Flows for the years ended December 31, 1997, 1996, and 1995 on page 58.
PSE&G Statements of Common Stockholder's Equity for the years ended December 31, 1997, 1996, and 1995 on page 59.
PSE&G Notes to Consolidated Financial Statements on pages 93 through 95.
(B) The following documents are filed as a part of this report:
(1) Enterprise Financial Statement Schedules:
Schedule II--Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 1997 (page 111).
(2) PSE&G Financial Statement Schedules:
Schedule II--Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 1997 (page 111).
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.
(C) The following exhibits are filed herewith:
(1) Enterprise:
Exhibit 10a(1) Directors' Deferred Compensation Plan Exhibit 10a(2) Deferred Compensation Plan for Certain Employees Exhibit 10a(3) Limited Supplemental Benefits Plan for Certain Employees Exhibit 10a(4) Mid Career Hire Supplemental Retirement Plan Exhibit 10a(5) Retirement Income Reinstatement Plan Exhibit 10a(6) Long-Term Incentive Plan Exhibit 10a(9)(i) Amendment to Letter Agreement with Robert C. Murray Exhibit 10a(16) Letter Agreement with Harold W. Keiser Exhibit 10a(17) CEA Deferred Compensation Plan Exhibit 10a(18) CEA Executive Incentive Compensation Plan Exhibit 10a(19) EDHI Management Incentive Compensation Plan Exhibit 10a(20) EDHI Deferred Compensation Plan Exhibit 10a(21) Energis Executive Incentive Compensation Plan Exhibit 10a(22) EDHI Limited Supplemental Benefits Plan for Certain Employees Exhibit 12 Computation of Ratios of Earnings to Fixed Charges Exhibit 21 Subsidiaries of Registrant Exhibit 23 Independent Auditors' Consent Exhibit 27 Financial Data Schedule
(See Exhibit Index on pages 115 through 122.)
(2) PSE&G:
Exhibit 10a(1) Directors' Deferred Compensation Plan Exhibit 10a(2) Deferred Compensation Plan for Certain Employees Exhibit 10a(3) Limited Supplemental Benefits Plan for Certain Employees Exhibit 10a(4) Mid Career Hire Supplemental Retirement Plan Exhibit 10a(5) Retirement Income Reinstatement Plan Exhibit 10a(6) Long-Term Incentive Plan Exhibit 10a(9)(i) Amendment to Letter Agreement with Robert C. Murray Exhibit 10a(16) Letter Agreement with Harold W. Keiser 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 Independent Auditors' Consent Exhibit 27 Financial Data Schedule
(See Exhibit Index on pages 122 through 128)
(D) The following reports on Form 8-K were filed by the registrant(s) named below during the last quarter of 1997 and the 1998 period covered by this report under Item 5:
Registrant Date of Report Item Reported
None.
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: February 23, 1998
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, February 23, 1998 E. James Ferland President and Chief Executive Officer and Director (Principal Executive Officer)
ROBERT C. MURRAY Vice President and Chief February 23, 1998 Robert C. Murray Financial Officer (Principal Financial Officer)
PATRICIA A. RADO Vice President and Controller February 23, 1998 Patricia A. Rado (Principal Accounting Officer)
LAWRENCE R. CODEY Director February 23, 1998 Lawrence R. Codey
ERNEST H. DREW Director February 23, 1998 Ernest H. Drew
T. J. DERMOT DUNPHY Director February 23, 1998 T. J. Dermot Dunphy
RAYMOND V. GILMARTIN Director February 23, 1998 Raymond V. Gilmartin
CONRAD K. HARPER Director February 23, 1998 Conrad K. Harper
IRWIN LERNER Director February 23, 1998 Irwin Lerner
MARILYN M. PFALTZ Director February 23, 1998 Marilyn M. Pfaltz
FORREST J. REMICK Director February 23, 1998 Forrest J. Remick
RICHARD J. SWIFT Director February 23, 1998 Richard J. Swift
JOSH S. WESTON Director February 23, 1998 Josh S. Weston
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: February 23, 1998
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 February 23, 1998 E. James Ferland Chief Executive Officer and Director (Principal Executive Officer)
ROBERT C. MURRAY Executive Vice President--Finance February 23, 1998 Robert C. Murray (Principal Financial Officer)
PATRICIA A. RADO Vice President and Controller February 23, 1998 Patricia A. Rado (Principal Accounting Officer)
LAWRENCE R. CODEY Director February 23, 1998 Lawrence R. Codey
RAYMOND V. GILMARTIN Director February 23, 1998 Raymond V. Gilmartin
CONRAD K. HARPER Director February 23, 1998 Conrad K. Harper
IRWIN LERNER Director February 23, 1998 Irwin Lerner
FORREST J. REMICK Director February 23, 1998 Forrest J. Remick
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. 1-973.
(b) Filed by PSE&G with Form 8-K under the Securities Exchange Act of 1934, on the respective dates indicated, File No. 1-973.
(c) Filed by PSE&G with Form 10-K under the Securities Exchange Act of 1934, on the respective dates indicated, File No. 1-973.
(d) Filed by PSE&G with Form 10-Q under the Securities Exchange Act of 1934, on the respective dates indicated, File No. 1-973.
(e) Filed by Enterprise with Form 10-K under the Securities Exchange Act of 1934, on the respective dates indicated, File No. 1-9120.
(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.
(j) 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.
(l) 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.
(m) 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.
ENTERPRISE - --------------------------------------------------- Exhibit Number - --------------------------------------------------- This Previous Filing ---------------------------------------- Filing Commission Exchanges - ------ ---------- --------- 3a (o) 3a (o) 3a Certificate of Incorporation Public Service Enterprise Group Incorporated
3b (e) 3b (e) 3b Copy of By-Laws of Public 4/11/88 Service Enterprise Group Incorporated, as in effect May 1,1987
3c (e) 3c (e) 3c Certificate of Amendment of 4/11/88 Certificate of Incorporation of Public Service Enterprise Group
4a(1) (f) B-1 (c) 4b(1) Incorporated, effective 2/18/81 April 23, 1987 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) (i) 7(1a) (c) 4b(2) April 1, 1927 2/18/81
4a(3) (k) 2b(3) (c) 4b(3) June 1, 1937 2/18/81
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) (j) 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
ENTERPRISE - --------------------------------------------------- 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(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 2/18/81
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
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) (l) 2b(33) (c) 4b(33) September 1, 1977 2/18/81
ENTERPRISE - ---------------------------------------------------- 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 1, 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(ii) (b) 4(ii) November 1, 1984 (No. 1) 1/4/85 1/9/85
4a(49) (b) 4(ii) (b) 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
ENTERPRISE - ---------------------------------------------------- Exhibit Number - ---------------------------------------------------- This Previous Filing ----------------------------------------- Filing 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 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
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
ENTERPRISE - ---------------------------------------------------- Exhibit Number - ---------------------------------------------------- This Previous Filing ----------------------------------------- Filing 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) (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) (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
ENTERPRISE - ---------------------------------------------------- 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
4b (h) 7(12) (c) 4c(1) Indenture between PSE&G and 2/18/81 Federal Trust Company, as Trustee (Midlantic National Bank, Successor Trustee) dated July 1, 1948, providing for 6% Debenture Bonds due 1998
4c (b) 4 (b) 4 Indenture of Trust between PSE&G 12/1/93 12/1/93 and The Chase Manhattan Bank (National Association), as Trustee, providing for Secured Medium-Term Notes dated July 1, 1993
4d(1) (c) (c) Indenture between PSE&G and 2/23/95 2/23/95 First Union National Bank, National Association (now known as First Union National Bank), as Trustee, dated November 1, 1994, providing for Deferrable Interest Subordinated Debentures in Series
4d(2) (a) (a) Supplemental Indenture between 9/11/95 9/11/95 PSE&G and First Fidelity Bank, National Association (now known as First Union National Bank), as Trustee, dated September 1, 1995 providing for Deferrable Interest Subordinated Debentures, Series B
9 Inapplicable
10a(1) Directors' Deferred Compensation Plan
10a(2) Deferred Compensation Plan for Certain Employees
10a(3) Limited Supplemental Benefits Plan for Certain Employees
10a(4) Mid Career Hire Supplemental Retirement Plan
10a(5) Retirement Income Reinstatement Plan
10a(6) Long-Term Incentive Plan
ENTERPRISE - ---------------------------------------------------- Exhibit Number - ---------------------------------------------------- This Previous Filing ----------------------------------------- Filing Commission Exchanges - ------ ---------- --------- 10a(7) (e) 10a(20) (e) 10a(20) Management Incentive 2/26/97 2/26/97 Compensation Plan
10a(8) (c) 10a(11) (c) 10a(11) Letter Agreement with E. James 2/10/93 2/11/93 Ferland dated April 16, 1986
10a(9) (c) 10a(15) (c) 10a(15) Letter Agreement with Robert C. 2/10/93 2/11/93 Murray dated December 17, 1991
10a(9)(i) Amendment to Letter Agreement with Robert C. Murray dated January 6, 1998
10a(10) (c) 10a(14) (c) 10a(14) Letter Agreement with 2/26/94 3/9/94 Patricia A. Rado dated March 24, 1993
10a(11) (c) 10a(15) (c) 10a(15) Letter Agreement, as amended, 2/23/95 2/23/95 with Leon R. Eliason dated September 14, 1994
10a(12) (d) 10a(15) (d) 10a(15) Letter Agreement with 8/14/95 8/14/95 Louis F. Storz dated July 7, 1995
10a(13) (d) 10a(16) (d) 10a(16) Letter Agreement with 8/14/95 8/14/95 Elbert C. Simpson dated May 31, 1995
10a(14) (d) 10a(17) (d) 10a(17) Letter Agreement with 11/14/95 11/14/95 Alfred C. Koeppe dated August 23, 1995
10a(15) (e) 10a(19) (e) 10a(19) Directors' Stock Plan 2/22/96 2/22/96
10a(16) Letter Agreement with Harold W. Keiser dated January 5, 1998
10a(17) CEA Deferred Compensation Plan
10a(18) CEA Executive Incentive Compensation Plan
10a(19) EDHI Management Incentive Compensation Plan
10a(20) EDHI Deferred Compensation Plan
10a(21) Energis Executive Incentive Compensation Plan
10a(22) EDHI Limited Supplemental Benefits Plan for Certain Employees
11 Inapplicable
12 Computation of Ratios of Earnings to Fixed Charges
13 Inapplicable
16 Inapplicable
18 Inapplicable
ENTERPRISE - ---------------------------------------------------- Exhibit Number - ---------------------------------------------------- This Previous Filing ----------------------------------------- Filing Commission Exchanges - ------ ---------- --------- 21 Subsidiaries of the Registrant
22 Inapplicable
23 Independent Auditors' Consent
24 Inapplicable
27 Financial Data Schedule
28 Inapplicable
99 Inapplicable
PSE&G - ---------------------------------------------------- Exhibit Number - ---------------------------------------------------- This Previous Filing ----------------------------------------- Filing Commission Exchanges - ------ ---------- --------- 3a(1) (b) 3a (b) 3a Restated Certificate of 8/28/86 8/29/86 Incorporation of PSE&G, effective May 1, 1986
3a(2) (c) 3a(2) (c) 3a(2) Certificate of Amendment of 4/10/87 Certificate of Restated Certificate of 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 2/3/94 2/14/94 Restated Certificate of Incorporation 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 2/3/94 2/14/94 Restated Certificate of Incorporation 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 2/3/94 2/14/94 Restated Certificate of Incorporation 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 Copy of By-Laws of PSE&G, as in effect September 1, 1995
4a(1) (f) B-1 (c) 4b(1) Indenture between PSE&G and 2/18/81 Fidelity Union Trust Company, (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(1), dated as follows:
4a(2) (i) 7(1a) (c) 4b(2) April 1, 1927 2/18/81
4a(3) (k) 2b(3) (c) 4b(3) June 1, 1937 2/18/81
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) (j) 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 2/18/81
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
PSE&G Exhibit Number - ---------------------------------------------------- This Previous Filing ----------------------------------------- Filing 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) (l) 2b(33) (c) 4b(33) September 1, 1977 2/18/81
4a(34) (a) 2 (c) 4b(34) November 1, 1978 11/21/78 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 1, 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
PSE&G - ---------------------------------------------------- Exhibit Number - ---------------------------------------------------- This Previous Filing ----------------------------------------- Filing Commission Exchanges - ------ ---------- --------- 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(ii) (b) 4(ii) November 1, 1984 (No. 1) 1/4/85 1/9/85
4a(49) (b) 4(ii) (b) 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) (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 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
4a(66) (a) 4 (a) 4 November 1, 1991 (No. 2) 12/2/91 12/3/91
PSE&G - ---------------------------------------------------- Exhibit Number - ---------------------------------------------------- This Previous Filing ----------------------------------------- Filing Commission Exchanges - ------ ---------- --------- 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 6/11/92
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) (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 1, 1994 11/8/94 12/2/94
4a(88) (d) 4 (d) 4 June 1, 1994 11/8/94 12/2/94
PSE&G - ---------------------------------------------------- Exhibit Number - ---------------------------------------------------- This Previous Filing ----------------------------------------- Filing Commission Exchanges - ------ ---------- --------- 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
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
4b (h) 7(12) (c) 4c(1) Indenture between PSE&G and 2/18/81 Federal Trust Company, as Trustee, (Midlantic National Bank, Successor Trustee) dated July 1, 1948, providing for 6% Debenture Bonds due 1998
4c (b) 4 (b) 4 Indenture of Trust between PSE&G 12/1/93 12/1/93 and Chase Manhattan Bank (National Association), as Trustee, providing for Secured Medium-Term Notes dated July 1, 1993
4d(1) (b) (c) Indenture between PSE&G and 2/23/95 2/23/95 First Fidelity Bank, National Association (now known as First Union National Bank), as Trustee, dated November 1, 1994, providing for Deferrable Interest Subordinated Debentures in Series
4d(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), as Trustee, dated September 1, 1995 providing for Deferrable Interest Subordinated Debentures in Series B
9 Inapplicable
10a(1) Directors' Deferred Compensation Plan
10a(2) Deferred Compensation Plan for Certain Employees
10a(3) Limited Supplemental Benefits Plan for Certain Employees
10a(4) Mid Career Hire Supplemental Retirement Plan
10a(5) Retirement Income Reinstatement Plan
10a(6) Long-Term Incentive Plan
10a(7) (c) 10a(20) (c) 10a(20) Management Incentive 2/26/97 2/26/97 Compensation Plan
PSE&G - ---------------------------------------------------- Exhibit Number - ---------------------------------------------------- This Previous Filing ----------------------------------------- Filing Commission Exchanges - ------ ---------- ---------
10a(8) (c) 10a(9) (c) 10a(9) Letter Agreement with 2/10/93 2/11/93 E. James Ferland dated April 16, 1986
10a(9) (c) 10a(12) (c) 10a(12) Letter Agreement with 2/10/93 2/11/93 Robert C. Murray dated December 17, 1991
10a(9)(i) Amendment to Letter Agreement with Robert C. Murray dated January 6, 1998
10a(10) (c) 10a(13) (c) 10a(13) Letter Agreement with 2/26/94 3/9/94 Patricia A. Rado dated March 24, 1993
10a(11) (c) 10a(14) (c) 10a(14) Letter Agreement, as amended, 2/23/95 2/23/95 with Leon R. Eliason dated September 14, 1994
10a(12) (d) 10a(15) (d) 10a(15) Letter Agreement with 8/14/95 8/14/95 Louis F. Storz dated July 7, 1995
10a(13) (d) 10a(16) (d) 10a(16) Letter Agreement with 8/14/95 8/14/95 Elbert C. Simpson dated May 31, 1995
10a(14) (d) 10a(17) (d) 10a(17) Letter Agreement with 11/14/95 11/14/95 Alfred C. Koeppe dated August 23, 1995
10a(15) (e) 10a(18) (e) 10a(18) Directors' Stock Plan 2/22/96 2/22/96
10a(16) Letter Agreement with Harold W. Keiser dated January 5, 1998
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
27 Financial Data Schedule