A portion of the increase in Operating Revenues for the year ended December 31, 2003, as compared to the same periods in 2002, was due to Power’s electric revenues no longer required to be eliminated in consolidation by PSEG subsequent to July 2002. Under the BGS contracts that terminated on July 31, 2002, Power sold energy directly to PSE&G, which in turn sold this energy to its customers. These revenues were properly recognized on each company’s stand-alone financial statements and were eliminated when preparing PSEG’s Consolidated Financial Statements. For the BGS contract period beginning August 1, 2002, Power entered into contracts with third parties who were direct suppliers of New Jersey’s EDCs and PSE&G purchased the energy for its customers’ needs from such third party suppliers. Due to this change in the BGS model, with the exception of a small portion of energy sold under the new contracts effective August 1, 2003, as discussed below, these revenues were no longer intercompany revenues and, therefore, were not eliminated in consolidation. For the year ended December 31, 2003, PSEG’s elimination related to the combined intercompany BGS and MTC revenues, decreased for that period by approximately $1.0 billion as compared to the prior year due primarily to this change. Also related to this change in the BGS model, PSE&G, in August 2002, began selling energy purchased under non-utility generation (NUG) contracts, which Power had previously paid PSE&G for at market prices, to the PJM, with the capacity purchased under these contracts being provided to the BGS suppliers on a pro-rata basis. As a result, for the year ended December 31, 2003, PSEG’s revenues related to NUG contracts increased by approximately $78 million.
For the year ended December 31, 2002, Operating Revenues increased by $1.3 billion or 19%, as compared to the same period in 2001, due primarily to Power’s BGS or commodity revenues subsequent to July 2002 not being eliminated in consolidation by PSEG. For the year ended December 31, 2002, PSEG’s elimination related to intercompany BGS and MTC revenues decreased by approximately $798 million as compared to 2001 due to this change. In addition, for the year ended December 31, 2002, PSEG’s revenues related to NUG contracts increased by approximately $82 million.
For the year ended December 31, 2003, as compared to the same period in 2002, Energy Costs increased approximately $2.7 billion or 72% due primarily to the fact that PSE&G no longer purchases
electric energy directly from Power, as discussed above in Operating Revenues. Amounts attributable to this change totaled approximately $1.1 billion between the year ended December 31, 2003 and 2002. Also contributing to the increase were an approximate $831 million net increase in gas costs, a $624 million increase at Power primarily related to increased power purchases and third-party wholesale electric supply contracts, discussed further below under Power, a $79 million increase in electric energy costs at PSE&G discussed further below under PSE&G and a $37 million increase at Energy Holdings, relating to projects at Global, discussed further below under Energy Holdings.
For the year ended December 31, 2002, as compared to the prior year, Energy Costs increased approximately $1 billion or 38% due primarily to the fact that PSE&G no longer purchased electric energy directly from Power, as discussed above in Operating Revenues, but rather from third party wholesalers. In 2001, and through July 31, 2002, PSE&G incurred energy costs related to electric energy transactions between it and Power. Accordingly, these costs were eliminated when preparing PSEG’s consolidated financial statements. Amounts attributable to this change totaled $880 million between the years ended December 31, 2002 and 2001.
The remaining increase was due to a $352 million increase at Power primarily related to increased energy purchases and third party wholesale electric supplier contracts, discussed further below in Power, and a $63 million increase at Energy Holdings, relating to acquisitions and projects going into operation at Global, discussed further below in Energy Holdings. These increases were partially offset by a $229 million decrease at PSE&G due primarily to decreased gas costs which resulted from lower demand, discussed further below in PSE&G.
Operation and Maintenance
For the year ended December 31, 2003, Operation and Maintenance expense increased $221 million or 12%, as compared to the year ended December 31, 2002, due to a $141 million increase at Power primarily due to the acquisition of the generating facilities in Connecticut in December 2002, higher accretion expense associated with the nuclear decommissioning liabilities, higher pension costs, higher nuclear refueling outage costs and higher real estate taxes, a $68 million increase at PSE&G due primarily to higher labor and fringe benefit costs, higher Demand Side Management (DSM) amortization, higher bad debt expense and storm-related costs, discussed further below under PSE&G. In addition, Operation and Maintenance expense increased at Energy Holdings by $8 million, due mainly to costs associated with projects at Global, as discussed further below under Energy Holdings.
For the year ended December 31, 2002, Operation and Maintenance expense increased $55 million or 3%, as compared to 2001 due to an increase of $35 million at Power primarily caused by scheduled outages at certain electric generating stations, and an increase at Energy Holdings of $46 million, primarily due to costs associated with acquisitions and projects going into operation. This increase was partially offset by a $14 million decrease at PSE&G primarily due to decreased labor and professional service costs, partially offset by higher DSM amortization, and a decrease in other charges of $12 million at PSEG.
Depreciation and Amortization
For the year ended December 31, 2003, Depreciation and Amortization decreased by $38 million or 7%, as compared to the same period in 2002. The decrease was primarily due to a $37 million decrease at PSE&G, as discussed further below.
For the year ended December 31, 2002, Depreciation and Amortization increased $70 million or 14%, as compared to 2001, primarily due to increases of $39 million at PSE&G, mainly due to a full period’s recognition of amortization of the regulatory asset related to stranded costs for securitization, $13 million at Power, primarily due to increases from Bergen 2 being placed into service in 2002 and a 2001 reversal of cost of removal reserves, and $13 million at Energy Holdings, primarily related to costs associated with acquisitions and projects going into operation.
58
Taxes Other Than Income Taxes
Taxes Other Than Income Taxes is comprised of the Transitional Energy Facility Assessment (TEFA) tax at PSE&G. Taxes Other Than Income Taxes increased $5 million or 4% for the year ended December 31, 2003, as compared to the same period in 2002. The change in the amount of the TEFA related to changes in PSE&G’s higher taxable sales in 2003. Legislation enacted in January 2002 freezes the TEFA unit rate surcharges at the 2001 levels through 2004 and then reduces the rates over the next three years, phasing out the TEFA by 2007.
Taxes Other Than Income Taxes increased $10 million or 8% in 2002, as compared to 2001. This increase was primarily due to a reduction of $6 million in the prior year’s TEFA recorded in 2001 and an increase of $3 million in the 2002 TEFA due to increased sales.
Other Income
For the year ended December 31, 2003, Other Income increased by $139 million, as compared to the year ended December 31, 2002, due primarily to a $148 million increase at Power. Power’s increase was primarily due to the recognition of realized gains and income related to Power’s Nuclear Decommissioning Trust (NDT) Fund.
Other Deductions
For the year ended December 31, 2003, Other Deductions increased by $21 million, as compared to the year ended December 31, 2002, due primarily an increase at Power of $77 million, partially offset by a decrease at Energy Holdings of approximately $72 million. Power’s increase was primarily due to the recognition of realized losses in Power’s NDT Fund. The decrease at Energy Holdings was largely attributable to lower foreign currency transaction losses, primarily related to U.S. Dollar debt in Argentina recorded in 2002.
For the year ended December 31, 2002, Other Deductions increased by $59 million as compared to 2001, primarily due to a $60 million increase in foreign currency transaction losses at Energy Holdings.
Interest Expense
For the year ended December 31, 2003, Interest Expense increased by $17 million or 2%, as compared to the year ended December 31, 2002, primarily due to a $40 million and $1 million increase at PSEG and Energy Holdings, respectively related to higher levels of debt outstanding, partially offset by decreases of $16 million and $8 million at PSE&G and Power, respectively, as discussed below.
For the year ended December 31, 2002, Interest Expense increased $43 million or 6% as compared to 2001 primarily due to higher amounts of debt outstanding at PSEG, Power and Energy Holdings used to support various projects and acquisitions and for other general corporate purposes, partially offset by decreases at PSE&G due to lower debt levels.
Income Taxes
For the year ended December 31, 2003, Income Taxes increased by $210 million or 83%, as compared to the year ended December 31, 2002, due primarily to higher pre-tax Income from Continuing Operations.
For the year ended December 31, 2002, Income Taxes decreased $119 million or 32% as compared to 2001 primarily due to lower pre-tax Income from Continuing Operations partially offset by adjustments in 2001 reflecting the conclusion of the 1994-96 Internal Revenue Service (IRS) audit.
Loss From Discontinued Operations
For the years ended December 31, 2003, 2002 and 2001, Energy Holdings recorded Losses From Discontinued Operations of $44 million, $49 million and $12 million, after-tax, respectively, as detailed further below under Energy Holdings.
59
Extraordinary Item
For the year ended December 31, 2003, PSE&G recorded an $18 million, after-tax, charge relating to its Electric Base Rate Case, as detailed further below under PSE&G.
Cumulative Effect of a Change in Accounting Principle
For the year ended December 31, 2003, Power recorded a $370 million, after-tax, benefit relating to the adoption of SFAS 143, as detailed further below under Power. For the year ended December 31, 2002, Energy Holdings recorded a $121 million, after-tax, charge due to goodwill impairments relating to the adoption of SFAS 142, as detailed further below under Energy Holdings.
PSE&G
Operating Revenues
PSE&G’s Operating Revenues increased by $821 million or 14% for the year ended December 31, 2003, as compared to the year ended December 31, 2002, due to a $758 million increase in gas revenues and a $63 million increase in electric revenues for the year ended December 31, 2003.
The increase in gas revenues primarily related to a $531 million increase due to price changes and $227 million due to higher sales volumes. The average cost of gas, which is passed through to customers, increased by 26% and total gas sales volumes increased by 10% due primarily to colder weather conditions.
The $63 million increase in electric revenues resulted from a $191 million increase due to price changes primarily relating to higher rates set in the BGS auction and the impact of the BPU order in its Electric Base Rate Case, both of which took effect on August 1, 2003. These were partially offset by the 4.9% rate reduction which was effective from August 1, 2002 through July 31, 2003, combined with increased sales of NUG power, primarily due to higher locational marginal pricing (LMP) in the PJM market. The increase related to price changes was partially offset by $129 million in lower sales volumes. While distribution sales volumes were higher by 1%, BGS volumes were down 7% due to the milder weather plus large customers switching to third party suppliers.
For the year ended December 31, 2002, PSE&G’s Operating Revenues decreased $172 million or 3%, as compared to the year ended December 31, 2001, primarily due to a decrease of $155 million in gas distribution revenues. This decrease was due to lower commodity revenues resulting from an average cost reduction of more than 10% in the cost of gas of approximately $125 million. Also contributing to the decrease were lower sales of approximately $88 million to interruptible customers resulting from the lower cost of gas and lower off-system sales revenues of approximately $26 million. These decreases were partially offset by increased gas base rates and increased volumes of approximately $75 million, primarily due to residential usage driven by favorable weather conditions and increased appliance service revenues of approximately $14 million. In addition, electric transmission and distribution revenues decreased $17 million, primarily due to a 4.9% rate reduction implemented in August 2002 under the Final Decision and Order in PSE&G’s rate unbundling, stranded costs and restructuring proceedings (Final Order) and approximately $123 million in rate reductions in February and August 2001 totaling 4%, which were recorded as reductions in MTC revenues. Also affecting 2002 performance were decreases of approximately $15 million in NUG sales at market prices, lower DSM sales due to revenue adjustments in 2001 of approximately $19 million and approximately $7 million in lower fiber optic attachment revenues due to unfavorable market conditions. These were offset by increased BGS revenues, primarily due to customers returning to PSE&G from third party suppliers of approximately $104 million, and higher distribution volumes for residential and commercial customers of approximately $37 million due to favorable weather conditions.
60
Operating Expenses
Energy Costs
For the year ended December 31, 2003, Energy Costs increased $737 million or 20%, as compared to the same period in 2002. Energy costs represent the cost of electric and gas purchases necessary to meet customer load. The differences between energy cost incurred and associated energy revenue is deferred for future collection or refund to customers.
Gas costs increased $658 million or 48% for the year ended December 31, 2003, as compared to the same period in 2002. The increase is a combination of a 26% increase in the price of gas ($527 million) and a 9% increase in sales volumes ($131 million).
Electric costs increased $79 million or 3% for the year ended December 31, 2003, as compared to the same period in 2002. The increase is the combination of higher prices for BGS and NUG purchases and higher MTC payments ($250 million) offset by lower BGS and NUG volumes ($170 million). As described above under revenues, BGS volumes are declining due to large customers switching to third party suppliers. NUG volumes are a function of the NUG generator and contract limits.
For the year ended December 31, 2002, PSE&G’s Energy Costs decreased $229 million or 6%, as compared to the year ended December 31, 2001, due primarily to a decrease in gas costs of approximately $230 million which resulted from lower commodity sales volumes of approximately $125 million, lower volumes of $88 million from interruptible customers due to lower rates and lower off-system sales volumes of approximately $18 million. Also contributing to the decrease were lower electric costs of $123 million due to the MTC rate reductions discussed above in Operating Revenues and decreased NUG energy sales of $15 million due to lower rates. Offsetting these decreases were increased electric energy costs of $104 million due to higher commodity sales volumes from customers returning from third party suppliers and a scheduled increase in the shopping credit and $30 million in higher amounts paid to Power relating to the amortization of the excess electric distribution depreciation reserve, which is a component of MTC.
Operation and Maintenance
Operation and Maintenance costs increased $68 million or 7% for the year ended December 31, 2003, as compared to the same periods in 2002. The increase primarily related to higher labor and fringe benefits of $49 million, due primarily to wage and incentive increases, the costs of an incentive program, higher pension costs and increased weather and storm-related expenses due to Hurricane Isabel and the extreme winter weather. Also contributing to the increase were higher bad debt expense of $10 million due to high winter gas sales and higher DSM costs of approximately $38 million relating to the increased sales, discussed above. DSM costs are deferred when incurred and amortized to expense when recovered in revenues. Partially offsetting these increases is a reduction in real estate tax expense of $18 million and the reversal of a $10 million reserve against a regulatory asset that is now being recovered.
Operation and Maintenance expense decreased $14 million or 1% in 2002, as compared to 2001, primarily comprised of decreased labor costs of approximately $9 million, decreased use of professional and contract services of approximately $7 million, $7 million in lower charges for administrative and general services and lower equipment rental of approximately $8 million. These decreases were offset by $14 million in increased DSM amortization and increased miscellaneous accounts receivable reserves of approximately $3 million.
Depreciation and Amortization
Depreciation and Amortization decreased $37 million or 9% for the year ended December 31, 2003, as compared to the year ended December 31, 2002, due primarily to a $52 million additional amortization of an excess electric distribution depreciation reserve and an $11 million decrease from the use of a lower book depreciation rate for electric distribution plant. Partially offsetting this decrease was a $13 million increase in depreciation expense due to increased plant in service and $9 million increase
61
in the amortization of the regulatory asset related to securitization, resulting from higher Securitization Transition Charge (STC) revenues.
Depreciation and Amortization expense increased $39 million or 11% in 2002, as compared to 2001, primarily due to $37 million in amortization of the regulatory asset related to stranded costs for securitization, $13 million in increased plant in service and $7 million in gas base rates for plant assets. Offsetting this increase is $22 million in amortization of an excess electric distribution depreciation reserve.
Taxes Other Than Income Taxes
Taxes Other Than Income Taxes is comprised of the Transitional Energy Facility Assessment (TEFA) tax at PSE&G. Taxes Other Than Income Taxes increased $5 million or 4% for the year ended December 31, 2003, as compared to the same period in 2002. The change in the amount of the TEFA related to changes in PSE&G’s higher taxable sales in 2003. Legislation enacted in January 2002 freezes the TEFA unit rate surcharges at the 2001 levels through 2004 and then reduces the rates over the next three years, phasing out the TEFA by 2007.
Taxes Other Than Income Taxes increased $10 million or 8% in 2002, as compared to 2001. This increase was primarily due to a reduction of $6 million in the prior year’s TEFA recorded in 2001 and an increase of $3 million in the 2002 TEFA due to increased sales.
Other Income
Other Income decreased $9 million or 60% for the year ended December 31, 2003, as compared to the same period in 2002, due primarily to equity return adjustments to regulatory assets of $11 million offset by $1 million in increased gains on the disposal of various electric transmission properties.
Other Income decreased $80 million or 84% in 2002, as compared to 2001, due primarily to $65 million related to PSEG’s settlement of an intercompany loan from PSE&G in 2001 and $16 million related to lower interest income on investments. This was offset by a $6 million gain on disposal of properties.
Interest Expense
Interest Expense decreased by $16 million or 4% for the year ended December 31, 2003, as compared to the same period in 2002. These decreases were due primarily to lower interest on long-term debt of $23 million for the year ended December 31, 2003, as compared to the same period in 2002, due to various maturities and redemptions of approximately $250 million. These decreases were partially offset by increased short-term interest expense of $2 million due to higher short-term debt balances outstanding due to increased working capital needs and $6 million in increased interest related to certain regulatory assets.
Interest Expense decreased $52 million or 11% for the year ended December 31, 2002, as compared to 2001, due to the $14 million in decreased debt redemptions, particularly of short-term debt in third quarter of 2001 and lower interest rates in 2002, $8 million related to the redemption of a floating rate note in 2001, the maturity of long-term debt of approximately $14 million, $3 million related to the repurchase of Pollution Control Bonds, the carrying costs on the deferred repair allowance of approximately $7 million and $2 million in New Jersey state accrued tax interest adjustments. These decreases were partially offset by higher securitization bond interest expense of approximately $7 million related to PSE&G Transition Funding LLC’s (Transition Funding) securitization bonds.
Income Taxes
Income Taxes increased by $14 million or 12% for the year ended December 31, 2003, as compared to the same period in 2002, due primarily to increases in pre-tax Income from Continuing Operations, offset by tax benefits recorded in 2003 attributable to the actual filing of the 2002 tax return.
62
Income taxes increased $26 million or 29% for the year ended December 31, 2002, as compared to 2001, primarily due to prior period tax adjustments recorded in 2001 reflecting the conclusion of the 1994-96 IRS audit.
Extraordinary Item
As discussed previously, included in the Electric Base Rate Case decision issued by the BPU was a refund related to revenues collected through the Societal Benefits Charge (SBC) for nuclear decommissioning. Because this amount reflects the final accounting for PSEG’s generation-related business pursuant to the four-year transition plan mandated by the Final Order, the adjustment has been recorded as an $18 million, after-tax, Extraordinary Item as required under Accounting Principles Board (APB) Opinion No. 30, “Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions” (APB 30) and SFAS No. 101, “Regulated Enterprises—Accounting for the Discontinuation of Application of FASB Statement No. 71”.
Power
Operating Revenues
For the year ended December 31, 2003, Operating Revenues increased approximately $2.0 billion, as compared to the year ended December 31, 2002, primarily due to an increase in gas supply revenues of approximately $1.3 billion. The increase is due to 2003 being the first full year of the Basic Gas Supply Service (BGSS) contract with PSE&G compared to a partial year in 2002 since the contract commenced in May 2002. Gas revenues for the first four months of 2003, totaled $1.1 billion. Also contributing to the increase in gas revenues were higher sales volumes and higher gas prices. Generation revenues also increased approximately $640 million for the year ended December 31, 2003, as compared to the same period in 2002, due to the increased supply obligations and new operations, as discussed above, as compared to the same period in 2002.
For the year ended December 31, 2002, Power’s Operating Revenues increased $1.2 billion, as compared to 2001, primarily due to the inclusion of $804 million of gas revenues relating to its BGSS contract and off-system gas sales resulting from the operations under the Gas Contracts transferred from PSE&G in May 2002. Also contributing to the increase was a $560 million increase in BGS related revenues, primarily due to the new BGS related revenues from third party wholesale electric suppliers which went into effect August 1, 2002 which was partially offset by lower MTC revenues of $98 million mostly due to a 4.9% rate reduction in August 2002 and two 2% rate reductions in August 2001 and February 2001. Also offsetting the increases were lower net trading revenues of approximately $104 million due to lower trading volumes and prices during 2002, as compared to 2001.
Operating Expenses
Energy Costs
For the year ended December 31, 2003, Energy Costs increased approximately $1.9 billion, as compared to the same period in 2002, primarily due to a $1.3 billion increase in gas costs due to the effect of a full year under the BGSS contract combined with higher gas sales volumes and prices and higher gas, oil and coal costs for generation. The increase in Energy Costs was also due to increased energy purchases on the spot market, as well as bilateral energy purchases, of approximately $413 million. Also, Power incurred an increase of approximately $116 million in network transmission expenses given that there were no payments for the first seven months in 2002. Additional charges associated with fuel and energy purchases to satisfy wholesale power agreements related to its Connecticut generating facilities totaled approximately $80 million for the year ended December 31, 2003.
63
For the year ended December 31, 2002, Power’s energy costs increased $1 billion compared to 2001 primarily due to increased energy purchase volumes and third party wholesale electric supplier contracts of approximately $297 million and $738 million of increased gas purchases to satisfy Power’s BGSS contract with PSE&G. Also contributing to the increase were higher network transmission expenses of $102 million. These higher expenses were partially offset by a $67 million decrease in NUG purchases. Additionally, the record capacity factor of its nuclear units enabled Power to produce low cost generation for a greater portion of its supply needs.
Operation and Maintenance
Operation and Maintenance expense increased $141 million or 18% for the year ended December 31, 2003 from the comparable period in 2002 due to costs of generating facilities in Connecticut acquired in December 2002 of $56 million, accretion expense of $24 million associated with the nuclear decommissioning liabilities, higher pension expense of $20 million, higher nuclear refueling outage costs of $24 million and other items.
For the period ended December 31, 2002, Operation and Maintenance expense increased $35 million or 5% as compared to the same period in 2001, due primarily to increases caused by scheduled outage work at electric generating stations.
Depreciation and Amortization
Depreciation and Amortization expense decreased $6 million or 6% for the year ended December 31, 2003 from the comparable periods in 2002. The net decrease was composed of lower depreciation costs of approximately $30 million due to the absence of decommissioning charges, which are no longer recorded as a result of the implementation of SFAS 143, partially offset by higher depreciation and amortization primarily related to generating facilities in Connecticut acquired in December 2002 and a higher asset base.
For the period ended December 31, 2002, Depreciation and Amortization expense increased $13 million or 14%, as compared to the same period in 2001, due primarily to increases from Bergen 2 being placed into service in 2002 and a 2001 reversal of cost of removal reserves.
Other Income
Other Income increased $148 million for the year ended December 31, 2003 from the comparable period in 2002, due primarily to the recording of realized gains and income on the NDT Fund.
Other Deductions
Other Deductions increased $77 million for the year ended December 31, 2003 from the comparable period in 2002, due primarily to the recording of realized losses on the NDT Fund.
Interest Expense
Interest Expense decreased by $8 million for the year ended December 31, 2003, as compared to the same period in 2002. Power incurred additional interest charges of $20 million due primarily to the new long-term financing of $600 million in June 2002, this increase was more than offset by lower interest expense on variable rate debt and other lower charges of approximately $15 million. Additionally, capitalized interest relating to various construction projects reduced interest expense by approximately $13 million for the year ended December 31, 2003, as compared to the same period in 2002.
Interest Expense decreased $21 million for the year ended December 31, 2002 from the comparable period in 2001 primarily due to improved financing rates and the repayment of intercompany notes, which resulted in a decrease in expense of $83 million. Offsetting these reductions were $94 million of increased interest expense associated with the issuance of the $2.4 billion of senior notes, including $600 million issued in 2002, $124 million of Pollution Control Notes and increased non-recourse financing
64
associated with the Lawrenceburg and Waterford construction projects, offset by increased capitalized interest relating to various construction projects of $32 million.
Income Taxes
Income taxes increased by $13 million or 4% for the year ended December 31, 2003, as compared to the same period in 2002. The increase was due primarily to higher pre-tax income.
Income Taxes increased $63 million or 25% for the year ended December 31, 2002, as compared to comparable period in 2001. The increase was due primarily to higher pre-tax income.
Cumulative Effect of Change in Accounting Principle
Upon adoption of SFAS 143 on January 1, 2003, Power recorded a Cumulative Effect of a Change in Accounting Principle in the amount of $370 million, after-tax. For additional information, see Note 4. Adoption of SFAS 143 of the Notes.
Energy Holdings
Operating Revenues
For the year ended December 31, 2003, Energy Holdings’ Operating Revenues increased $116 million or 19%, from the comparable period in 2002. Higher electric generation and distribution revenues at Global of $115 million and $6 million, respectively, was the primary reason for this increase. This increase was partially offset by lower revenues at Resources of $10 million, as discussed below.
For the year ended December 31, 2002, Energy Holdings’ Operating Revenues increased $155 million or 34%, from the comparable period in 2001. Higher electric generation and distribution revenues at Global of $116 million and $56 million, respectively, was the primary reason for this increase. Also contributing to this increase was higher revenues at Resources of $8 million. Partially offsetting the increase was a lower gain from partnership withdrawal relating to EPCP of $28 million compared to the same period in 2001. In 2001, Global withdrew from its interest in EPCP in exchange for a series of payments through 2005, provided certain operating contingencies are met.
Global
For the year ended December 31, 2003, Global’s Operating Revenues increased $124 million or 35% from the comparable period in 2002. Contributing to the increase was a $47 million increase from Skawina CHP (Skawina), a generation facility in Poland, in which Global purchased a majority ownership in June 2002, a $38 million increase from Salalah, a generation facility in Oman, which began commercial operation in May 2003 and a $28 million increase in revenue from GWF Energy LLC (GWF Energy). This increase in revenue at GWF Energy was due to the Henrietta and Tracy Peaking Plants becoming operational in the second quarter of 2003 and 2002, respectively and consolidation of GWF Energy from the fourth quarter 2002 to the fourth quarter 2003. In the second half of 2002, Global’s ownership of GWF Energy exceeded 75% and under the operating agreement Global gained a controlling interest. Accordingly, Global consolidated GWF Energy for the first three quarters of 2003 as compared to the first three quarters of 2002 when it was accounted for under the equity method. Global recommenced recording GWF Energy under the equity method in the fourth quarter of 2003 when its ownership was reduced to less than 75%. Also contributing to the increase was a $19 million increase in revenue from Sociedad Austral de Electricidad S.A. (SAESA), a distribution facility in Chile, due to improved sales volume compared to same period in 2002. These increases were partially offset by the absence of $19 million in revenue from Empresa Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA), in Argentina, which was abandoned in 2003.
For the year ended December 31, 2002, Global’s, Operating Revenues increased $148 million or 73% from the comparable period in 2001. The increase was primarily due to the acquisition in the second half of 2001 of SAESA and Electroandes, a Peruvian hydroelectric generation and transmission company, resulting in increased revenue of $97 million and $42 million, respectively. Also contributing
65
was $49 million related to the increase in revenues at Skawina, in which Global purchased a majority ownership in the second quarter of 2002. Revenues increased at the GWF Energy peaker plants by $25 million as the Hanford and Henrietta Peaker Plants became operational in the third quarter of 2001 and second quarter of 2002, respectively. Partially offsetting these increases was a decrease in revenue of $37 million at EDEERSA due to the economic crisis in Argentina. In addition, in 2001, Global recorded $76 million for the gain on the sale and withdrawal from the EPCP compared to the $47 million recorded for the withdrawal in 2002, resulting in a reduction of approximately $29 million.
Resources
For the year ended December 31, 2003, Resources’ Operating Revenues decreased $10 million or 4% from the comparable period in 2002. This decrease was primarily related to a $45 million net decrease in leveraged lease income and a $6 million decrease in realized income due to the termination of two leveraged leases in December 2002. Partially offsetting this decrease was the absence of an other than temporary impairment of non-publicly traded equity securities held within the leveraged buyout funds of $42 million that was recorded in 2002.
For the year ended December 31, 2002, Resources’ Operating Revenues increased $8 million from the comparable period in 2001. This increase was primarily due to $45 million from higher leveraged lease income. The increase was mostly offset by lower net investment results of $39 million, of which $37 million resulted from other than temporary impairments of non-publicly traded equity securities within certain leveraged buyout funds and other investments, and $9 million resulted from a net decrease in the gains on the sale of properties subject to leveraged leases. For further discussion of other than temporary impairments, see Note 16. Risk Management—Equity Securities of the Notes. There was also a net increase of $6 million associated with the change in the carrying value of publicly traded equity securities in certain leveraged buyout funds. The values of the publicly traded equity securities in 2002 decreased by $10 million compared to the same period in 2001.
Of the $45 million increase in leveraged lease income in 2002, $29 million resulted from a gain due to a recalculation of certain leveraged leases. A change in an essential assumption which affects the estimated total net income over the life of a leveraged lease requires a recalculation of the leveraged lease, from inception, using the revised information. The change in the net investment in the leveraged leases is recognized as a gain or loss in the year the assumption is changed. The change in assumption which occurred was related to a change in New Jersey tax rates applied in the leveraged lease calculations. This was due to the restructuring of Resources from a corporation to a limited liability company, which resulted in the ability to more efficiently match state tax expenses of an affiliate company with the state tax benefits associated with Resources’ lease portfolio. The remaining $16 million increase in leveraged lease income was due to additional investments in leveraged lease transactions in 2002 and 2001.
Operating Expenses
For the year ended December 31, 2003, Energy Holdings’ Operating Expenses decreased $450 million or 55% from the comparable period in 2002. This decrease was primarily due to Global’s $511 million write-down of investments in 2002, primarily in Argentina, as well as decreased operating expenses in 2003 compared to the same period in 2002. Also contributing were decreased expenses at Global of $28 million related to the abandonment of Global’s Argentine investments combined with lower labor and administrative costs due to reduced headcounts. Partially offsetting this decrease was an increase in operating expenses of $42 million from Skawina and $28 million from Salalah. Also offsetting the decrease was an increase of approximately $16 million from GWF Energy, primarily due to the consolidation of this project beginning in the fourth quarter of 2002.
For the year ended December 31, 2002, Energy Holdings’ Operating Expenses increased $626 million from the comparable period in 2001, primarily due to the investment write-down in 2002 discussed above. In addition to the write-down, Operating Expenses, increased $115 million for the year ended 2002 compared to 2001 primarily due to an increase at SAESA of $64 million and Empresa de Electricidad de los Andes S.A. (Electroandes) of $20 million, two acquisitions that occurred in the
66
second half of 2001 and Skawina of $45 million which became operational in 2002. Partially offsetting these increases were decreased operating expenses at EDEERSA which was accounted for under the equity method of accounting for the second half of 2002.
Income from Equity Method Investments
For the year ended December 31, 2003, Energy Holdings’ Income from Equity Method Investments decreased by $5 million or 4% from the comparable period in 2002. This decrease was primarily due to lower earnings in 2003 of $17 million at GWF Energy, which was recorded as a consolidated company for the first three quarters in 2003, as well as decreased earnings at Chilquinta of $4 million. Partially offsetting this decrease was improved earnings at TIE of $14 million related to PPA’s entered into in early 2003 and improved market conditions in Texas.
For the year ended December 31, 2002, Energy Holdings’ Income from Equity Method Investments decreased by $59 million or 33% from the comparable period in 2001. The decrease is due to lower earnings from Global’s Argentine investments in 2002 of $26 million due to the economic crisis in Argentina, which led to Global’s abandonment of its assets in Argentina. The decrease also resulted from reduced earnings of $21 million at the GWF facilities and a $17 million decrease at TIE, both due to lower energy prices in those markets. Also contributing to this decrease were operational losses at Prisma of $5 million and reduced earnings at PPN of $3 million. Partially offsetting these decreases were increased earnings at GWF Energy of $24 million related to the Hanford and Henrietta Peaker Plants, which became operational in the third quarter of 2001 and second quarter of 2002, respectively.
Other Income
For the year ended December 31, 2003, Energy Holdings’ Other Income decreased by $6 million from the comparable period in 2002. This decrease is primarily due to the absence of favorable changes in fair value mainly relating to foreign exchange contracts held by Energy Holdings.
For the year ended December 31, 2002, Energy Holdings’ Other Income increased $22 million, from the comparable period in 2001. This increase was primarily driven by $11 million of net gains on foreign exchange contracts from SAESA, with no comparable amount in 2001, and a $14 million gain on the early retirement of debt in 2002.
Other Deductions
For the year ended December 31, 2003, Energy Holdings’ Other Deductions decreased by $72 million from the comparable period in 2002. The decrease was largely due to a $77 million foreign currency transaction loss during 2002, which primarily related to Global’s Argentine investments.
For the year ended December 31, 2002, Energy Holdings’ Other Deductions increased $60 million from the comparable period in 2001 primarily due to higher foreign currency exchange losses, primarily due to the remeasuring of the U.S. Dollar denominated debt relative to the devaluing Argentine Peso, which resulted in a loss of $66 million.
Interest Expense
For the year ended December 31, 2003, Energy Holdings’ Interest Expense increased by $1 million or 1% from the comparable period in 2002.
For the year ended December 31, 2002, Energy Holdings’ Interest Expense increased $34 million or 19% from the comparable period in 2001. The increase was the result of issuing $135 million of 8.625% Senior Notes in July 2002 and an increase in project level debt at Global. The increase was partially offset by the repayments of borrowings under the revolving credit facilities.
Income Taxes
For the year ended December 31, 2003, Energy Holdings’ Income Taxes from continuing operations increased $203 million from the comparable period in 2002. This increase is primarily
67
attributed to increased pre-tax income for the year ended December 31, 2003, as compared to pre-tax losses in the same period in 2002. The pre-tax losses in 2002 resulted from the write-off of $511 million, primarily related to investments in Argentina.
For the year ended December 31, 2002, Energy Holdings had Income Tax benefits of $144 million, compared to $58 million of Income Tax Expense in 2001. The tax benefits in 2002 resulted primarily from the write-offs recorded during 2002, which resulted in a pre-tax loss.
Loss From Discontinued Operations
CPC
Global has a 60% ownership interest in CPC which owns and operates the Rades Power Plant, an electric generation facility located in Tunisia. In December 2003, Global entered into a purchase and sale agreement related to its majority interest in CPC for approximately $43 million, plus interest. Global has reduced its carrying value of CPC to its fair value less cost to sell and recorded a loss on disposal for the year ended December 31, 2003 of $23 million (after tax). The results of operations of these discontinued operations for the years ended December 31, 2003, 2002 and 2001 yielded additional (after tax) losses of $1 million and income of $1 million and $4 million, respectively. See Note 5. Discontinued Operations of the Notes.
Energy Technologies
Energy Holdings reduced the carrying value of the investments in the 11 HVAC/mechanical operating companies to their fair value less costs to sell, and recorded a loss on disposal for the year ended December 31, 2002 of $20 million, net of $11 million in taxes.
During 2003, Energy Holdings re-evaluated the carrying value of Energy Technologies’ assets and liabilities and determined that market conditions required an additional write-down to fair value less cost to sell. Energy Holdings recorded an additional loss on disposal of Energy Technologies of $9 million, net of a $3 million tax benefit.
In September 2003, Energy Holdings completed the sale of the remaining companies of Energy Technologies. The results of operations of these discontinued operations for the years ended December 31, 2003, 2002 and 2001 yielded additional (after-tax) losses of $11 million, $21 million and $23 million, respectively. See Note 5. Discontinued Operations of the Notes.
Tanir Bavi
In the fourth quarter of 2002, Global sold its 74% interest in Tanir Bavi, a 220 MW barge mounted, combined-cycle generating facility in India. Global reduced the carrying value of Tanir Bavi to the contracted sales price of $45 million and recorded a loss on disposal of $14 million (after-tax) for the year ended December 31, 2002. The operating results of Tanir Bavi for the years ended December 31, 2002 and December 31, 2001 yielded (after tax) income of $5 million and $7 million, respectively. See Note 5. Discontinued Operations of the Notes.
Cumulative Effect of Change in Accounting Principle
In 2002, Energy Holding finalized the evaluation of the effect of adopting SFAS 142 on its recorded amount of goodwill. Under this standard, PSEG was required to complete an impairment analysis of its recorded goodwill and record any resulting impairment. The total amount of goodwill impairments was $121 million, net of tax of $66 million and was comprised of $36 million (after-tax) at EDEERSA, $35 million (after-tax) at RGE, $32 million (after-tax) at Energy Technologies and $18 million (after-tax) at Tanir Bavi. All of the goodwill on these companies, other than RGE, was fully impaired. In accordance with SFAS 142, this impairment charge was recorded as of January 1, 2002 as a component of the Cumulative Effect of a Change in Accounting Principle and is reflected in the Consolidated Statement of Operations for the year ended December 31, 2002. See Note 3. Recent Accounting Standards of the Notes.
68
In 2001, Energy Holdings adopted SFAS 133, which established accounting and reporting standards
for derivative instruments. Energy Holdings recorded an after-tax gain of $10 million as a result of adopting SFAS 133.
Other
Global
The following table summarizes the net contribution to Earnings Before Interest and Taxes (EBIT) by Global’s projects in the following regions for the years ended December 31, 2003, 2002 and 2001.
| | For the Years Ended
December 31, | |
Earnings Before Interest and Taxes (EBIT) | | 2003 | | 2002 | | 2001 | |
| | (Millions) | |
North America | | $ | 87 | | $ | 76 | | $ | 87 | |
Latin America | | | | | | | | | | |
Chilquinta | | | 28 | | | 33 | | | 32 | |
Electroandes | | | 28 | | | 25 | | | (1 | ) |
LDS | | | 19 | | | 16 | | | 16 | |
RGE | | | 17 | | | 6 | | | 5 | |
SAESA | | | 55 | | | 51 | | | 21 | |
Other(A) | | | 1 | | | (555 | ) | | 46 | |
Total Latin America | | | 148 | | | (424 | ) | | 119 | |
Asia Pacific | | | 9 | | | 7 | | | 9 | |
Europe | | | 24 | | | (18 | ) | | (3 | ) |
India | | | 9 | | | 1 | | | 4 | |
EBIT | | | 277 | | | (358 | ) | | 216 | |
Interest Expense(B) | | | (119 | ) | | (118 | ) | | (81 | ) |
Income (Loss) Before Income Taxes | | $ | 158 | | $ | (476 | ) | $ | 135 | |
______________
| (A) | Primarily relates to investments in Argentina which were abandoned in 2002. |
| (B) | For the consolidated projects above, interest associated with nonrecourse debt totaled $31 million, $26 million and $13 million for the years ended December 31, 2003, 2002 and 2001, respectively. |
For additional information, see Note 23. Financial Information by Business Segment of the Notes.
LIQUIDITY AND CAPITAL RESOURCES
The following discussion of liquidity and capital resources is on a consolidated basis for PSEG, noting the uses and contributions of PSEG’s three direct operating subsidiaries, PSE&G, Power and Energy Holdings.
Financing Methodology
PSEG, PSE&G, Power and Energy Holdings
Capital requirements for PSE&G, Power and Energy Holdings are met through liquidity provided by internally generated cash flow and external financings. Although earnings growth has moderated, PSEG expects to be able to fund existing commitments, reduce debt and meet dividend requirements using internally generated cash. PSEG, Power and Energy Holdings from time to time make equity contributions or otherwise provide credit support to their respective direct and indirect subsidiaries to provide for part of their capital and cash requirements, generally relating to long-term investments. PSEG does not intend to contribute additional equity to Energy Holdings.
69
At times, PSEG utilizes intercompany dividends and intercompany loans (except however, that PSE&G may not, without prior BPU approval, make loans to its parent or to affiliates that are not its direct subsidiaries) to satisfy various subsidiary or parental needs and efficiently manage short-term cash. Any excess funds are invested in short-term liquid investments.
External funding to meet PSEG’s and PSE&G’s needs and a majority portion of the requirements of Power and Energy Holdings consist of corporate finance transactions. The debt incurred is the direct obligation of those respective entities. Some of the proceeds of these debt transactions are used by the respective obligor to make equity investments in its subsidiaries.
As discussed below, depending on the particular company, external financing may consist of public and private capital market debt and equity transactions, bank revolving credit and term loans, commercial paper and/or project financings. Some of these transactions involve special purpose entities (SPEs), formed in accordance with applicable tax and legal requirements in order to achieve specified beneficial financial advantages, such as favorable legal liability treatment. PSEG consolidates SPE’s, as applicable, in accordance with Financial Accounting Standards Board (FASB) Interpretation No. 46, “Consolidation of Variable Interest Entities (VIEs)”(FIN 46). See Note 3. Recent Accounting Standards of the Notes.
The availability and cost of external capital could be affected by each entity’s performance, as well as by the performance of their respective subsidiaries and affiliates. This could include the degree of structural separation between PSEG and its subsidiaries and the potential impact of affiliate ratings on consolidated and unconsolidated credit quality. Additionally, compliance with applicable financial covenants will depend upon future financial position and levels of earnings and net cash flows, as to which no assurances can be given.
Over the next several years, PSEG, PSE&G, Power and Energy Holdings may be required to extinguish or refinance maturing debt and to the extent there is not sufficient internally generated funds may incur additional debt and/or provide equity to fund investment activities. Any inability to obtain required additional external capital or to extend or replace maturing debt and/or existing agreements at current levels and reasonable interest rates may adversely affect PSEG’s, PSE&G’s, Power’s and Energy Holdings' respective financial condition, results of operations and net cash flows.
From time to time, PSEG, PSE&G, Power and Energy Holdings may repurchase portions of their respective debt securities using funds from operations, asset sales, commercial paper, debt issuances, equity issuances and other sources of funding and may make exchanges of new securities, including common stock, for outstanding securities. Such repurchases may be at variable prices below, at or above prevailing market prices and may be conducted by way of privately negotiated transactions, open-market purchases, tender or exchange offers or other means. PSEG, PSE&G, Power and Energy Holdings may utilize brokers or dealers or effect such repurchases directly. Any such repurchases may be commenced or discontinued at any time without notice.
Power and Energy Holdings
A portion of the financing for Global’s projects and investments is normally provided by non-recourse project financing transactions. These consist of loans from banks and other lenders that are typically secured by project assets and/or cash flows. Power’s projects in Ohio and Indiana currently have similar financing. Nonrecourse transactions generally impose no material obligation on the parent-level investor to repay any debt incurred by the project borrower. The consequences of permitting a project-level default includes loss of any invested equity by the parent. However, in some cases, certain obligations relating to the investment being financed, including additional equity commitments, may be guaranteed by Global, Energy Holdings and/or Power for their respective subsidiaries. PSEG has not currently provided any guarantees or credit support to Power and does not provide guarantees or credit support to Energy Holdings or its subsidiaries.
70
Operating Cash Flows
PSEG
For the year ended December 31, 2003, PSEG’s operating cash flow increased by approximately $135 million from $1.3 billion to $1.4 billion, as compared to the year ended December 31, 2002 due to net increases from its subsidiaries as discussed below.
PSE&G
PSE&G’s operating cash flow decreased approximately $225 million from $830 million to $605 million for the year ended December 31, 2003, as compared to the year ended December 31, 2002. The 2002 operating cash flow was abnormally high primarily due to the sale of the gas inventory totaling approximately $415 million in 2002, $183 million of which related to PSE&G’s sale of the gas supply business to Power. Working capital needs also increased during 2003 due to changes in the over/under collected balances of PSE&G’s energy clauses and increased Accounts Receivable balances resulting from higher billings.
Power
Power’s operating cash flow increased approximately $163 million from $417 million to $580 million for the year ended December 31, 2003, as compared to the year ended December 31, 2002. The 2002 operating cash flow was abnormally low, due to the purchase of the gas contracts from PSE&G in May 2002 for approximately $183 million and gas storage volume requirements, including higher gas prices, to meet its BGSS and generation requirements in 2002. However, higher gas prices in 2003 led to higher working capital requirements for fuels than in 2002.
Energy Holdings
Energy Holdings’ operating cash flow increased approximately $188 million from $108 million to $296 million for the year ended December 31, 2003, as compared to the year ended December 31, 2002. This increase is primarily related to increased earnings and realization of deferred tax assets, partially offset by a $115 million tax payment in the first quarter of 2003 related to two leveraged lease transactions at Resources with affiliates of TXU-Europe that were terminated in the fourth quarter of 2002 and other miscellaneous items. Also, Global received a $137 million return of capital from its investment in GWF Energy that is reflected in financing activities rather than operating cash flows as that project had been consolidated at that time.
PSEG, PSE&G, Power and Energy Holdings
The cash flow metric PSEG uses to manage the business is cash available to pay down recourse debt (i.e., excess cash). This metric is calculated by taking PSEG’s operating cash flows, less investing activities, less dividends and adjusted for the operating and investing activities of consolidated subsidiaries of Energy Holdings that do not affect its liquidity position, such as capital expenditures made by SAESA that are funded locally, rather than through Global.
In 2003, PSEG did not achieve its target of up to $200 million in excess cash due to increased working capital requirements of about $200 million at PSE&G and Power driven by increases in gas prices and because of the delay of securitization financing at PSE&G. In the future, PSEG expects operating cash flows to be sufficient to fund the majority of future capital requirements and dividend payments. PSEG expects that cash available to pay down recourse debt will increase substantially in the later part of its business plan as capital expenditures are expected to decrease materially after 2005 when the current construction program at Power is completed.
71
Debt Covenants
PSEG, PSE&G, Power and Energy Holdings
PSEG’s, PSE&G’s, Power’s and Energy Holdings’ respective credit agreements generally contain customary provisions under which the lenders could refuse to advance loans in the event of a material adverse change in the borrower’s business or financial condition.
As explained in detail below, some of these credit agreements also contain maximum debt-to-equity ratios, minimum cash flow tests and other restrictive covenants and conditions to borrowing. Compliance with applicable financial covenants will depend upon the respective future financial position, level of earnings and cash flows of PSEG, PSE&G, Power and Energy Holdings, as to which no assurances can be given. The ratios presented below are for the benefit of the investors of the related securities to which the covenants apply. They are not intended as a financial performance or liquidity measure. The debt underlying the preferred securities of PSEG, which is presented in Long-Term Debt in accordance with FIN 46, is not included as debt when calculating these ratios, as provided for in the various credit agreements.
PSEG
Financial covenants contained in PSEG’s credit facilities include a ratio of debt (excluding non-recourse project financings, securitization debt and debt underlying preferred securities and including commercial paper and loans, certain letters of credit and similar instruments) to total capitalization covenant. This covenant requires that at the end of any quarterly financial period, such ratio not be more than 70.0%. As of December 31, 2003, PSEG’s ratio of debt to capitalization (as defined above) was 57.0%. PSEG expects to continue to meet the financial covenants necessary to maintain its credit ratings.
PSE&G
Financial covenants contained in PSE&G’s credit facilities include a ratio of long-term debt (excluding securitization debt and long-term debt maturing within one year) to total capitalization covenant. This covenant requires that at the end of any quarterly financial period, such ratio will not be more than 65.0%. As of December 31, 2003, PSE&G’s ratio of long-term debt to total capitalization (as defined above) was 54.5%.
In addition, under its First and Refunding Mortgage (Mortgage), PSE&G may issue new First and Refunding Mortgage Bonds against previous additions and improvements, provided that its ratio of earnings to fixed charges calculated in accordance with its Mortgage is at least 2:1, and/or against retired Mortgage Bonds. As of December 31, 2003, PSE&G’s Mortgage coverage ratio was 3:1 and the Mortgage would permit up to approximately $1.5 billion aggregate principal amount of new Mortgage Bonds to be issued against previous additions and improvements.
PSEG and Power
Financial covenants contained in the PSEG/Power joint and several credit facility include a ratio of debt to total capitalization for each specific borrower. Where PSEG is the borrower, the covenant described above in PSEG is applicable. Where Power is the borrower, a debt (excluding non-recourse project financings and including loans, certain letters of credit and similar instruments) to total capitalization, adjusted for the $986 million Basis Adjustment (see Consolidated Balance Sheets), covenant applies. This covenant requires that at the end of any quarterly financial period, such ratio will not exceed 65.0%. As of December 31, 2003, Power’s ratio of debt to capitalization (as defined above) was 44.7%.
Energy Holdings
In April 2003, Energy Holdings issued $350 million of Senior Notes which contain financial covenants that include debt incurrence tests consisting of a debt service coverage test and a ratio of
72
consolidated recourse indebtedness to recourse capitalization test, which covenants require that Energy Holdings will not incur additional consolidated recourse indebtedness, other than certain permitted indebtedness, unless, on a pro forma basis, giving effect to the incurrence of the additional consolidated recourse indebtedness: (i) the debt service coverage ratio would be at least 2 to 1 and (ii) the ratio of consolidated recourse indebtedness to recourse capitalization would not exceed 0.60 to 1. Certain permitted indebtedness, such as permitted refinancings and borrowings are excluded from the requirements under this test. The provisions of the Senior Notes also restrict Energy Holdings from selling assets with a net book value greater than 10% of its assets in any four consecutive quarters, unless the proceeds are used to reduce debt of Energy Holdings or its subsidiaries or are retained by Energy Holdings.
Energy Holdings entered into a new $200 million three-year bank revolving credit agreement in October 2003 with a covenant requiring the ratio of Earnings Before Interest, Taxes, Depreciation and Amortization (EBITDA) to fixed charges to be greater than 1.75x. As of December 31, 2003, Energy Holdings’ coverage of this covenant was 2.60x. Additionally, Energy Holdings must maintain a ratio of net debt to EBITDA of less than 5.25. As of December 31, 2003, Energy Holdings’ ratio under this covenant was 3.87. Energy Holdings is a co-borrower under this facility with Global and Resources, which are joint and several obligors. The terms of the agreement include a pledge of Energy Holdings’ membership interest in Global, restrictions on the use of proceeds related to material sales of assets and the satisfaction of certain financial covenants. Cash proceeds from asset sales in excess of 5% of total assets of Energy Holdings during any 12-month period must be used to repay any outstanding amounts under the credit agreement. Cash proceeds in excess of 10% must be retained by Energy Holdings or used to repay the debt of Energy Holdings, Global or Resources.
Energy Holdings has been informed that its indirect subsidiary, CPC, has incurred a non-payment related default under its non-recourse project financing. There are no cross-defaults associated with this technical default. CPC is seeking a waiver and although no acceleration of the approximately $160 million of outstanding project debt is expected, no assurances can be given.
Cross Default Provisions
PSEG, PSE&G, Power and Energy Holdings
The PSEG credit agreements contain default provisions under which a default by it, PSE&G or Power in an aggregate amount of $50 million or greater would result in a default and the potential acceleration of payment under those agreements.
PSEG’s bank credit agreements and note purchase agreements (collectively, Credit Agreements) related to its private placement of debt contain cross default provisions under which certain payment defaults by PSE&G or Power, certain bankruptcy events relating to PSE&G or Power, the failure by PSE&G or Power to satisfy certain final judgments or the occurrence of certain events of default under the financing agreements of PSE&G or Power, would each constitute an event of default under the PSEG Credit Agreements. It is also an event of default under the PSEG Credit Agreements if PSE&G or Power ceases to be wholly-owned by PSEG.
PSEG removed Energy Holdings from all cross default provisions effective with the cancellation of Energy Holdings’ $495 million revolving credit agreement in September 2003. In October 2003, Energy Holdings entered into a new three-year bank revolving credit agreement in the amount of approximately $200 million that does not include PSEG-level covenants other than the maintenance of ownership of at least 80% of the capital stock of Energy Holdings.
PSE&G
PSE&G’s Mortgage has no cross-defaults. The PSE&G Medium-Term Note Indenture has a cross-default to the PSE&G Mortgage. The credit agreements have cross-defaults under which a default by PSE&G in the aggregate of $50 million or greater would result in an event of default and the potential acceleration of payment under the credit agreements.
73
Power
The Power Senior Debt Indenture contains a default provision under which a default by it, Nuclear, Fossil or ER&T in an aggregate amount of $50 million would result in an event of default and the potential acceleration of payment under the indenture. There are no cross-defaults within Power’s indenture from PSEG, Energy Holdings or PSE&G.
Energy Holdings
Energy Holdings’ Credit Agreement and Senior Note Indenture contain default provisions under which a default by it, Resources or Global in an aggregate amount of $25 million or greater would result in an event of default and the potential acceleration of payment under those agreements or the Indenture.
Ratings Triggers
PSEG, PSE&G, Power and Energy Holdings
The debt indentures and credit agreements of PSEG, PSE&G, Power and Energy Holdings do not contain any material “ratings triggers” that would cause an acceleration of the required interest and principal payments in the event of a ratings downgrade. However, in the event of a downgrade, any one or more of the affected companies may be subject to increased interest costs on certain bank debt and certain collateral requirements.
PSE&G
In accordance with the BPU credit requirements under the BGS contracts that PSE&G enters into with suppliers, PSE&G is required to maintain an investment grade credit rating. If PSE&G were to lose its investment grade rating, PSE&G would be required to file with the BPU a plan to assure continued payment for the BGS requirements of its customers.
Power
In connection with its energy marketing and trading activities, Power must meet certain credit quality standards required by counterparties. If Power loses its investment grade credit rating, ER&T would have to provide credit support (letters of credit or cash), which would materially impact the cost of its energy trading activities. In addition, all master agreements and other supply contracts contain margin and/or other collateral requirements that, as of December 31, 2003, could require Power to post additional collateral of approximately $377 million if Power were to lose its investment grade credit rating and all counterparties to contracts in which Power is “out-of-the money” were entitled to and called for collateral. Providing this credit support would increase Power’s costs of doing business and could limit Power’s ability to successfully conduct its energy trading operations. See Note 17. Commitments and Contingent Liabilities of the Notes.
Energy Holdings
Energy Holdings and Global posted letters of credit of approximately $9 million and $35 million for certain of their equity commitments in September 2003 and October 2003, respectively, as a result of Energy Holdings’ ratings falling below investment grade. The letters of credit totaling $35 million issued in October 2003 have been reduced to approximately $10 million as of December 31, 2003. Under existing agreements, no further letters of credit will need to be posted should there be a future downgrade.
74
Credit Ratings
PSEG, PSE&G, Power and Energy Holdings
The current ratings of securities of PSEG and its subsidiaries are shown below and reflect the respective views of the rating agencies. Any downward revision or withdrawal may adversely affect the market price of PSEG’s, PSE&G’s, Power’s and Energy Holdings’ securities and serve to increase those companies’ cost of capital and limit their access to capital. All ratings have a stable outlook unless otherwise noted. (N) denotes a negative outlook. There is no assurance that the ratings will continue for any given period of time or that they will not be revised by the rating agencies, if, in their respective judgments, circumstances so warrant. Each rating given by an agency should be evaluated independently of the other agencies’ ratings. The ratings should not be construed as an indication to buy, hold or sell any security.
The financial objectives for PSEG include maintaining credit ratings for each of PSEG, PSE&G, Power and Energy Holdings. To accomplish this, PSEG expects to improve its funds from operations and interest coverage ratios and continue to lower its leverage ratio over the planning period. Failure to meet these targets could lead to a lower credit rating.
In the fourth quarter of 2003, Standard & Poor’s (S&P) affirmed the corporate credit ratings of PSEG, PSE&G and Power, and downgraded the credit rating of Energy Holdings from BBB- to BB-. Moody’s Investors Service (Moody’s) similarly has recently affirmed the credit ratings of PSEG, PSE&G and Power and downgraded Energy Holdings’ credit rating from Baa3 to Ba3. These actions concluded the review for possible downgrade of Power and Energy Holdings that was initiated by Moody’s in June 2003. On September 26, 2003, Moody’s confirmed PSEG’s P2 commercial paper rating. The current ratings of securities of PSEG and its subsidiaries are shown below:
| | Moody’s(A) | | S&P(B) | | Fitch(C) | |
PSEG: | | | | | | | |
Preferred Securities | | Baa3(N) | | BB+ | | BBB(N) | |
Commercial Paper | | P2(N) | | A2 | | Not Rated | |
PSE&G: | | | | | | | |
Mortgage Bonds | | A3 | | A– | | A(N) | |
Preferred Securities(D) | | Baa3 | | BB+ | | BBB+(N) | |
Commercial Paper | | P2 | | A2 | | F1 | |
Power: | | | | | | | |
Senior Notes | | Baa1 | | BBB | | BBB+ | |
Energy Holdings: | | | | | | | |
Senior Notes | | Ba3(N) | | BB– | | BBB– | |
______________
| (A) | Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P-1 (highest) to NP (lowest) for short-term securities. |
| (B) | S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A-1 (highest) to D (lowest) for short-term securities. |
| (C) | Fitch ratings range from AAA (highest) to D (lowest) for long-term securities and F-1 (highest) to D (lowest) for short-term securities. |
| (D) | Rating for PSE&G Cumulative Preferred Stock without Mandatory Redemption. |
75
Short-Term Liquidity
PSEG, PSE&G, Power and Energy Holdings
As of December 31, 2003, PSEG and its subsidiaries had a total of approximately $1.9 billion of committed credit facilities with approximately $1.5 billion of available liquidity under these facilities, supplemented by cash investments of approximately $200 million. In addition to this amount, PSEG and PSE&G have access to certain uncommitted credit facilities. Neither PSEG nor PSE&G had any loans outstanding under these facilities as of December 31, 2003. Each facility is restricted to availability and use to the specific companies as listed below.
Company | | Expiration
Date | | Total
Facility | | Primary
Purpose | | Usage at
12/31/2003 | | Available
Liquidity at
12/31/2003 | |
| | (Millions) | |
PSEG: | | | | | | | | | | | | | | | | |
364-day Credit Facility | | March 2004 | | $ | 350 | | CP Support | | $ | 299 | | | $ | 51 | | |
5-year Credit Facility | | March 2005 | | $ | 280 | | CP Support | | $ | — | | | $ | 280 | | |
3-year Credit Facility | | December 2005 | | $ | 350 | | CP Support/ | | $ | 10 | (C) | | $ | 340 | | |
| | | | | | | Funding/Letters | | | | | | | | | |
| | | | | | | of Credit | | | | | | | | | |
Uncommitted Bilateral Agreement | | N/A | | | N/A | | Funding | | $ | — | | | | N/A | | |
PSE&G: | | | | | | | | | | | | | | | | |
364-day Credit Facility | | June 2004 | | $ | 200 | | CP Support | | $ | — | | | $ | 200 | | |
3-year Credit Facility | | June 2005 | | $ | 200 | | CP Support | | $ | — | | | $ | 200 | | |
Uncommitted Bilateral Agreement | | N/A | | | N/A | | Funding | | $ | — | | | | N/A | | |
PSEG and Power: | | | | | | | | | | | | | | | | |
364-day Credit Facility(A) | | March 2004 | | $ | 250 | | CP Support/ Funding | | $ | — | | | $ | 250 | | |
Power: | | | | | | | | | | | | | | | | |
3-year Credit Facility | | August 2005 | | $ | 25 | | Funding/Letters | | $ | 19 | (C) | | $ | 6 | | |
| | | | | | | of Credit | | | | | | | | | |
Energy Holdings: | | | | | | | | | | | | | | | | |
3-year Credit Facility(B) | | October 2006 | | $ | 200 | | Funding/ | | $ | 56 | (C) | | $ | 144 | | |
| | | | | | | Letters of | | | | | | | | | |
| | | | | | | Credit | | | | | | | | | |
______________
| (A) | PSEG/Power co-borrower facility |
| (B) | The facility could be reduced to a total of $100 million on June 30, 2004 if available liquidity during the period, after repayment of the Energy Holdings’ Senior Notes due in February 2004 to June 30, 2004 does not reach $100 million for 15 days. |
| (C) | These amounts relate to letters of credit outstanding. |
Energy Holdings
As of December 31, 2003, in addition to amounts outstanding under Energy Holdings’ credit facilities shown in the above table, subsidiaries of Global had $35 million of non-recourse short-term financing at the project level. As of December 31, 2003, Energy Holdings had loaned $300 million of excess cash to PSEG. For information regarding affiliate borrowings, see Note 26. Related-Party Transactions of the Notes.
76
External Financings
PSEG
On October 7, 2003, PSEG issued $356 million (approximately 8.8 million shares) of common equity. Proceeds from the offering were used for the repayment of short-term debt.
In 2002, PSEG began issuing shares of its common stock under its Dividend Reinvestment Program and Employee Stock Purchase Plan, rather than purchasing shares on the open market. For the year ended December 31, 2003, PSEG issued approximately 2.1 million shares for approximately $85 million pursuant to these plans.
Dividend payments on common stock for the year ended December 31, 2003 were $2.16 per share and totaled approximately $493 million. In January 2004, PSEG’s Board of Directors approved an increase in the quarterly dividend by $0.01 per share, from $0.54 to $0.55. Future dividends declared will be dependent upon PSEG’s future earnings, cash flows, financial requirements, alternative investment opportunities and other factors.
PSE&G
In January 2003, PSE&G issued $150 million of 5.000% Medium-Term Notes due 2013. The proceeds of this issuance were used to repay $150 million of 6.875% Series MM Mortgage Bonds which matured in January 2003.
Also in January 2003, PSEG contributed $170 million to PSE&G to support its capital structure. PSE&G paid a common stock dividend of approximately $200 million to PSEG in September 2003.
In June 2003, $150 million of 8.875% Series DD Mortgage Bonds matured.
In September 2003, PSE&G issued $300 million of 5.375% Medium-Term Notes due 2013. The proceeds of this issuance were used to both repay short-term debt incurred to pay for the previously matured $150 million of Series DD Mortgage Bonds, as well as to reduce other short-term debt.
In November 2003, PSE&G issued $250 million of 4.000% Medium-Term Notes due 2008. The proceeds of this issuance were used to retire $60 million and $95 million of its subordinated debt which supported cumulative Monthly Income Preferred Securities and cumulative Quarterly Income Preferred Securities, respectively, in December as detailed below and to reduce short-term debt.
During 2003, PSE&G Transition Funding LLC repaid approximately $129 million of its transition bonds.
On December 31, 2003, PSE&G Capital, L.P., a limited partnership of which PSE&G is the sole general partner, redeemed all of its $60 million outstanding 8.000% Cumulative Monthly Income Preferred Securities, Series B at a price of $25 per preferred security for approximately $60 million.
On December 31, 2003, PSE&G Capital Trust II, a statutory trust of which PSE&G is the sole depositor, redeemed all of its $95 million outstanding 8.125% Cumulative Quarterly Income Preferred Securities, Series B at a price of $25 per preferred security for approximately $95 million.
In December 2003, PSE&G redeemed $64 million of its 5.700% First and Refunding Mortgage Bonds, Pollution Control Series L due 2028 (Series L Bonds) and $145 million of its 5.550% First and Refunding Mortgage Bonds, Pollution Control Series N due 2033 (Series N Bonds). Each of these series of mortgage bonds serviced and secured like principal amounts of pollution control revenue refunding bonds of The Pollution Control Financing Authority of Salem County, New Jersey (Salem Authority). The Series L Bonds and the Series N Bonds were refinanced through the issuance of new series of mortgage bonds that are multi-mode and that were initially issued in a floating rate 35-day auction mode. The Series L Bonds were refinanced by the issuance of $64 million of First and Refunding Mortgage Bonds, Pollution Control Series Y due 2028, with an initial auction rate of 1.100%. The Series N Bonds were refinanced by the issuance of three separate series of mortgage bonds: $50 million First and Refunding Mortgage Bonds, Pollution Control Series Z due 2033 with an initial rate of 1.140%, $50 million First and Refunding Mortgage Bonds, Pollution Control Series AA due 2033 with an initial rate of 1.100%, and a $45.2 million First and Refunding Mortgage Bonds, Pollution Control Series AB due
77
2033 with an initial rate of 1.150%. Similarly, these new mortgage bonds service and secure like principal amounts of pollution control revenue refunding bonds of the Salem Authority.
Power
In December 2003, PSEG contributed approximately $150 million of equity to Power.
In December 2003, Power issued $300 million of 5.500% Senior Notes due 2015. The proceeds of this issuance were used to repay intercompany debt and for general corporate purposes.
Energy Holdings
In April 2003, Energy Holdings, in a private placement, issued $350 million of 7.750% Senior Notes due in 2007. The proceeds were used in part to repay PSEG Capital’s remaining $252 million of 6.250% Medium-Term Notes that matured in May 2003. The remaining proceeds from the sale of the Senior Notes were used for general corporate purposes. In July 2003, Energy Holdings completed an exchange of the Senior Notes for registered securities.
In September 2003, Energy Holdings repurchased approximately $12 million of its outstanding Senior Notes. In February 2004, Energy Holdings redeemed the remaining $267 million of these Senior Notes at maturity. In addition, Energy Holdings expects to redeem approximately $75 million of preferred securities held by PSEG in the first quarter of 2004.
In addition, as detailed below, a number of entities in which Global has invested engaged in financing transactions, each of which is non-recourse to Global and Energy Holdings:
During January and February of 2003, Sociedad Austral de Electricidad S.A. (SAESA) and Empresa Electrica de la Frontera S.A. (Frontel), two distribution companies in Chile, refinanced certain short-term obligations through a combination of bonds, a syndicated bank facility and equity from Global. SAESA issued two series of bonds equivalent to $117 million with respective final maturities in 2009 and 2023. Frontel executed a syndicated loan facility equivalent to $23 million with final maturity in 2010. In addition, during January 2003, Global made equity contributions to SAESA and Frontel totaling $55 million.
In March 2003, Electroandes, a generation facility in Peru, refinanced a $100 million bridge loan with a $70 million seven-year amortizing facility and two $15 million one-year facilities (each guaranteed by Energy Holdings). Additionally, in June 2003, Electroandes sold $50 million of bonds in the local market. These bonds have a 6.440% coupon and mature in 2013. The bonds include a five-year grace period on principal payments. Proceeds from this bond issue were used to repay the two $15 million one-year facilities, at which time the related guarantees by Energy Holdings were eliminated, along with $20 million of the $70 million seven-year facility.
In September 2003, Electroandes sold an additional $30 million of Peruvian Sol denominated bonds with a coupon of 6.000%. The proceeds from this bond issue were used to repay $30 million of the $50 million balance of the seven-year facility. In the fourth quarter of 2003, Electroandes completed the refinancing of the final $20 million of the seven-year facility with a ten-year bond issued at 5.875%.
In May 2003, GWF Power Systems, L.P. (GWF) and Hanford L.P. (Hanford) closed on a $55 million syndicated bank loan along with an additional $7 million letter of credit facility. Interest on this bank loan is at LIBOR plus 2.000% through September 30, 2004 and LIBOR plus 2.250% thereafter. Global and Harbert Power (Harbert) each own 50% of GWF and Hanford. GWF and Hanford used the net proceeds from the bank loan to pay back investments from Global and Harbert. Global received a cash distribution of approximately $27 million in May 2003 and reduced its investment in GWF to $66 million as of September 30, 2003.
In September 2003, GWF Energy issued $226 million of 6.131% senior secured notes that mature on December 30, 2011. The note proceeds were used by GWF Energy to repay a $45 million bank loan that matured on September 30, 2003, to make distributions to its members and for general corporate purposes. GWF Energy also closed a $35 million letter of credit and working capital facility simultaneous with the issuance of the notes. The bank facility is available to GWF Energy to provide letters of credit to fund the debt service reserve account required by the notes’ indenture and to secure
78
project obligations. The portion of the bank facility that is not used to provide letters of credit may be used to provide working capital loans to GWF Energy up to a maximum of $7.5 million. GWF Energy has approximately $27 million of issued and undrawn letters of credit outstanding under the bank facility and approximately $8 million available for working capital loans and/or additional letters of credit, subject to the $7.5 million cap on working capital loans. GWF Energy made cash distributions to Global prior to September 30, 2003 of approximately $137 million from the proceeds of this financing.
As of December 31, 2003, RGE had total outstanding debt equivalent to approximately $240 million of which approximately $204 million matures over the next two years. RGE is currently in discussions with various financial institutions to obtain financing for approximately $35 million. Proceeds from these facilities will be used to refinance certain short-term obligations and to fund capital expenditures. Due to the macroeconomic conditions in Brazil, the country’s debt markets have become increasingly short term in nature, impacting RGE’s ability to refinance on a long-term basis, which could negatively impact RGE’s liquidity and increase their costs of borrowing. RGE’s current average interest rate is approximately 18%.
OCI Charge for Pension Liability
PSEG, PSE&G, Power and Energy Holdings
PSEG maintains certain pension plans for the benefit of its and its subsidiaries’ employees. Due to general market conditions in 2002, the master trust fund for PSEG’s pension plans experienced significant unrealized losses and deteriorated below the accumulated benefit obligation (ABO) of these plans. In accordance with SFAS No. 87, “Employers Accounting for Pensions” (SFAS 87), PSEG, PSE&G, Power and Energy Holdings were required to record a minimum pension liability on their respective Consolidated Balance Sheets as of December 31, 2002. As calculated under SFAS 87, a minimum pension liability was recorded because the ABO of the plan exceeded the fair value of the plan assets as of December 31, 2002. The excess of the ABO over the fair value of the plan assets was recorded as a charge to OCI within the equity section of the Consolidated Balance Sheets. The offsetting adjustment was recorded as a pension liability or as a reduction of certain pension plan intangible assets as applicable. The minimum pension liabilities totaling $289 million related to the qualified pension plans were reversed as of December 31, 2003, as the fair value of the pension plan assets exceeded the ABO. This was achieved by improved conditions in the financial markets, as well as contributions by the respective companies of approximately $210 million during 2003. In 2004, PSEG plans to contribute approximately $90 million to fund the pension plans. For additional information, see Note 21. Pension, Other Postretirement Benefit (OPEB) and Savings Plans of the Notes.
79
CAPITAL REQUIREMENTS
Forecasted Expenditures
PSEG, Power and Energy Holdings
PSEG, Power and Energy Holdings have materially reduced their respective capital expenditure forecasts in response to tightening market conditions resulting from market and lender concerns regarding the overall economy and the industry in particular, including an investor and rating agency focus on leverage ratios.
It is expected that the majority of each subsidiary’s capital requirements over the next five years will come from internally generated funds, with the balance to be provided through equity from PSEG (other than to Energy Holdings) and by the issuance of debt at the project level. Projected construction and investment expenditures, excluding nuclear fuel purchases, for PSEG’s subsidiaries for the next five years are as follows:
| | 2004 | | 2005 | | 2006 | | 2007 | | 2008 | |
| | (Millions) | |
PSE&G | | | | | | | | | | | | | | | | |
Facilities Support | | $ | 40 | | $ | 45 | | $ | 45 | | $ | 70 | | $ | 90 | |
Environmental/Regulatory | | | 20 | | | 15 | | | 20 | | | 20 | | | 20 | |
Facility Replacement | | | 160 | | | 135 | | | 150 | | | 145 | | | 155 | |
System Reinforcement | | | 90 | | | 100 | | | 90 | | | 95 | | | 90 | |
New Business | | | 150 | | | 145 | | | 150 | | | 155 | | | 155 | |
Total PSE&G | | | 460 | | | 440 | | | 455 | | | 485 | | | 510 | |
Power | | | | | | | | | | | | | | | | |
Non-recurring (new MWs and Environmental) | | | 590 | | | 150 | | | 75 | | | 75 | | | 80 | |
Maintenance | | | 110 | | | 140 | | | 100 | | | 90 | | | 110 | |
Total Power | | | 700 | | | 290 | | | 175 | | | 165 | | | 190 | |
Energy Holdings | | | 40 | | | 30 | | | 15 | | | 20 | | | 20 | |
Other | | | 20 | | | 10 | | | 10 | | | 10 | | | 15 | |
Total PSEG | | $ | 1,220 | | $ | 770 | | $ | 655 | | $ | 680 | | $ | 735 | |
| | | | | | | | | | | | | | | | | | | | | |
PSE&G
PSE&G projects future capital needs for additions to its transmission and distribution systems to meet expected growth and to manage reliability.
Power
Power has revised its schedule for completion of several projects under development to provide better sequencing of its construction program with anticipated market demand. In 2003, Power made approximately $655 million of capital expenditures, primarily related to developing the Lawrenceburg, Indiana, Waterford, Ohio and Bethlehem, New York (Albany) sites and adding capacity to the Linden station in New Jersey. The Waterford, Ohio facility was placed in service in August 2003.
Energy Holdings
Energy Holdings’ capital needs in 2004 will be limited to fulfilling existing contractual and potential contingent commitments. The balance relates to capital requirements of consolidated subsidiaries, which will be financed from internally generated cash flow within the projects, from local sources on a non-recourse basis or discretionary investments at Energy Holdings.
In 2003, Energy Holdings invested approximately $307 million of capital expenditures, primarily related to capital projects at SAESA, Salalah, Elcho and the GWF Energy plants. This amount exceeded Energy Holdings’ original 2003 plan largely due to capital expenditures at Global’s
80
investments using internally generated funds or local financing, but is included in Energy Holdings’ capital expenditures as certain of these investments are consolidated. Approximately $133 million of this amount was funded by Energy Holdings’ equity contributions to Global primarily to fulfill existing commitments for projects in construction.
Disclosures about Long-Term Maturities, Contractual and Commercial Obligations and Certain Investments
The following tables, reflect PSEG’s and its subsidiaries’ contractual cash obligations and other commercial commitments in the respective periods in which they are due. In addition the table summarizes anticipated recourse and non-recourse debt maturities for the years shown. The chart below does not reflect debt maturities of non-consolidated investments. If those obligations were not able to be refinanced by the project, Energy Holdings may elect to make additional contributions in these investments. For additional information, see Note 15. Schedule of Consolidated Debt of the Notes.
Contractual Cash Obligations | | Total
Amounts
Committed | | Less
Than
1 year | | 2–3
years | | 4–5
years | | Over
5 years | |
| | | | | | (Millions) | | | | | |
Short-Term Debt Maturities: | | | | | | | | | | | | | | | | |
PSEG | | $ | 299 | | $ | 299 | | $ | — | | $ | — | | $ | — | |
Energy Holdings | | | 2 | | | 2 | | | — | | | — | | | — | |
Long-Term Debt Maturities: | | | | | | | | | | | | | | | | |
Recourse Debt Maturities | | | | | | | | | | | | | | | | |
PSEG (A) | | | 1,462 | | | — | | | 98 | | | 558 | | | 806 | |
PSE&G | | | 3,330 | | | 286 | | | 272 | | | 363 | | | 2,409 | |
Transition Funding (PSE&G) | | | 2,222 | | | 137 | | | 302 | | | 331 | | | 1,452 | |
Power | | | 2,816 | | | — | | | 500 | | | — | | | 2,316 | |
Energy Holdings | | | 2,067 | | | 267 | | | — | | | 857 | | | 943 | |
Non-Recourse Project Financing | | | | | | | | | | | | | | | | |
Power | | | 800 | | | — | | | 800 | | | — | | | — | |
Energy Holdings | | | 974 | | | 36 | | | 99 | | | 147 | | | 692 | |
Capital Lease Obligations | | | | | | | | | | | | | | | | |
PSEG | | | 76 | | | 6 | | | 13 | | | 14 | | | 43 | |
Power | | | 18 | | | 1 | | | 2 | | | 4 | | | 11 | |
Operating Leases | | | | | | | | | | | | | | | | |
PSE&G | | | 11 | | | 3 | | | 5 | | | 3 | | | — | |
Energy Holdings | | | 48 | | | 8 | | | 13 | | | 11 | | | 16 | |
Services | | | 8 | | | 1 | | | 2 | | | 2 | | | 3 | |
Energy Related Purchase Commitments | | | | | | | | | | | | | | | | |
Power | | | 1,493 | | | 414 | | | 510 | | | 336 | | | 233 | |
Restructuring Commitments | | | | | | | | | | | | | | | | |
Power | | | 6 | | | 6 | | | — | | | — | | | — | |
Energy Holdings | | | 4 | | | 4 | | | — | | | — | | | — | |
Total Contractual Cash Obligations | | $ | 15,636 | | $ | 1,470 | | $ | 2,616 | | $ | 2,626 | | $ | 8,924 | |
Standby Letters of Credit | | | | | | | | | | | | | | | | |
Power | | $ | 74 | | $ | 74 | | $ | — | | $ | — | | $ | — | |
Energy Holdings | | | 56 | | | 51 | | | 5 | | | — | | | — | |
Guarantees and Equity Commitments | | | | | | | | | | | | | | | | |
Power | | | 25 | | | 25 | | | — | | | — | | | — | |
Energy Holdings | | | 125 | | | — | | | — | | | 49 | | | 76 | |
Total Commercial Commitments | | $ | 280 | | $ | 150 | | $ | 5 | | $ | 49 | | $ | 76 | |
| (A) | Includes debt supporting trust preferred securities of $1.2 billion. |
| * | Power has also entered into contractual commitments for a variety of services for which annual amounts are not quantifiable. See Note 17, Commitments and Contingent Liabilities. |
81
OFF BALANCE SHEET ARRANGEMENTS
Power
Power issues guarantees in conjunction with certain of its energy trading activities, see Note 17. Commitments and Contingent Liabilities of the Notes for further discussion.
Energy Holdings
Global has certain investments that are accounted for under the equity method in accordance with accounting principles generally accepted in the U.S. (GAAP). Accordingly, amounts recorded on the Consolidated Balance Sheets for such investments represent Global’s equity investment, which is increased for Global’s pro-rata share of earnings less any dividend distribution from such investments. The companies in which PSEG invests that are accounted for under the equity method have an aggregate $1.8 billion of debt on their combined, consolidated financial statements. PSEG’s pro-rata share of such debt is $800 million. This debt is non-recourse to PSEG, Energy Holdings and Global. PSEG is generally not required to support the debt service obligations of these companies. However, default with respect to this non-recourse debt could result in a loss of invested equity.
Resources has investments in leveraged leases that are accounted for in accordance with SFAS No. 13, “Accounting for Leases.” Leveraged lease investments generally involve three parties: an owner/lessor, a creditor and a lessee. In a typical leveraged lease financing, the lessor purchases an asset to be leased. The purchase price is typically financed 80% with debt provided by the creditor and the balance comes from equity funds provided by the lessor. The creditor provides long-term financing to the transaction, and is secured by the property subject to the lease. Such long-term financing is non- recourse to the lessor. As such, in the event of default, the leased asset, and in some cases the lessee, secure the loan. As a lessor, Resources has ownership rights to the property and rents the property to the lessees for use in their business operation. As of December 31, 2003, Resources’ equity investment in leased assets was approximately $1.4 billion, net of deferred taxes of approximately $1.6 billion. For additional information, see Note 12. Long-Term Investments of the Notes.
In the event that collectibility of the minimum lease payments to be received by the lessor is no longer reasonably assumed, the accounting treatment for some of the leases may change. In such cases, Resources may deem that a lessee has a high probability of defaulting on the lease obligation. Should Resources ever directly assume a debt obligation, the fair value of the underlying asset and the associated debt would be recorded on the Consolidated Balance Sheets instead of the net equity investment in the lease.
Energy Holdings have guaranteed certain obligations of their subsidiaries or affiliates related to certain projects. See Note 17. Commitments and Contingent Liabilities of the Notes for further discussion.
CRITICAL ACCOUNTING ESTIMATES
PSEG, PSE&G, Power and Energy Holdings
Under GAAP, there are many accounting standards that require the use of estimates, variable inputs and assumptions (collectively referred to as estimates) that are subjective in nature. Because of this, differences between the actual measure realized versus the estimate can have a material impact on results of operations, financial position and cash flows. The managements of PSEG, PSE&G, Power and Energy Holdings have each, respectively, determined that the following estimates are considered critical to the application of rules that relate to its business.
Accounting for Pensions
PSEG, PSE&G, Power and Energy Holdings account for pensions under SFAS 87. Pension costs under SFAS 87 are calculated using various economic and demographic assumptions. Economic assumptions include the discount rate and the long-term rate of return on trust assets. Demographic assumptions include projections of future mortality rates, pay increases and retirement patterns. In
82
2003, PSEG recorded pension expense of $147 million, compared to $89 million in 2002 and $58 million in 2001. Additionally, in 2003, PSEG and its respective subsidiaries contributed cash of approximately $210 million compared to cash contributions of $240 million in 2002, and $90 million in 2001.
PSEG’s discount rate assumption, which is determined annually, is based on the rates of return on high-quality fixed-income investments currently available and expected to be available during the period to maturity of the pension benefits. The discount rate used to calculate pension obligations is determined as of December 31 each year, PSEG’s SFAS 87 measurement date. The discount rate used to determine year-end obligations is also used to develop the following year’s net periodic pension cost. The discount rates used in PSEG’s 2002 and 2003 net periodic pension costs were 7.25% and 6.75%, respectively. PSEG’s 2004 net periodic pension cost was developed using a discount rate of 6.25%.
PSEG’s expected rate of return on plan assets reflects current asset allocations, historical long-term investment performance, and an estimate of future long-term returns by asset class using input from PSEG’s actuary and investment advisors, as well as long-term inflation assumptions. For 2002, and 2003, PSEG assumed a rate of return of 9.0% on PSEG’s pension plan assets. For 2004, PSEG has reduced the rate of return assumption to 8.75%.
As indicated above, the 2004 pension expense is calculated using a reduced discount rate of 6.25%, which is based on high-quality fixed-income rates as of December 31, 2003, and a reduced expected rate of return on plan assets of 8.75%. However, PSEG’s 2004 pension costs are expected to decrease significantly as a result of the material increase in the value of its pension funds during 2003. This increase was driven by PSEG’s contributions of approximately $210 million and a 2003 return of 25%.
Based on the above assumptions, PSEG has estimated net period pension costs of approximately $90 million and contributions of up to $100 million in 2004. As part of the business planning process, PSEG has modeled its future costs assuming an 8.75% rate of return and the return to a 6.75% discount rate for 2005 and beyond. Based on these assumptions, PSEG has estimated net period pension costs of approximately $60 million in 2005 and $50 million in 2006. Actual future pension expense and funding levels will depend on future investment performance, changes in discount rates, market conditions, funding levels relative to PSEG’s Pension Benefit Obligation (PBO) and ABO and various other factors related to the populations participating in PSEG’s pension plans.
The following chart reflects the sensitivities associated with a change in certain actuarial assumptions. The effects of the assumption changes shown below solely reflect the impact of that specific assumption.
Actuarial Assumption | | Current | | Change/
(Decrease) | | As of December 31, 2003
Impact on Pension
Benefit Obligation | | Increase to
Pension Expense
in 2004 | |
| | | | | | (Millions) | |
Discount Rate | | 6.25% | | (1%) | | | $ | 473 | | $81 | |
Rate of Return on Plan Assets | | 8.75% | | (1%) | | | $ | — | | $27 | |
Accounting for Deferred Taxes
PSEG, PSE&G, Power and Energy Holdings provide for income taxes based on the asset and liability method required by SFAS No. 109, “Accounting for Income Taxes.” Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases, as well as net operating loss and credit carryforwards.
PSEG, PSE&G, Power and Energy Holdings evaluate the need for a valuation allowance against their respective deferred tax assets based on the likelihood of expected future taxable income. PSEG, PSE&G, Power and Energy Holdings do not believe a valuation allowance is necessary; however, if the expected level of future taxable income changes or certain tax planning strategies become unavailable, PSEG, PSE&G, Power and Energy Holdings would record a valuation allowance through income tax expense in the period the valuation allowance is deemed necessary. Resources’ and Global’s ability to realize their deferred tax assets are dependent on PSEG’s subsidiaries’ ability to generate ordinary income and capital gains.
83
PSE&G
Unbilled Revenues
Electric and gas revenues are recorded based on services rendered to customers during each accounting period. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. Unbilled usage is calculated in two steps. The initial step is to apply a base usage per day to the number of unbilled days in the period. The second step estimates seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms. The resulting usage is priced at current rate levels and recorded as revenue. A calculation of the associated energy cost for the unbilled usage is recorded as well. Each month the prior month’s unbilled amounts are reversed and the current month’s amounts are accrued. Using benchmarks other than those used in this calculation could have a material effect on the amounts accrued for in a reporting period. The resulting revenue and expense reflect the billed data less the portion recorded in the prior month plus the unbilled portion of the current month.
SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS 71)
PSE&G prepares its Consolidated Financial Statements in accordance with the provisions of SFAS 71, which differs in certain respects from the application of GAAP by non-regulated businesses. In general, SFAS 71 recognizes that accounting for rate-regulated enterprises should reflect the economic effects of regulation. As a result, a regulated utility is required to defer the 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 future rates. Accordingly, PSE&G has deferred certain costs, which will be amortized over various future 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 is charged or credited to income. See Note 10. Regulatory Assets and Liabilities of the Notes for further discussion of these and other regulatory issues.
Power and PSEG
Nuclear Decommissioning Trust (NDT) Fund
Power accounts for the assets in the NDT Fund under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS 115). The assets in the NDT Fund are classified as available-for-sale securities and are marked to market with unrealized gains and losses recorded in OCI. Realized gains, losses, and dividend and interest income are recorded on Power’s and PSEG’s Statements of Operations under Other Income and Other Deductions. Unrealized losses that are deemed to be Other Than Temporarily Impaired (OTTI), as defined under SFAS 115, Emerging Issues Task Force 03-1, “The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments” (EITF 03-1), and related interpretive guidance, will be charged against earnings rather than OCI. These factors, such as the length of time and extent to which the fair value is below carrying value, the potential for impairments of securities when the issuer or industry is experiencing significant financial difficulties and Power’s intent and ability to continue to hold securities, are used as indicators of the prospects of the securities to recover their value 10% test.
ITEM 7A. QUALITATIVE AND QUANTITATIVE DISCLOSURES ABOUT MARKET RISK
PSEG, PSE&G, Power and Energy Holdings
The market risk inherent in PSEG’s, PSE&G’s, Power’s and Energy Holdings’ market risk sensitive instruments and positions is the potential loss arising from adverse changes in foreign currency exchange rates, commodity prices, equity security prices and interest rates as discussed in the Notes to the Consolidated Financial Statements. It is the policy of each entity to use derivatives to manage risk
84
consistent with its respective business plans and prudent practices. PSEG, PSE&G, Power and Energy Holdings use a Risk Management Committee (RMC) comprised of executive officers who utilize an independent risk oversight function to ensure compliance with corporate policies and prudent risk management practices.
Additionally, PSEG, PSE&G, Power and Energy Holdings are exposed to counterparty credit losses in the event of non-performance or non-payment. PSEG has a credit management process, which is used to assess, monitor and mitigate counterparty exposure for PSEG and its subsidiaries. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on PSEG and its subsidiaries’ financial condition, results of operations or net cash flows.
Foreign Exchange Rate Risk
Energy Holdings
Global is exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of this risk is that some of its foreign subsidiaries and affiliates utilize currencies other than the consolidated reporting currency, the U.S. Dollar. Additionally, certain of Global’s foreign subsidiaries and affiliates have entered into monetary obligations and maintain receipts/receivables in U.S. Dollars or currencies other than their own functional currencies. Primarily, Global is exposed to changes in the U.S. Dollar to Brazilian Real, Euro, Polish Zloty, Peruvian Nuevo Sol and the Chilean Peso exchange rates. With respect to the foreign currency risk associated with the Brazilian Real, there has already been significant devaluation since the initial acquisition of these investments, which has resulted in reduced U.S. Dollar earnings and cash flows relative to initial projections. However, there have been material improvements during 2003. Whenever possible, these subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust to changes in foreign exchange rates. Global also uses foreign currency forward, swap and option agreements, wherever possible, to manage risk related to certain foreign currency fluctuations.
As of December 31, 2003, the devaluing Brazilian Real has resulted in a cumulative $253 million loss of value which is recorded as a $228 million after-tax charge to OCI related to Global’s equity method investments in RGE. An additional devaluation in the December 31, 2003 Brazilian Real to the U.S. Dollar exchange rate of 10% would result in a $18 million change in the value of the investment in RGE and corresponding impact to OCI. In addition, Global had transactional exposure to the Real in which a 10% adverse change in the exchange rate would result in a loss to earnings of $3 million.
Additionally, Global has $64 million of Euro-denominated receivables subject to fluctuations in the U.S. Dollar to Euro exchange rate. If the December 31, 2003 Euro to U.S. Dollar exchange rate were to appreciate by 10%, Global would record a $6 million after-tax foreign currency transaction gain. If the December 31, 2003 Euro to U.S. Dollar exchange rate were to devalue by 10%, Global would record a $5 million after-tax foreign currency transaction loss.
Global also has net monetary positions in the Polish Zloty related to its consolidated investments in Elcho. If the December 31, 2003 Polish Zloty to U.S. Dollar exchange rate were to appreciate by 10%, Global would record a $4 million after-tax foreign currency transaction gain. If the December 31, 2003 Polish Zloty to U.S. Dollar exchange rate were to devalue by 10%, Global would record a $5 million after-tax foreign currency transaction loss.
Global has various other foreign currency exposures related to translation adjustments. In aggregate, a 10% devaluation in such foreign currencies would result in an after-tax charge to OCI of $93 million.
Commodity Contracts
PSEG and Power
The availability and price of energy commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies
85
and other events. To reduce price risk caused by market fluctuations, Power enters into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties, to hedge its anticipated supply and demand differential. These contracts, in conjunction with owned electric generation capacity and demand obligations, make up the portfolio.
VaR Model
Power
Power uses value-at-risk (VaR) models to assess the market risk of its commodity businesses. The model for Power includes its owned generation and physical contracts, as well as fixed price sales requirements, load requirements and financial derivative instruments. VaR represents the potential gains or losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. Power estimates VaR across its commodity businesses.
Power manages its exposure at the portfolio level. Its portfolio consists of owned generation, load-serving contracts (both gas and electric), fuel supply contracts and energy derivatives designed to manage the risk around the differential between generation and load.
The RMC established a VaR threshold of $50 million for a one-week (5 business days) holding period at a 95% (two-tailed) confidence level. The RMC will be notified if the VaR reaches $40 million and the portfolio will be closely monitored. The Board of Directors of PSEG is notified if a VaR threshold of $75 million is reached.
The model is an augmented variance/covariance model adjusted for the delta of positions with a 95% two-tailed confidence level for a one-week holding period. The model is augmented to incorporate the non-log-normality of energy-related commodity prices, especially emissions and capacity and the non-stationary nature of energy volatility. In many commodities, the natural log of prices is normally distributed. This is not true of energy commodities which have a higher frequency of extreme events than would be predicted by a normal distribution. The model also assumes no hedging activity throughout the holding period, whereas Power actively manages its portfolio.
As of December 31, 2003, VaR was approximately $18 million, compared to the December 31, 2002 level of $7 million. As of December 31, 2003, Power’s load obligation is determined primarily by the results of the annual BGS auction. To maintain an actionable VaR and to match the terms of the auction, generation is modeled at 100% of its expected output through May 2004 and at one-third of the expected output from June 2004 through May 2006.
For the Year Ended December 31, 2003 | Total VaR |
| (Millions) |
95% Confidence Level, Five-Day Holding Period, Two-Tailed: | | | | |
Period End | | $ | 18 | |
Average for the Period | | $ | 18 | |
High | | $ | 35 | |
Low | | $ | 9 | |
99% Confidence Level, One-Day Holding Period, Two-Tailed: | | | | |
Period End | | $ | 11 | |
Average for the Period | | $ | 10 | |
High | | $ | 20 | |
Low | | $ | 5 | |
Energy Holdings
In general, Energy Holdings manages its commodity exposure through long-term power purchase agreements. One notable exception is Global’s partial ownership of TIE, which owns two merchant energy plants that sell their output in the day ahead and forward market. As a result of this open
86
position, as of December 31, 2003, VaR was approximately $11 million, compared to the December 31, 2002 level of $4 million.
The model is a variance/covariance model with a two-tailed 95% confidence level for a one-week holding period. Expected energy output and fuel usage are modeled as forward obligations over a rolling 12-month period. The Electric Reliability Council of Texas (ERCOT) system is a closed system and is less liquid than the PJM. This lack of liquidity in ERCOT limits how far forward TIE is able to sell. This lack of liquidity also makes estimates of volatility and correlation less reliable.
Interest Rates
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s, PSE&G, Power and Energy Holdings’ policy is to manage interest rate risk through the use of fixed and floating rate debt, interest rate swaps and interest rate lock agreements. PSEG, PSE&G, Power and Energy Holdings manage their respective interest rate exposures by maintaining a targeted ratio of fixed and floating rate debt. As of December 31, 2003, a hypothetical 10% change in market interest rates would result in a $3 million, $2 million and $2 million change in annual interest costs related to debt at PSE&G, Power and Energy Holdings, respectively. In addition, as of December 31, 2003, a hypothetical 10% change in market interest rates would result in a $5 million, $233 million, $118 million and $53 million change in the fair value of the debt of PSEG, PSE&G, Power and Energy Holdings, respectively.
Debt and Equity Securities
PSEG, PSE&G, Power and Energy Holdings
PSEG has approximately $2.7 billion invested in its pension plans. Although fluctuations in market prices of securities within this portfolio do not directly affect PSEG’s earnings in the current period, changes in the value of these investments could affect PSEG’s future contributions to these plans, its financial position if its ABO under its pension plans exceeds the fair value of its pension funds and future earnings as PSEG would earn a different return on the fund balance and could be required to adjust its assumed rate of return.
Power
Power’s NDT Fund is comprised of both fixed income and equity securities totaling $985 million as of December 31, 2003. The fair value of equity securities is determined independently each month by the Trustee. As of December 31, 2003, the portfolio was comprised of approximately $619 million of equity securities and approximately $344 million in fixed income securities. The fair market value of the NDT assets will fluctuate depending on the performance of equity markets. As of December 31, 2003, a hypothetical 10% change in the equity market would impact the value of the equity securities in the NDT Fund by approximately $61 million.
Power uses duration to measure the interest rate sensitivity of the fixed income portfolio. Duration is a summary statistic of the effective average maturity of the fixed income portfolio. The benchmark for the fixed income component of the NDT Fund is the Lehman Brothers Aggregate Bond Index, which currently has a duration of 4.5 years and a yield of 4.1%. The portfolio’s value will appreciate or depreciate by the duration with a 1% change in interest rates. As of December 31, 2003, a hypothetical 1% increase in interest rates would result in a decline in the market value for the fixed income portfolio of approximately $14 million.
Energy Holdings
Resources has investments in equity securities and limited partnerships. Resources carries its investments in equity securities at their fair value as of the reporting date. Consequently, the carrying value of these investments is affected by changes in the fair value of the underlying securities. Fair value
87
is determined by adjusting the market value of the securities for liquidity and market volatility factors, where appropriate.
As of December 31, 2003, Resources had investments in leveraged buyout funds of approximately $74 million, of which $25 million was comprised of public securities with available market prices and $49 million was comprised of privately held interests in certain companies. The potential change in fair value resulting from a hypothetical 10% change in quoted market prices of the publicly traded investments amounted to $3 million as of December 31, 2003.
Credit Risk
PSEG, PSE&G, Power and Energy Holdings
Credit risk relates to the risk of loss that PSEG, PSE&G, Power and Energy Holdings would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. PSEG, PSE&G, Power and Energy Holdings have established credit policies that they believe significantly minimize credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements, which may allow for the netting of positive and negative exposures associated with a single counterparty.
PSE&G
BGS suppliers expose PSE&G to credit losses in the event of non-performance or non-payment upon a default of the BGS supplier. Credit requirements are governed under the BPU approved BGS contract.
Power
Counterparties expose Power’s trading operation to credit losses in the event of non-performance or non-payment. Power has a credit management process, which is used to assess, monitor and mitigate counterparty exposure for Power and its subsidiaries. Power’s counterparty credit limits are based on a scoring model that considers a variety of factors, including leverage, liquidity, profitability, credit ratings and risk management capabilities. Power’s trading operations have entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Power’s exposure to counterparty risk by providing the offset of amounts payable to the counterparty against amounts receivable from the counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power and its subsidiaries’ financial condition, results of operations or net cash flows. As of December 31, 2003 over 96% of the credit exposure (mark-to-market plus net receivables and payables, less cash collateral) for Power’s trading operations was with investment grade counterparties. The majority of the credit exposure with non-investment grade counterparties is with certain companies that supply fuel to Power. Therefore, this exposure relates to the risk of a counterparty performing under its obligations rather than payment risk. As of December 31, 2003, Power’s trading operations had over 160 active counterparties.
As a result of the 2003 New Jersey BGS auction, Power’s trading operation contracted to provide energy to the direct suppliers of New Jersey electric utilities, including PSE&G, commencing August 1, 2003. The revenue from the majority of the suppliers is paid directly to Power from the utilities that those suppliers serve. These bilateral contracts are subject to credit risk. A material portion of credit risk relates to the ability of suppliers to meet their payment obligations for the power delivered under each contract. Any failure to collect these payments under the contracts could have a material impact on Power’s results of operations, cash flows and financial position. The payment risk that is associated with potential nonpayment by any EDC making direct payment under the BGS contracts is lower than the risk under standard bilateral contracts, since the EDCs are rate-regulated entities.
88
Energy Holdings
Global
Eagle Point
In 2000, Global withdrew from its interest in the Eagle Point Cogeneration Project (EPCP) with El Paso Corporation (El Paso) in exchange for a series of contingent payments over five years. The payments to date have been received in accordance with the terms of the agreement, including a payment of $44 million in January 2004. The final principal payment of $37 million under the terms of the agreement is expected to occur in the first quarter of 2005. In the event that EPCP operating cash flows are insufficient to make payment, mandatory capital contributions are required from the partners to pay the note to Global as amounts become due. Additional covenants in the note security package include mandatory restrictions on cash distributions to the partners and performance guarantees of EPCP’s obligations are required. El Paso indirectly owns more than 85% of the partnership interests of EPCP. In February 2003, S&P downgraded El Paso’s long-term corporate credit rating to B+ from BB and Moody’s reduced El Paso’s debt rating to Caa1 from Ba2. If El Paso or its subsidiaries or affiliates is required to fulfill an obligation in accordance with the terms of the agreement and is unable to perform, there could be a material impact to Energy Holdings’ Consolidated Statements of Operations and net cash flows in 2005.
Other
Global has credit risk with respect to its counterparties to PPA’s and other parties. For further discussion, see MD&A—Future Outlook—Energy Holdings.
Resources
Resources has credit risk related to its investments in leveraged leases, totaling $1.4 billion, which is net of deferred taxes of $1.6 billion, as of December 31, 2003. These investments are largely concentrated in the energy industry and have some exposure to the airline industry. As of December 31, 2003, 65% of counterparties in the lease portfolio were rated investment grade by both S&P and Moody’s. Resources is the lessor of various aircraft to several domestic airlines. Resources leases a Boeing B767 aircraft to United Airlines (UAL). In December 2002, UAL filed for Chapter 11 bankruptcy protection. UAL has stated that it intends to retain its B767 aircraft to use in place of other aircraft. UAL has an additional debt obligation of $53 million associated with this aircraft. Resources will work constructively with UAL to keep the leveraged lease in place. The gross invested balance of this investment as of December 31, 2003 was $21 million.
Resources is the lessor of domestic generating facilities in several U.S. energy markets. As a result of recent actions of the rating agencies due to concerns over forward energy prices, the credit of some of the lessees was downgraded. Specifically, the lessees in the following transactions were downgraded below investment grade during 2002 by these rating agencies. Resources’ investment in such transactions was approximately $412 million, net of deferred taxes of $398 million as of December 31, 2003.
Resources leases a generation facility to Reliant Energy Mid Atlantic Power Holdings LLC (REMA), an indirect wholly-owned subsidiary of Reliant Resources Incorporated (RRI). The leased assets are the Keystone, Conemaugh and Shawville generating facilities located in the PJM West market in Pennsylvania. REMA is capitalized with over $1 billion of equity from RRI and has no debt obligations senior to the lease obligations. REMA is currently rated B- by S&P and B3 by Moody’s. As the lessor/equity participant in the lease, Resources is protected with significant lease covenants that restrict the flow of dividends from REMA to its parent, and by over-collateralization of REMA with non-leased assets, transfer of which is restricted by the financing documents. Restrictive covenants include historical and forward cash flow coverage tests that prohibit discretionary capital expenditures and dividend payments to the parent/lessee if stated minimum coverages are not met, and similar cash flow restrictions if ratings are not maintained at stated levels. The covenants are designed to maintain cash reserves in the transaction entity for the benefit of the non-recourse lenders and the lessor/equity participants in the event of a market downturn or degradation in operating performance of the leased
89
assets. Resources’ investment in the REMA transaction was $117 million, net of deferred taxes of $122 million as of December 31, 2003.
Resources is the lessor of the Danskammer generation facility in New York to Dynegy Danskammer LLC (Danskammer) and the Roseton generation facility to Dynegy Roseton LLC (Roseton). Both Danskammer and Roseton are indirect subsidiaries of Dynegy Holdings Inc. (DHI). The lease obligations are guaranteed by DHI which is currently rated B by S&P and Caa2 by Moody’s. Resources’ investment in Danskammer and Roseton was $122 million, net of deferred taxes of $68 million as of December 31, 2003.
Resources is the lessor/equity participant of the Collins facility, as well as the Powerton and Joliet stations to Midwest Generation LLC (Midwest), an indirect subsidiary of Edison Mission Energy (EME). Edison Mission Midwest Holdings (EMM Holdings) is also an indirect subsidiary of EME. As of December 31, 2003, the gross investment balances for the Collins facility and the Powerton and Joliet facilities were $101 million and $72 million, respectively net of taxes of $98 million and $110 million, respectively. On October 16, 2003, certain of EMM Holdings’ corporate credit ratings were placed on credit watch with negative implications. On December 12, 2003, after completion of a refinancing, S&P removed EMM Holdings from credit watch and affirmed its B rating.
Resources has lease covenants that include historical and forward cash flow coverage tests that prohibit certain capital expenditures and dividend payments to the parent/lessee if stated minimum coverages are not met, and similar cash flow restrictions if ratings are not maintained at stated levels. The covenants are designed to maintain cash reserves in the transaction entity for the benefit of the non-recourse lenders and the lessor/equity participants in the event of a market downturn or degradation in operating performance of the leased assets. In the event of default under the lease covenants, Resources among others would have rights to the cash trapped at EMM Holdings. While these covenants help to provide liquidity to the creditors and the lease equity in the transaction, no assurances can be given that such covenants will be sufficient to prevent Resources from incurring a material loss of its equity investment and future earnings and cash flow.
In the event of a default, Energy Holdings would exercise its rights and attempt to seek recovery of its investment. The results of such efforts may not be known for a period of time. A bankruptcy of a lessor and failure to recover adequate value could lead to a foreclosure of the lease. Under a worst-case scenario, if a foreclosure were to occur, Resources would record a pre-tax write-off up to its gross investment in these facilities. The investment balance increases as earnings are recognized and decreases as rental payments are received by the lessor. Also, in the event of a potential foreclosure, the net tax benefits generated by Resources’ portfolio of investments could be materially reduced in the period in which gains associated with the potential forgiveness of debt at these projects occurs. The amount and timing of any potential reduction in net tax benefits is dependent upon a number of factors including, but not limited to, the time of a potential foreclosure, the amount of lease debt outstanding, any cash trapped at the projects and negotiations during such potential foreclosure process. The potential loss of earnings, impairment and/or tax payments could have a material impact to PSEG’s and Energy Holdings’ financial position, results of operations and net cash flows.
As of December 31, 2003, lease payments on these facilities were current. Also, as of December 31, 2003, Resources determined that the collectibility of the minimum lease payments under its leveraged lease investments is still reasonably probable and therefore continues to account for these investments as leveraged leases.
Other Supplemental Information Regarding Market Risk
PSEG and Power
The following presentation of the activities of Power is included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers. For additional information, see Note 16. Risk Management of the Notes.
Normal Operations and Hedging Activities
Power enters into physical contracts, as well as financial contracts, including forwards, futures, swaps and options designed to eliminate risk associated with volatile commodity prices. Commodity
90
price risk is associated with market price movements resulting from market generation demand, changes in fuel costs and various other factors.
Power’s derivative contracts are accounted for under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133), its amendments and related guidance. Most non-trading contracts qualify for the normal purchases and normal sales exemption under SFAS 133 and/or SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149). Changes in the fair value of qualifying cash flow hedge transactions are recorded in OCI, and gains and losses are recognized in earnings when the underlying transaction occurs. Changes in the fair value of derivative contracts that do not meet hedge criteria under SFAS 133 and the ineffective portion of hedge contracts are recognized in earnings currently. Additionally, changes in the fair value attributable to fair value hedges are similarly recognized in earnings.
Trading
Power’s objective for its trading activities is to produce net earnings from trading energy-related products around its owned electric generation assets, gas supply contracts and electric and gas supply obligations. These activities are marked to market in accordance with SFAS 133, its amendments and related guidance, with gains and losses recognized in earnings.
The following table describes the drivers of Power’s energy trading and marketing activities and operating revenues included in its Consolidated Statements of Operations for the year ended December 31, 2003. Normal operations and hedging activities represent the marketing of electricity available from Power’s owned or contracted generation sold into the wholesale market. As the information in this table highlights, mark-to-market activities represent a small portion of the total Operating Revenues for Power. Activities accounted for under the accrual method, including normal purchases and sales, account for the majority of the revenue. The mark-to-market activities reported here are those relating to changes in fair value due to external movement in prices.
91
Operating Revenues
For the Year Ended December 31, 2003
| | Normal
Operations and
Hedging(A) | | Trading | | Total | |
| | (Millions) | |
Mark-to-Market Activities: | | | | | | | | | | | | | | | | |
Unrealized Mark-to-Market Gains (Losses) | | | | | | | | | | | | | | | | |
Changes in Fair Value of Open Positions | | | $ | 29 | | | | $ | 66 | | | | $ | 95 | | |
Origination Unrealized Gain at Inception | | | | — | | | | | — | | | | | — | | |
Changes in Valuation Techniques and Assumptions | | | | — | | | | | — | | | | | — | | |
Realization at Settlement of Contracts | | | | (41 | ) | | | | (87 | ) | | | | (128 | ) | |
Total Change in Unrealized Fair Value | | | | (12 | ) | | | | (21 | ) | | | | (33 | ) | |
Realized Net Settlement of Transactions Subject to Mark-to-Market | | | | 41 | | | | | 87 | | | | | 128 | | |
Broker Fees and Other Related Expenses | | | | — | | | | | (8 | ) | | | | (8 | ) | |
Net Mark-to-Market Gains | | | | 29 | | | | | 58 | | | | | 87 | | |
Accrual Activities | | | | | | | | | | | | | | | | |
Accrual Activities—Revenue, Including Hedge Reclassifications | | | | 5,518 | | | | | — | | | | | 5,518 | | |
Total Operating Revenues | | | $ | 5,547 | | | | $ | 58 | | | | $ | 5,605 | | |
______________
| (A) | Includes derivative contracts that Power enters into to hedge anticipated exposures related to its owned and contracted generation supply, all asset backed transactions (ABT) and hedging activities, but excludes owned and contracted generation assets. |
The following table indicates Power’s energy trading assets and liabilities, as well as Power’s hedging activity related to asset backed transactions and derivative instruments that qualify for hedge accounting under SFAS 133, its amendments and related guidance. This table presents amounts segregated by portfolio which are then netted for those counterparties with whom Power has the right to set off and therefore, are not necessarily indicative of amounts presented on the Consolidated Balance Sheets since balances with many counterparties are subject to offset and are shown net on the Consolidated Balance Sheets regardless of the portfolio in which they are included.
Energy Contract Net Assets/Liabilities
As of December 31, 2003
| | Normal
Operations and
Hedging | | Trading | | Total | |
| | (Millions) | |
Mark-to-Market Energy Assets | | | | | | | | | | | | | | | | |
Current Assets | | | $ | 33 | | | | $ | 69 | | | | $ | 102 | | |
Noncurrent Assets | | | | — | | | | | 12 | | | | | 12 | | |
Total Mark-to-Market Energy Assets | | | $ | 33 | | | | $ | 81 | | | | $ | 114 | | |
Mark-to-Market Energy Liabilities | | | | | | | | | | | | | | | | |
Current Liabilities | | | $ | (41 | ) | | | $ | (74 | ) | | | $ | (115 | ) | |
Noncurrent Liabilities | | | | — | | | | | (5 | ) | | | | (5 | ) | |
Total Mark-to-Market Current Liabilities | | | $ | (41 | ) | | | $ | (79 | ) | | | $ | (120 | ) | |
Total Mark-to-Market Energy Contract Net Assets (Liabilities) | | | $ | (8 | ) | | | $ | 2 | | | | $ | (6 | ) | |
92
The following table presents maturity of net fair value of mark-to-market energy trading contracts.
Maturity of Net Fair Value of Mark-to-Market Energy Trading Contracts
As of December 31, 2003
| | Maturities within | |
| | 2004 | | 2005 | | 2006 | | 2007-
2008 | | Total | |
| | (Millions) | |
Trading | | $ | (4 | ) | $ | 7 | | $ | (1 | ) | $ | — | | $ | 2 | |
Normal Operations and Hedging | | | 5 | | | (7 | ) | | — | | | (6 | ) | | (8 | ) |
Total Net Unrealized Gains (Losses) on Mark-to-Market Contracts | | $ | 1 | | $ | — | | $ | (1 | ) | $ | (6 | ) | $ | (6 | ) |
Wherever possible, fair values for these contracts were obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques were employed using assumptions reflective of current market rates, yield curves and forward prices as applicable to interpolate certain prices. The effect of using such modeling techniques is not material to Power’s financial results.
PSEG, PSE&G, Power and Energy Holdings
The following table identifies gains (losses) on cash flow hedges that are currently in Accumulated OCI, a separate component of equity. Power uses forward sale and purchase contracts, swaps and fixed transmission rights (FTRs) contracts to hedge forecasted energy sales from its generation stations. Power also enters into swaps, options and futures transactions to hedge the price of fuel to meet its fuel purchase requirements for generation. PSEG, PSE&G, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s policy is to manage interest rate risk through the use of fixed rate debt, floating rate debt and interest rate derivatives. Affiliates of Energy Holdings purchase forward-exchange contracts as hedges of anticipated payments to contractors for projects under construction. These contracts are designed to hedge against the risk that the future cash payments will be adversely affected by changes in foreign currency rates. The table also provides an estimate of the gains (losses) that are expected to be reclassified out of OCI and into earnings over the next twelve months.
Cash Flow Hedges Included in OCI
As of December 31, 2003
| | Accumulated
OCI | | Portion Expected
to be Reclassified
in next 12 months |
| | (Millions) |
Cash Flow Hedges Included in OCI | | | | | | | | | |
Commodities | | $ | (25 | ) | | | $ (17 | ) | |
Interest Rates | | | (104 | ) | | | (31 | ) | |
Foreign Currency | | | 7 | | | | — | | |
Net Cash Flow Hedge Loss Included in OCI | | $ | (122 | ) | | | $ (48 | ) | |
Power
Credit Risk
Counterparties expose Power to credit losses in the event of non-performance or non-payment. Power has a credit management process which is used to assess, monitor and mitigate counterparty exposure for Power and its subsidiaries. Power’s counterparty credit limits are based on a variety of factors, including credit ratings, leverage, liquidity, profitability and risk management capabilities. Power has entered into payment netting agreements or enabling agreements that allow for payment netting with the majority of its large counterparties, which reduce Power’s exposure to counterparty risk by
93
providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty.
The following table provides information on Power’s credit exposure, net of collateral, as of December 31, 2003. Credit exposure, in the table below, is defined as net accounts receivable as well as any net “in-the-money” forward mark-to-market exposure. It further delineates that exposure by the credit rating of the counterparties and provides guidance on the concentration of credit risk to individual counterparties and an indication of the maturity of a company’s credit risk by credit rating of the counterparties.
Schedule of Credit Risk Exposure on Energy Contracts Net Assets
As of December 31, 2003
Rating | | Current
Exposure | | Securities
Held
as Collateral | | Net
Exposure | | Number of
Counterparties
>10% | | Net Exposure of
Counter parties
>10% |
| | | | | | (Millions) | | | | | | | | | | (Millions) |
Investment Grade—External Rating | | $ | 406 | | | | $ | 28 | | | $ | 398 | | | | 1 | | | | $186 | (A) |
Non-Investment Grade—External Rating | | | 18 | | | | | 14 | | | | 6 | | | | — | | | | — | |
Investment Grade—No External Rating | | | 13 | | | | | — | | | | 13 | | | | — | | | | — | |
Non-Investment Grade—No External Rating | | | 13 | | | | | — | | | | 13 | | | | — | | | | — | |
Total | | $ | 450 | | | | $ | 42 | | | $ | 430 | | | | 1 | | | | $186 | |
______________
| (A) | Represents exposure with PSE&G |
The net exposure listed above, in some cases, will not be the difference between the current exposure and the collateral held. A counterparty may have posted more collateral than the outstanding exposure, in which case there would not be exposure. As of December 31, 2003, Power’s trading operations had over 160 active counterparties.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
This combined Form 10-K is separately filed by Public Service Enterprise Group Incorporated (PSEG), Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power) and PSEG Energy Holdings LLC (Energy Holdings). Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and makes no representations as to any other company.
94
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, 2003 and 2002, and the related consolidated statements of operations, common stockholders’ equity and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the consolidated financial statement schedule listed in the Index in Item 15. These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and consolidated financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, the accompanying 2002 and 2001 consolidated financial statements have been restated.
As discussed in Note 3 to the consolidated financial statements, on January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets.”
As discussed in Note 3 to the consolidated financial statements, on January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”
DELOITTE & TOUCHE LLP
Parsippany, New Jersey
February 17, 2004
95
INDEPENDENT AUDITORS’ REPORT
To the Sole Stockholder and 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, 2003 and 2002, and the related consolidated statements of operations, common stockholder’s equity and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the consolidated financial statement schedule listed in the Index in Item 15. These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and consolidated financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.
DELOITTE & TOUCHE LLP | | | |
| | |
|
Parsippany, New Jersey
February 17, 2004 | | | |
96
INDEPENDENT AUDITORS’ REPORT
To the Sole Member and Board of Directors of
PSEG POWER LLC:
We have audited the consolidated balance sheets of PSEG Power LLC and its subsidiaries (the “Company”) as of December 31, 2003 and 2002, and the related consolidated statements of operations, capitalization and member’s equity and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the consolidated financial statement schedule listed in the Index in Item 15. These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and consolidated financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.
As discussed in Note 3 to the consolidated financial statements, on January 1, 2003, the Company adopted Statement of Financial Accounting Standards No. 143, “Accounting for Asset Retirement Obligations.”
DELOITTE & TOUCHE LLP | | | |
| | |
|
Parsippany, New Jersey
February 17, 2004 | | | |
97
INDEPENDENT AUDITORS’ REPORT
To the Sole Member and Board of Directors of
PSEG ENERGY HOLDINGS L.L.C.:
We have audited the consolidated balance sheets of PSEG Energy Holdings L.L.C. and its subsidiaries (the “Company”) as of December 31, 2003 and 2002, and the related consolidated statements of operations, member’s/stockholder’s equity and cash flows for each of the three years in the period ended December 31, 2003. Our audits also included the consolidated financial statement schedule listed in the Index in Item 15. These consolidated financial statements and the consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements and consolidated financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2003 and 2002, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly in all material respects, the information set forth therein.
As discussed in Note 2 to the consolidated financial statements, the accompanying 2002 and 2001 consolidated financial statements have been restated.
As discussed in Note 3 to the consolidated financial statements, on January 1, 2002, the Company adopted Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets.”
DELOITTE & TOUCHE LLP | | | |
| | |
|
Parsippany, New Jersey
February 17, 2004 | | | |
98
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions, except for Share Data)
| | For The Years Ended December 31, | |
| | | | As Restated, see Note 2 | |
| | 2003 | | 2002 | | 2001 | |
OPERATING REVENUES | | $ | 11,116 | | $ | 8,216 | | $ | 6,883 | |
OPERATING EXPENSES | | | | | | | | | | |
Energy Costs | | | 6,368 | | | 3,706 | | | 2,686 | |
Operation and Maintenance | | | 2,120 | | | 1,899 | | | 1,844 | |
Write-down of Project Investments | | | — | | | 511 | | | 7 | |
Depreciation and Amortization | | | 527 | | | 565 | | | 495 | |
Taxes Other Than Income Taxes | | | 136 | | | 131 | | | 121 | |
Total Operating Expenses | | | 9,151 | | | 6,812 | | | 5,153 | |
Income from Equity Method Investments | | | 114 | | | 119 | | | 178 | |
OPERATING INCOME | | | 2,079 | | | 1,523 | | | 1,908 | |
Other Income | | | 178 | | | 39 | | | 33 | |
Other Deductions | | | (101 | ) | | (80 | ) | | (21 | ) |
Interest Expense | | | (836 | ) | | (819 | ) | | (776 | ) |
Preferred Stock Dividends | | | (4 | ) | | (4 | ) | | (5 | ) |
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | | | 1,316 | | | 659 | | | 1,139 | |
Income Tax Expense | | | (464 | ) | | (254 | ) | | (373 | ) |
INCOME FROM CONTINUING OPERATIONS | | | 852 | | | 405 | | | 766 | |
Loss from Discontinued Operations, including Loss on Disposal, net of tax benefit of $8, $28 and $13 for the years ended 2003, 2002 and 2001, respectively | | | (44 | ) | | (49 | ) | | (12 | ) |
INCOME BEFORE EXTRAORDINARY ITEM AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE. | | | 808 | | | 356 | | | 754 | |
Extraordinary Item, net of tax benefit of $12 | | | (18 | ) | | — | | | — | |
Cumulative Effect of a Change in Accounting Principle, net of tax (expense) benefit of ($255), $66 and ($8)for the years ended 2003, 2002 and 2001, respectively | | | 370 | | | (121 | ) | | 10 | |
NET INCOME | | $ | 1,160 | | $ | 235 | | $ | 764 | |
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: | | | | | | | | | | |
BASIC | | | 228,222 | | | 208,647 | | | 207,737 | |
DILUTED | | | 228,824 | | | 208,813 | | | 208,226 | |
EARNINGS PER SHARE: | | | | | | | | | | |
BASIC | | | | | | | | | | |
INCOME FROM CONTINUING OPERATIONS | | $ | 3.73 | | $ | 1.94 | | $ | 3.68 | |
NET INCOME | | $ | 5.08 | | $ | 1.13 | | $ | 3.67 | |
DILUTED | | | | | | | | | | |
INCOME FROM CONTINUING OPERATIONS | | $ | 3.72 | | $ | 1.94 | | $ | 3.68 | |
NET INCOME | | $ | 5.07 | | $ | 1.13 | | $ | 3.67 | |
DIVIDENDS PAID PER SHARE OF COMMON STOCK | | $ | 2.16 | | $ | 2.16 | | $ | 2.16 | |
See Notes to Consolidated Financial Statements.
99
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions)
| | December 31, | |
| | | | As Restated,
see Note 2 | |
| | 2003 | | 2002 | |
CURRENT ASSETS | | | | | | | | |
Cash and Cash Equivalents | | $ | 548 | | $ | 171 | | |
Accounts Receivable, net of allowances of $40 and $47 in 2003 and 2002, respectively | | | 1,547 | | | 1,404 | | |
Unbilled Revenues | | | 261 | | | 275 | | |
Fuel | | | 527 | | | 413 | | |
Materials and Supplies | | | 227 | | | 203 | | |
Energy Trading Contracts | | | 101 | | | 157 | | |
Assets Held for Sale | | | — | | | 83 | | |
Prepayments | | | 164 | | | 73 | | |
Assets of Discontinued Operations | | | 298 | | | 419 | | |
Other | | | 44 | | | 91 | | |
Total Current Assets | | | 3,717 | | | 3,289 | | |
PROPERTY, PLANT AND EQUIPMENT | | | 17,406 | | | 16,374 | | |
Less: Accumulated Depreciation and Amortization | | | (4,984 | ) | | (4,734 | ) | |
Net Property, Plant and Equipment | | | 12,422 | | | 11,640 | | |
NONCURRENT ASSETS | | | | | | | | |
Regulatory Assets | | | 4,801 | | | 5,002 | | |
Long-Term Investments | | | 4,808 | | | 4,468 | | |
Nuclear Decommissioning Trust (NDT) Funds | | | 985 | | | 766 | | |
Other Special Funds | | | 470 | | | 72 | | |
Goodwill | | | 507 | | | 446 | | |
Other Intangibles | | | 103 | | | 206 | | |
Energy Trading Contracts | | | 12 | | | 21 | | |
Other | | | 230 | | | 225 | | |
Total Noncurrent Assets | | | 11,916 | | | 11,206 | | |
TOTAL ASSETS | | $ | 28,055 | | $ | 26,135 | | |
See Notes to Consolidated Financial Statements.
100
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND CAPITALIZATION
(Millions, except for Share Data)
| | December 31, | |
| | | | As Restated,
see Note 2 | |
| | 2003 | | 2002 | |
CURRENT LIABILITIES | | | | | | | |
Long-Term Debt Due Within One Year | | $ | 726 | | $ | 730 | |
Commercial Paper and Loans | | | 301 | | | 760 | |
Accounts Payable | | | 1,216 | | | 1,137 | |
Energy Trading Contracts | | | 72 | | | 101 | |
Accrued Taxes | | | 33 | | | 229 | |
Liabilities of Discontinued Operations | | | 242 | | | 324 | |
Other | | | 795 | | | 746 | |
Total Current Liabilities | | | 3,385 | | | 4,027 | |
NONCURRENT LIABILITIES | | | | | | | |
Deferred Income Taxes and Investment Tax Credits (ITC) | | | 4,196 | | | 2,903 | |
Regulatory Liabilities | | | 536 | | | 252 | |
Nuclear Decommissioning Liabilities | | | 284 | | | 766 | |
Other Postemployment Benefit (OPEB) Costs | | | 532 | | | 501 | |
Accrued Pension Costs | | | 67 | | | 336 | |
Cost of Removal | | | — | | | 524 | |
Other | | | 501 | | | 623 | |
Total Noncurrent Liabilities | | | 6,116 | | | 5,905 | |
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 17) | | | | | | | |
CAPITALIZATION | | | | | | | |
LONG-TERM DEBT | | | | | | | |
Long-Term Debt | | | 7,921 | | | 7,116 | |
Securitization Debt | | | 2,085 | | | 2,222 | |
Project Level, Non-Recourse Debt | | | 1,738 | | | 1,539 | |
Debt Supporting Trust Preferred Securities | | | 1,201 | | | 1,361 | |
Total Long-Term Debt | | | 12,945 | | | 12,238 | |
SUBSIDIARIES’ PREFERRED SECURITIES | | | | | | | |
Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2003 and 2002—795,234 shares | | | 80 | | | 80 | |
COMMON STOCKHOLDERS’ EQUITY | | | | | | | |
Common Stock, no par, authorized 500,000,000 shares; issued 2003—262,252,032 shares 2002—251,385,937 shares | | | 4,490 | | | 4,051 | |
Treasury Stock, at cost; 2003 and 2002—26,118,590 shares | | | (981 | ) | | (981 | ) |
Retained Earnings | | | 2,221 | | | 1,554 | |
Accumulated Other Comprehensive Loss | | | (201 | ) | | (739 | ) |
Total Common Stockholders’ Equity | | | 5,529 | | | 3,885 | |
Total Capitalization | | | 18,554 | | | 16,203 | |
TOTAL LIABILITIES AND CAPITALIZATION | | $ | 28,055 | | $ | 26,135 | |
See Notes to Consolidated Financial Statements.
101
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
| | For The Years Ended December 31, | |
| | | | As Restated, see
Note 2 | |
| | 2003 | | 2002 | | 2001 | |
CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | | | | |
Net Income | | $ | 1,160 | | $ | 235 | | $ | 764 | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | | | |
Extraordinary Item, net of tax | | | 18 | | | — | | | — | |
Loss on Disposal of Discontinued Operations, net of tax | | | 32 | | | 34 | | | — | |
Cumulative Effect of a Change in Accounting Principle, net of tax | | | (370 | ) | | 121 | | | (10 | ) |
Write-Down of Project Investments | | | — | | | 511 | | | 7 | |
Depreciation and Amortization | | | 527 | | | 565 | | | 495 | |
Amortization of Nuclear Fuel | | | 89 | | | 89 | | | 101 | |
Provision for Deferred Income Taxes (Other than Leases) and ITC | | | 368 | | | (139 | ) | | (116 | ) |
Non-Cash Employee Benefit Plan Costs | | | 258 | | | 193 | | | 158 | |
Leveraged Lease Income, Adjusted for Rents Received | | | 77 | | | (44 | ) | | (6 | ) |
Undistributed Earnings from Affiliates | | | 40 | | | (5 | ) | | (96 | ) |
Foreign Currency Transaction (Gain) Loss | | | (16 | ) | | 77 | | | 11 | |
Unrealized Losses (Gains) on Energy Contracts and Other Derivatives | | | 38 | | | (35 | ) | | 22 | |
Under Recovery of Electric Energy Costs (BGS and NTC) and Gas Costs | | | (38 | ) | | (60 | ) | | (87 | ) |
Under (Over) Recovery of SBC | | | (105 | ) | | 61 | | | 88 | |
Net Realized Gains and Income from NDT Fund | | | (65 | ) | | — | | | — | |
Other Non-Cash Charges (Credits) | | | 75 | | | (3 | ) | | (65 | ) |
Net Change in Certain Current Assets and Liabilities | | | (280 | ) | | 77 | | | 136 | |
Employee Benefit Plan Funding and Related Payments | | | (279 | ) | | (308 | ) | | (210 | ) |
Proceeds from the Withdrawal of Partnership Interests and Other Distributions | | | 66 | | | 54 | | | 124 | |
Other | | | (148 | ) | | (136 | ) | | (147 | ) |
Net Cash Provided By Operating Activities | | | 1,447 | | | (1,287 | ) | | 1,169 | |
CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | | | | |
Additions to Property, Plant and Equipment | | | (1,351 | ) | | (1,549 | ) | | (2,029 | ) |
Investments in Joint Ventures, Partnerships and Capital Leases | | | (36 | ) | | (242 | ) | | (597 | ) |
Proceeds from the Sale of Investments and Return of Capital from Partnerships | | | 47 | | | 398 | | | 146 | |
Acquisitions, Net of Cash Provided | | | — | | | (288 | ) | | (832 | ) |
Other | | | (24 | ) | | (34 | ) | | (175 | ) |
Net Cash Used In Investing Activities | | | (1,364 | ) | | (1,715 | ) | | (3,487 | ) |
CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | | | | |
Net Change in Short-Term Debt | | | (327 | ) | | (421 | ) | | (1,511 | ) |
Issuance of Long-Term Debt | | | 1,537 | | | 1,293 | | | 2,838 | |
Issuance of Non-Recourse Debt | | | 676 | | | 103 | | | 3,418 | |
Issuance of Participating Units | | | — | | | 446 | | | — | |
Issuance of Common Stock | | | 441 | | | 521 | | | — | |
Issuance of Preferred Securities | | | — | | | 174 | | | — | |
Redemptions of Long-Term Debt | | | (1,303 | ) | | (1,213 | ) | | (1,304 | ) |
Redemptions of Preferred Securities | | | (155 | ) | | — | | | (448 | ) |
Purchase of Treasury Stock | | | — | | | — | | | (91 | ) |
Cash Dividends Paid on Common Stock | | | (493 | ) | | (456 | ) | | (448 | ) |
Distributions to (Proceeds from) Minority Shareholders | | | (48 | ) | | 5 | | | (61 | ) |
Other | | | (36 | ) | | (7 | ) | | (4 | ) |
Net Cash Provided By Financing Activities | | | 292 | | | 445 | | | 2,389 | |
Effect of Exchange Rate Change | | | 2 | | | (13 | ) | | — | |
Net Change In Cash and Cash Equivalents | | | 377 | | | 4 | | | 71 | |
Cash and Cash Equivalents at Beginning of Period | | | 171 | | | 167 | | | 96 | |
Cash and Cash Equivalents at End of Period | | $ | 548 | | $ | 171 | | $ | 167 | |
Supplemental Disclosure of Cash Flow Information: | | | | | | | | | | |
Income Taxes (Received) Paid | | $ | (21 | ) | $ | 145 | | $ | 87 | |
Interest Paid, Net of Amounts Capitalized | | $ | 975 | | $ | 843 | | $ | 713 | |
See Notes to Consolidated Financial Statements.
102
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
(Millions)
| | Common
Stock | | Treasury
Stock | | As
Restated,
see Note 2 | | As
Restated,
see Note 2 | | As
Restated,
see Note 2 | | |
Accumulated
Other
Comprehensive
Loss | |
Retained
Earnings | |
Shs. | | Amount | Shs. | | Amount | Total | |
Balance as of January 1, 2001 | | 232 | | $ | 3,604 | | (24 | ) | $ | (895 | ) | $ | 1,459 | | | $ | (222 | ) | | $ | 3,946 | | |
Net Income | | — | | | — | | — | | | — | | | 764 | | | | — | | | | 764 | | |
Other Comprehensive Income (Loss), net of tax: | | | | | | | | | | | | | | | | | | | | | | | |
Currency Translation Adjustment, net of tax $(7) | | — | | | — | | — | | | — | | | — | | | | (68 | ) | | | (68 | ) | |
Change in Fair Value of Derivative Instruments, net of tax $(31) | | — | | | — | | — | | | — | | | — | | | | (39 | ) | | | (39 | ) | |
Cumulative Effect of Change in Accounting Principle, net of tax $ (14) | | — | | | — | | — | | | — | | | — | | | | (15 | ) | | | (15 | ) | |
Reclassification Adjustments for Net Amounts Included in Net Income, net of tax of $19 | | — | | | — | | — | | | — | | | — | | | | 25 | | | | 25 | | |
Pension Adjustments, net of tax $ (1) | | — | | | — | | — | | | — | | | — | | | | 2 | | | | 2 | | |
Change in Fair Value of Equity Investments, net of tax $(1) | | — | | | — | | — | | | — | | | — | | | | (2 | ) | | | (2 | ) | |
Other Comprehensive Loss | | — | | | — | | — | | | — | | | — | | | | — | | | | (97 | ) | |
Comprehensive Income | | | | | | | | | | | | | | | | | | | | | 667 | | |
Cash Dividends on Common Stock | | — | | | — | | — | | | — | | | (448 | ) | | | — | | | | (448 | ) | |
Purchase of Treasury Stock | | — | | | — | | (2 | ) | | (91 | ) | | — | | | | — | | | | (91 | ) | |
Other | | — | | | (5 | ) | — | | | 5 | | | (6 | ) | | | — | | | | (6 | ) | |
Balance as of December 31, 2001 | | 232 | | $ | 3,599 | | (26 | ) | $ | (981 | ) | $ | 1,769 | | | $ | (319 | ) | | $ | 4,068 | | |
Net Income | | — | | | — | | — | | | — | | | 235 | | | | — | | | | 235 | | |
Other Comprehensive Income (Loss), net of tax: | | | | | | | | | | | | | | | | | | | | | | | |
Currency Translation Adjustment, net of tax $(45) | | — | | | — | | — | | | — | | | — | | | | (140 | ) | | | (140 | ) | |
Reclassification Adjustment for Losses Included in Net Income | | — | | | — | | — | | | — | | | — | | | | 68 | | | | 68 | | |
Change in Fair Value of Derivative Instruments, net of tax $(13) | | — | | | — | | — | | | — | | | — | | | | (60 | ) | | | (60 | ) | |
Reclassification Adjustments for Net Amounts Included in Net Income | | — | | | — | | — | | | — | | | — | | | | 9 | | | | 9 | | |
Settlement Adjustments Related to Projects Under Construction | | | | | | | | | | | | | | | | | (3 | ) | | | (3 | ) | |
Minimum Pension Liability, net of tax $ (201) | | — | | | — | | — | | | — | | | — | | | | (293 | ) | | | (293 | ) | |
Change in Fair Value of Equity Investments | | — | | | — | | — | | | — | | | — | | | | (1 | ) | | | (1 | ) | |
Other Comprehensive Loss | | — | | | — | | — | | | — | | | — | | | | — | | | | (420 | ) | |
Comprehensive Loss | | | | | | | | | | | | | | | | | | | | | (185 | ) | |
Cash Dividends on Common Stock | | — | | | — | | — | | | — | | | (456 | ) | | | — | | | | (456 | ) | |
Issuance of Equity | | 19 | | | 536 | | — | | | — | | | — | | | | — | | | | 536 | | |
Issuance Costs and Other | | — | | | (84 | ) | — | | | — | | | 6 | | | | — | | | | (78 | ) | |
Balance as of December 31, 2002 | | 251 | | $ | 4,051 | | (26 | ) | $ | (981 | ) | $ | 1,554 | | | $ | (739 | ) | | $ | 3,885 | | |
Net Income | | — | | | — | | — | | | — | | | 1,160 | | | | — | | | | 1,160 | | |
Other Comprehensive Income (Loss), net of tax: | | | | | | | | | | | | | | | | | | | | | | | |
Currency Translation Adjustment, net of tax $(4) | | — | | | — | | — | | | — | | | — | | | | 164 | | | | 164 | | |
Available for Sale Securities, net of tax $81 | | — | | | — | | — | | | — | | | — | | | | 118 | | | | 118 | | |
Change in Fair Value of Derivative Instruments, net of tax $(32) | | — | | | — | | — | | | — | | | — | | | | (57 | ) | | | (57 | ) | |
Reclassification Adjustments for Net Amounts Included in Net Income | | — | | | — | | — | | | — | | | — | | | | 32 | | | | 32 | | |
Settlement Adjustments Related to Projects Under Construction | | — | | | — | | — | | | — | | | — | | | | (11 | ) | | | (11 | ) | |
Minimum Pension Liability, net of tax $200 | | — | | | — | | — | | | — | | | — | | | | 289 | | | | 289 | | |
Change in Fair Value of Equity Investments | | — | | | — | | — | | | — | | | — | | | | 3 | | | | 3 | | |
Other Comprehensive Income | | — | | | — | | — | | | — | | | — | | | | — | | | | 538 | | |
Comprehensive Income | | | | | | | | | | | | | | | | | | | | | 1,698 | | |
Cash Dividends on Common Stock | | — | | | — | | — | | | — | | | (493 | ) | | | — | | | | (493 | ) | |
Issuance of Equity | | 11 | | | 452 | | — | | | — | | | — | | | | — | | | | 452 | | |
Issuance Costs and Other | | — | | | (13 | ) | — | | | — | | | — | | | | — | | | | (13 | ) | |
Balance as of December 31, 2003 | | 262 | | $ | 4,490 | | (26 | ) | $ | (981 | ) | $ | 2,221 | | | $ | (201 | ) | | $ | 5,529 | | |
See Notes to Consolidated Financial Statements.
103
[THIS PAGE INTENTIONALLY LEFT BLANK]
104
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
| | For The Years Ended December 31, | |
| | 2003 | | 2002 | | 2001 | |
| | | | | | | �� | | | |
OPERATING REVENUES | | $ | 6,740 | | $ | 5,919 | | $ | 6,091 | |
OPERATING EXPENSES | | | | | | | | | | |
Energy Costs. | | | 4,421 | | | 3,684 | | | 3,913 | |
Operation and Maintenance | | | 1,050 | | | 982 | | | 996 | |
Depreciation and Amortization | | | 372 | | | 409 | | | 370 | |
Taxes Other Than Income Taxes | | | 136 | | | 131 | | | 121 | |
Total Operating Expenses | | | 5,979 | | | 5,206 | | | 5,400 | |
OPERATING INCOME | | | 761 | | | 713 | | | 691 | |
Other Income | | | 6 | | | 15 | | | 95 | |
Other Deductions | | | (1 | ) | | (2 | ) | | (4 | ) |
Interest Expense | | | (390 | ) | | (406 | ) | | (458 | ) |
INCOME BEFORE INCOME TAXES AND EXTRAORDINARY ITEM | | | 376 | | | 320 | | | 324 | |
Income Tax Expense | | | (129 | ) | | (115 | ) | | (89 | ) |
INCOME BEFORE EXTRAORDINARY ITEM | | | 247 | | | 205 | | | 235 | |
Extraordinary Item, net of tax benefit of $12 | | | (18 | ) | | — | | | — | |
NET INCOME | | | 229 | | | 205 | | | 235 | |
Preferred Stock Dividends | | | (4 | ) | | (4 | ) | | (5 | ) |
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED | | $ | 225 | | $ | 201 | | $ | 230 | |
See disclosures regarding Public Service Electric and Gas Company included in the
Notes to Consolidated Financial Statements.
105
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions)
| | December 31, | |
| | 2003 | | 2002 | |
CURRENT ASSETS | | | | | | | |
Cash and Cash Equivalents | | $ | 140 | | $ | 35 | |
Accounts Receivable, net of allowances of $34 and $32 in 2003 and 2002, respectively | | | 804 | | | 769 | |
Unbilled Revenues | | | 261 | | | 275 | |
Materials and Supplies | | | 50 | | | 45 | |
Prepayments | | | 44 | | | 25 | |
Other | | | 22 | | | 17 | |
Total Current Assets | | | 1,321 | | | 1,166 | |
PROPERTY, PLANT AND EQUIPMENT | | | 9,793 | | | 9,581 | |
Less: Accumulated Depreciation and Amortization | | | (3,258 | ) | | (3,211 | ) |
Net Property, Plant and Equipment | | | 6,535 | | | 6,370 | |
NONCURRENT ASSETS | | | | | | | |
Regulatory Assets | | | 4,801 | | | 5,002 | |
Long-Term Investments | | | 131 | | | 128 | |
Other Special Funds | | | 272 | | | 44 | |
Intangibles | | | 2 | | | 60 | |
Other | | | 74 | | | 71 | |
Total Noncurrent Assets | | | 5,280 | | | 5,305 | |
TOTAL ASSETS | | $ | 13,136 | | $ | 12,841 | |
See disclosures regarding Public Service Electric and Gas Company included in the
Notes to Consolidated Financial Statements.
106
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND CAPITALIZATION
(Millions, except for Share Data)
| | December 31, | |
| | 2003 | | 2002 | |
CURRENT LIABILITIES | | | | | | | |
Long-Term Debt Due Within One Year | | $ | 423 | | $ | 429 | |
Commercial Paper and Loans | | | — | | | 224 | |
Accounts Payable | | | 286 | | | 336 | |
Accounts Payable — Affiliated Companies net | | | 405 | | | 388 | |
Clean Energy Program | | | 110 | | | 18 | |
Other | | | 322 | | | 311 | |
Total Current Liabilities | | | 1,546 | | | 1,706 | |
NONCURRENT LIABILITIES | | | | | | | |
Deferred Income Taxes and ITC | | | 2,715 | | | 2,436 | |
OPEB Costs | | | 509 | | | 486 | |
Regulatory Liabilities | | | 536 | | | 252 | |
Cost of Removal | | | — | | | 393 | |
Accrued Pension Costs | | | 16 | | | 175 | |
Other | | | 145 | | | 209 | |
Total Noncurrent Liabilities | | | 3,921 | | | 3,951 | |
| | | | | | | |
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 17) | | | | | | | |
| | | | | | | |
CAPITALIZATION | | | | | | | |
LONG-TERM DEBT | | | | | | | |
Long-Term Debt | | | 3,044 | | | 2,627 | |
Securitization Debt | | | 2,085 | | | 2,222 | |
Debt Supporting Trust Preferred Securities | | | — | | | 160 | |
Total Long-Term Debt | | | 5,129 | | | 5,009 | |
PREFERRED SECURITIES | | | | | | | |
Preferred Stock Without Mandatory Redemption, $100 par value, 7,500,000 authorized; issued and outstanding, 2003 and 2002 — 795,234 shares | | | 80 | | | 80 | |
COMMON STOCKHOLDER’S EQUITY | | | | | | | |
Common Stock; 150,000,000 shares authorized, 132,450,344 shares issued and outstanding | | | 892 | | | 892 | |
Contributed Capital | | | 170 | | | — | |
Basis Adjustment | | | 986 | | | 986 | |
Retained Earnings | | | 414 | | | 389 | |
Accumulated Other Comprehensive Loss | | | (2 | ) | | (172 | ) |
Total Common Stockholder’s Equity | | | 2,460 | | | 2,095 | |
Total Capitalization | | | 7,669 | | | 7,184 | |
TOTAL LIABILITIES AND CAPITALIZATION | | $ | 13,136 | | $ | 12,841 | |
See disclosures regarding Public Service Electric and Gas Company included in the
Notes to Consolidated Financial Statements.
107
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
| | For The Years Ended
December 31, | |
| | 2003 | | | 2002 | | 2001 | |
CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | | | | | |
Net Income | | $ | 229 | | $ | 205 | | $ | 235 | | |
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities: | | | | | | | | | | | |
Extraordinary Item, net of tax benefit | | | 18 | | | — | | | — | | |
Depreciation and Amortization | | | 372 | | | 409 | | | 370 | | |
Provision for Deferred Income Taxes and ITC | | | 132 | | | (21 | ) | | (201 | ) | |
Non-Cash Employee Benefit Plan Costs | | | 179 | | | 141 | | | 125 | | |
Non-Cash Interest Expense | | | 50 | | | 18 | | | (6 | ) | |
(Under) Over Recovery of Electric Energy Costs (BGS and NTC) | | | (139 | ) | | (19 | ) | | 56 | | |
Over (Under) Recovery of Gas Costs | | | 101 | | | (41 | ) | | (143 | ) | |
(Under) Over Recovery of SBC | | | (105 | ) | | 61 | | | 88 | | |
Gain on the Sale of Property, Plant and Equipment | | | (11 | ) | | (10 | ) | | (4 | ) | |
Other Non-Cash Credits | | | (1 | ) | | (17 | ) | | (1 | ) | |
Net Changes in Certain Current Assets and Liabilities: | | | | | | | | | | | |
Accounts Receivable and Unbilled Revenues | | | (21 | ) | | (154 | ) | | 127 | | |
Natural Gas | | | — | | | 415 | | | (43 | ) | |
Materials and Supplies | | | (5 | ) | | 5 | | | (2 | ) | |
Prepayments | | | (19 | ) | | 15 | | | (35 | ) | |
Accrued Taxes | | | 2 | | | (22 | ) | | 5 | | |
Accrued Interest | | | 2 | | | (13 | ) | | 11 | | |
Accounts Payable | | | (33 | ) | | 82 | | | 56 | | |
Other Current Assets and Liabilities | | | 109 | | | — | | | 20 | | |
Employee Benefit Plan Funding and Related Payments | | | (177 | ) | | (198 | ) | | (139 | ) | |
Other | | | (78 | ) | | (26 | ) | | (82 | ) | |
Net Cash Provided By Operating Activities | | | 605 | | | 830 | | | 437 | | |
CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | | | | | |
Additions to Property, Plant and Equipment | | | (411 | ) | | (447 | ) | | (351 | ) | |
Proceeds from the Sale of Property, Plant and Equipment—Affiliate | | | 53 | | | — | | | — | | |
Proceeds from the Sale of Property, Plant and Equipment | | | 13 | | | 10 | | | 4 | | |
Return of Capital from Trusts | | | 5 | | | — | | | 11 | | |
Net Cash Used In Investing Activities | | | (340 | ) | | (437 | ) | | (362 | ) | |
CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | | | | | |
Net Change in Short-Term Debt | | | (224 | ) | | 224 | | | (1,543 | ) | |
Issuance of Securitization Debt | | | — | | | — | | | 2,525 | | |
Issuance of Long-Term Debt | | | 909 | | | 300 | | | — | | |
Redemption of Securitization Debt | | | (129 | ) | | (120 | ) | | (53 | ) | |
Redemption of Long-Term Debt | | | (514 | ) | | (547 | ) | | (528 | ) | |
Redemption of Preferred Securities | | | (155 | ) | | — | | | (448 | ) | |
Capital Lease Payments | | | (3 | ) | | (6 | ) | | (6 | ) | |
Contributed Capital | | | 170 | | | — | | | — | | |
Return of Capital | | | — | | | — | | | (2,265 | ) | |
Deferred Issuance Costs | | | (10 | ) | | (2 | ) | | (201 | ) | |
Collection of Note Receivable—Affiliated Company | | | — | | | — | | | 2,786 | | |
Cash Dividends Paid on Common Stock | | | (200 | ) | | (305 | ) | | (274 | ) | |
Preferred Stock Dividends | | | (4 | ) | | (4 | ) | | (5 | ) | |
Net Cash Used In Financing Activities | | | (160 | ) | | (460 | ) | | (12 | ) | |
Net Change In Cash and Cash Equivalents | | | 105 | | | (67 | ) | | 63 | | |
Cash and Cash Equivalents at Beginning of Period | | | 35 | | | 102 | | | 39 | | |
Cash and Cash Equivalents at End of Period | | $ | 140 | | $ | 35 | | $ | 102 | | |
Supplemental Disclosure of Cash Flow Information: | | | | | | | | | | | |
Income Taxes Paid | | $ | 16 | | $ | 161 | | $ | 264 | | |
Interest Paid, Net of Amounts Capitalized | | $ | 371 | | $ | 428 | | $ | 427 | | |
See disclosures regarding Public Service Electric and Gas Company included in the
Notes to Consolidated Financial Statements.
108
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
(Millions)
| | Common
Stock | | Contributed
Capital from
PSEG | | Basis
Adjustment | | Retained
Earnings | | Accumulated
Other
Comprehensive
Loss | | Total | |
| | | | | | | | | | | | | | | | | | | | | | | | |
Balance as of January 1, 2001 | | $ | 2,563 | | | $ | 594 | | | $ | 986 | | | $ | 375 | | | $ | (3 | ) | | $ | 4,515 | |
Net Income | | | — | | | | — | | | | — | | | | 235 | | | | — | | | | 235 | |
Other Comprehensive Income, net of tax: | | | | | | | | | | | | | | | | | | | | | | | | |
Pension Adjustments, netof tax $1 | | | — | | | | — | | | | — | | | | — | | | | 2 | | | | 2 | |
Comprehensive Income | | | | | | | | | | | | | | | | | | | | | | | 237 | |
Cash Dividends on Common Stock | | | — | | | | — | | | | — | | | | (112 | ) | | | — | | | | (112 | ) |
Cash Dividends on Preferred Stock | | | — | | | | — | | | | — | | | | (5 | ) | | | — | | | | (5 | ) |
Return of Capital | | | (1,671 | ) | | | (594 | ) | | | — | | | | — | | | | — | | | | (2,265 | ) |
Balance as of December 31, 2001 | | $ | 892 | | | $ | — | | | $ | 986 | | | $ | 493 | | | $ | (1 | ) | | $ | 2,370 | |
Net Income | | | — | | | | — | | | | — | | | | 205 | | | | — | | | | 205 | |
Other Comprehensive Loss, net of tax: | | | | | | | | | | | | | | | | | | | | | | | | |
Minimum Pension Liability, net of tax $(104) | | | — | | | | — | | | | — | | | | — | | | | (171 | ) | | | (171 | ) |
Comprehensive Income | | | | | | | | | | | | | | | | | | | | | | | 34 | |
Cash Dividends on Common Stock | | | — | | | | — | | | | — | | | | (305 | ) | | | — | | | | (305 | ) |
Cash Dividends on Preferred Stock | | | — | | | | — | | | | — | | | | (4 | ) | | | — | | | | (4 | ) |
Balance as of December 31, 2002 | | $ | 892 | | | $ | — | | | $ | 986 | | | $ | 389 | | | $ | (172 | ) | | $ | 2,095 | |
Net Income | | | — | | | | — | | | | — | | | | 229 | | | | — | | | | 229 | |
Other Comprehensive Income, net of tax: | | | | | | | | | | | | | | | | | | | | | | | | |
Minimum Pension Liability, net of tax $117 | | | — | | | | — | | | | — | | | | — | | | | 170 | | | | 170 | |
Comprehensive Income | | | | | | | | | | | | | | | | | | | | | | | 399 | |
Cash Dividends on Common Stock | | | — | | | | — | | | | — | | | | (200 | ) | | | — | | | | (200 | ) |
Cash Dividends on Preferred Stock | | | — | | | | — | | | | — | | | | (4 | ) | | | — | | | | (4 | ) |
Contributed Capital | | | — | | | | 170 | | | | — | | | | — | | | | — | | | | 170 | |
Balance as of December 31, 2003 | | $ | 892 | | | $ | 170 | | | $ | 986 | | | $ | 414 | | | $ | (2 | ) | | $ | 2,460 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
See disclosures regarding Public Service Electric and Gas Company included in the
Notes to Consolidated Financial Statements.
109
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
| | For the Years Ended
December 31, | |
| | 2003 | | 2002 | | 2001 | |
OPERATING REVENUES | | $ | 5,605 | | $ | 3,636 | | $ | 2,464 | |
OPERATING EXPENSES | | | | | | | | | | |
Energy Costs | | | 3,746 | | | 1,852 | | | 844 | |
Operation and Maintenance | | | 914 | | | 773 | | | 738 | |
Depreciation and Amortization | | | 102 | | | 108 | | | 95 | |
Total Operating Expenses | | | 4,762 | | | 2,733 | | | 1,677 | |
OPERATING INCOME | | | 843 | | | 903 | | | 787 | |
Other Income | | | 149 | | | 1 | | | — | |
Other Deductions | | | (78 | ) | | (1 | ) | | — | |
Interest Expense | | | (114 | ) | | (122 | ) | | (143 | ) |
INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE | | | 800 | | | 781 | | | 644 | |
Income Tax Expense | | | (326 | ) | | (313 | ) | | (250 | ) |
INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE | | | 474 | | | 468 | | | 394 | |
Cumulative Effect of a Change in Accounting Principle, net of tax expense of $255 | | | 370 | | | — | | | — | |
EARNINGS AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED | | $ | 844 | | $ | 468 | | $ | 394 | |
See disclosures regarding PSEG Power LLC included in the
Notes to Consolidated Financial Statements.
110
PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS
(Millions)
| | December 31, | |
| | 2003 | | 2002 | |
A S S E T S | | | | | | | |
CURRENT ASSETS | | | | | | | |
Cash and Cash Equivalents | | $ | 66 | | $ | 26 | |
Accounts Receivable | | | 615 | | | 527 | |
Accounts Receivable — Affiliated Companies, net | | | 240 | | | 238 | |
Short-Term Loan to Affiliate | | | 77 | | | — | |
Fuel | | | 516 | | | 406 | |
Materials and Supplies | | | 162 | | | 148 | |
Energy Trading Contracts | | | 101 | | | 157 | |
Other | | | 32 | | | 72 | |
Total Current Assets | | | 1,809 | | | 1,574 | |
PROPERTY, PLANT AND EQUIPMENT | | | 5,980 | | | 5,342 | |
Less: Accumulated Depreciation and Amortization | | | (1,399 | ) | | (1,302 | ) |
Net Property, Plant and Equipment | | | 4,581 | | | 4,040 | |
NON CURRENT ASSETS | | | | | | | |
Deferred Income Taxes and Investment Tax Credits (ITC) | | | 24 | | | 547 | |
Nuclear Decommissioning Trust (NDT) Funds | | | 985 | | | 766 | |
Intangibles | | | 108 | | | 141 | |
Energy Trading Contracts | | | 12 | | | 21 | |
Other Special Funds | | | 115 | | | 10 | |
Other | | | 94 | | | 118 | |
Total Noncurrent Assets | | | 1,338 | | | 1,603 | |
TOTAL ASSETS | | $ | 7,728 | | $ | 7,217 | |
L I A B I L I T I E S A N D M E M B E R’S E Q U I T Y | | | | | | | |
CURRENT LIABILITIES | | | | | | | |
Accounts Payable | | $ | 800 | | $ | 690 | |
Short-Term Loan from Affiliate | | | — | | | 239 | |
Energy Trading Contracts | | | 72 | | | 101 | |
Other | | | 207 | | | 282 | |
Total Current Liabilities | | | 1,079 | | | 1,312 | |
NON CURRENT LIABILITIES | | | | | | | |
Nuclear Decommissioning Liabilities | | | 284 | | | 766 | |
Cost of Removal | | | — | | | 131 | |
Environmental Costs | | | 58 | | | 59 | |
Accrued Pension Costs | | | 14 | | | 101 | |
Other | | | 72 | | | 93 | |
Total Noncurrent Liabilities | | | 428 | | | 1,150 | |
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 17) | | | | | | | |
| | | | | | | |
LONG-TERM DEBT | | | | | | | |
Project Level, Non-Recourse Debt | | | 800 | | | 800 | |
Long-Term Debt | | | 2,816 | | | 2,516 | |
Total Long-Term Debt | | | 3,616 | | | 3,316 | |
MEMBER’S EQUITY | | | | | | | |
Contributed Capital | | | 1,700 | | | 1,550 | |
Basis Adjustment | | | (986 | ) | | (986 | ) |
Retained Earnings | | | 1,810 | | | 966 | |
Accumulated Other Comprehensive Income (Loss) | | | 81 | | | (91 | ) |
Total Member’s Equity | | | 2,605 | | | 1,439 | |
TOTAL LIABILITIES AND MEMBER’S EQUITY | | $ | 7,728 | | $ | 7,217 | |
See disclosures regarding PSEG Power LLC included in the
Notes to Consolidated Financial Statements.
111
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
| | For the Years Ended
December 31, | |
| | 2003 | | 2002 | | 2001 | |
CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | | | | |
Net Income | | $ | 844 | | $ | 468 | | $ | 394 | |
Adjustments to Reconcile Net Income to Net Cash Flows from | | | | | | | | | | |
Operating Activities: | | | | | | | | | | |
Cumulative Effect of a Change in Accounting Principle, net of tax | | | (370 | ) | | — | | | — | |
Depreciation and Amortization | | | 102 | | | 108 | | | 95 | |
Amortization of Nuclear Fuel | | | 89 | | | 89 | | | 101 | |
Interest Accretion on NDT Liability | | | 24 | | | — | | | — | |
Provision for Deferred Income Taxes | | | 151 | | | 88 | | | 94 | |
Unrealized Losses (Gains) on Energy Contracts and Derivatives | | | 33 | | | (23 | ) | | 22 | |
Non-Cash Employee Benefit Plan Costs | | | 54 | | | 32 | | | 20 | |
Net Realized Gains and Income on NDT Fund | | | (65 | ) | | — | | | — | |
Net Changes in Certain Current Assets and Liabilities | | | | | | | | | | |
Fuel, Materials and Supplies | | | (125 | ) | | (329 | ) | | (35 | ) |
Accounts Receivable | | | (90 | ) | | (212 | ) | | 2 | |
Accounts Payable | | | 110 | | | 263 | | | (84 | ) |
Other Current Assets and Liabilities | | | (37 | ) | | 94 | | | 80 | |
Employee Benefit Plan Funding and Other Payments | | | (70 | ) | | (76 | ) | | (34 | ) |
Other | | | (70 | ) | | (85 | ) | | (80 | ) |
Net Cash Provided By Operating Activities | | | 580 | | | 417 | | | 575 | |
CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | | | | |
Additions to Property, Plant and Equipment | | | (655 | ) | | (1,046 | ) | | (1,592 | ) |
Short-Term Loan—Affiliate | | | (77 | ) | | — | | | — | |
Acquisition of Generation Businesses, net of cash | | | — | | | (271 | ) | | (22 | ) |
Proceeds from the Sale of Property, Plant and Equipment | | | — | | | 47 | | | 30 | |
Other | | | (17 | ) | | (29 | ) | | (29 | ) |
Net Cash Used In Investing Activities | | | (749 | ) | | (1,299 | ) | | (1,613 | ) |
CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | | | | |
Issuance of Recourse Long-Term Debt | | | 300 | | | 600 | | | 1,915 | |
Issuance of Non-Recourse Long-Term Debt | | | — | | | 30 | | | 770 | |
Proceeds from Contributed Capital | | | 150 | | | 200 | | | 1,200 | |
Deferred Issuance Costs | | | (2 | ) | | (6 | ) | | (16 | ) |
Repayment of Note Payable—Affilated Company | | | — | | | — | | | (2,786 | ) |
Short-Term Loan (Repayment)—Affiliate | | | (239 | ) | | 75 | | | (56 | ) |
Net Cash Provided By Financing Activities | | | 209 | | | 899 | | | 1,027 | |
Net Change In Cash and Cash Equivalents | | | 40 | | | 17 | | | (11 | ) |
Cash and Cash Equivalents at Beginning of Period | | | 26 | | | 9 | | | 20 | |
Cash and Cash Equivalents at End of Period | | $ | 66 | | $ | 26 | | $ | 9 | |
Supplemental Disclosure of Cash Flow Information: | | | | | | | | | | |
Property, Plant, and Equipment Assumed from Acquisitions | | $ | — | | $ | 235 | | $ | 24 | |
Income Taxes Paid | | $ | 99 | | $ | 91 | | $ | 166 | |
Interest Paid, Net of Amounts Capitalized | | $ | 217 | | $ | 200 | | $ | 197 | |
See disclosures regarding PSEG Power LLC included in the
Notes to Consolidated Financial Statements.
112
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF CAPITALIZATION AND MEMBER’S EQUITY
(Millions)
| | Contributed
Capital | | Basis
Adjustment | | Retained
Earnings | | Accumulated
Other
Comprehensive
Income (Loss) | | Total
Member's
Equity |
Balance as of January 1, 2001 | | $ | 150 | | | | $ | (986 | ) | | $ | 104 | | | | $ | — | | | | $ | (732 | ) |
Net Income | | | — | | | | | — | | | | 394 | | | | | — | | | | | 394 | |
Other Comprehensive Income (Loss), net of tax: | | | | | | | | | | | | | | | | | | | | | | | |
Change in Fair Value of Derivative Instruments, net of tax $(16) | | | — | | | | | — | | | | — | | | | | (23 | ) | | | | (23 | ) |
Reclassification Adjustments for Net Amount included in Net Income, net of tax $14 | | | — | | | | | — | | | | — | | | | | 21 | | | | | 21 | |
Other Comprehensive Loss | | | — | | | | | — | | | | — | | | | | — | | | | | (2 | ) |
Comprehensive Income | | | | | | | | | | | | | | | | | | | | | | 392 | |
Contributed Capital | | | 1,200 | | | | | — | | | | — | | | | | — | | | | | 1,200 | |
Balance as of December 31, 2001 | | $ | 1,350 | | | | $ | (986 | ) | | $ | 498 | | | | $ | (2 | ) | | | $ | 860 | |
Net Income | | | — | | | | | — | | | | 468 | | | | | — | | | | | 468 | |
Other Comprehensive Income (Loss), net of tax: | | | | | | | | | | | | | | | | | | | | | | | |
Change in Fair Value of Derivative Instruments, net of tax $(3) | | | — | | | | | — | | | | — | | | | | (5 | ) | | | | (5 | ) |
Pension Adjustments, net of tax $(50) | | | — | | | | | — | | | | — | | | | | (84 | ) | | | | (84 | ) |
Other Comprehensive Loss | | | — | | | | | — | | | | — | | | | | — | | | | | (89 | ) |
Comprehensive Income | | | | | | | | | | | | | | | | | | | | | | 379 | |
Contributed Capital | | | 200 | | | | | — | | | | — | | | | | — | | | | | 200 | |
Balance as of December 31, 2002 | | $ | 1,550 | | | | $ | (986 | ) | | $ | 966 | | | | $ | (91 | ) | | | $ | 1,439 | |
Net Income | | | — | | | | | — | | | | 844 | | | | | — | | | | | 844 | |
Other Comprehensive Income (Loss), net of tax: | | | | | | | | | | | | | | | | | | | | | | | |
Available for Sale Securities, net of tax $81 | | | — | | | | | — | | | | — | | | | | 118 | | | | | 118 | |
Change in Fair Value of Derivative Instruments, net of tax $(21) | | | — | | | | | — | | | | — | | | | | (40 | ) | | | | (40 | ) |
Reclassification Adjustments for Net Amount Included in Net Income | | | — | | | | | — | | | | — | | | | | 11 | | | | | 11 | |
Pension Adjustments, net of tax $58 | | | — | | | | | — | | | | — | | | | | 83 | | | | | 83 | |
Other Comprehensive Income | | | — | | | | | — | | | | — | | | | | — | | | | | 172 | |
Comprehensive Income | | | | | | | | | | | | | | | | | | | | | | 1,016 | |
Contributed Capital | | | 150 | | | | | — | | | | — | | | | | — | | | | | 150 | |
Balance as of December 31, 2003 | | $ | 1,700 | | | | $ | (986 | ) | | $ | 1,810 | | | | $ | 81 | | | | $ | 2,605 | |
See disclosures regarding PSEG Power LLC included in the
Notes to Consolidated Financial Statements.
113
[THIS PAGE INTENTIONALLY LEFT BLANK]
114
PSEG ENERGY HOLDINGS LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
(Millions)
| | For The Years Ended December 31, | |
| | | | | | As Restated, see Note 2 | |
| | | | 2003 | | | | 2002 | | | | 2001 | | |
OPERATING REVENUES | | | | | | | | | | | | | | |
Electric Generation and Distribution Revenues | | | $ | 431 | | | $ | 304 | | | $ | 128 | | |
Income from Capital and Operating Leases | | | | 217 | | | | 260 | | | | 214 | | |
Other | | | | 77 | | | | 45 | | | | 112 | | |
Total Operating Revenues | | | | 725 | | | | 609 | | | | 454 | | |
OPERATING EXPENSES | | | | | | | | | | | | | | |
Energy Costs | | | | 155 | | | | 118 | | | | 55 | | |
Operation and Maintenance | | | | 176 | | | | 168 | | | | 122 | | |
Write-down of Project Investments | | | | — | | | | 511 | | | | 7 | | |
Depreciation and Amortization | | | | 44 | | | | 28 | | | | 15 | | |
Total Operating Expenses | | | | 375 | | | | 825 | | | | 199 | | |
Income from Equity Method Investments | | | | 114 | | | | 119 | | | | 178 | | |
OPERATING INCOME (LOSS) | | | | 464 | | | | (97 | ) | | | 433 | | |
Other Income | | | | 20 | | | | 26 | | | | 4 | | |
Other Deductions | | | | (5 | ) | | | (77 | ) | | | (17 | ) | |
Interest Expense | | | | (218 | ) | | | (217 | ) | | | (183 | ) | |
INCOME (LOSS) BEFORE INCOME TAXES, MINORITY INTEREST, DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE | | | | 261 | | | | (365 | ) | | | 237 | | |
Income Tax (Expense) Benefit | | | | (59 | ) | | | 144 | | | | (58 | ) | |
Minority Interests in (Earnings) Losses of Subsidiaries | | | | (13 | ) | | | 1 | | | | — | | |
INCOME (LOSS) BEFORE DISCONTINUED OPERATIONS AND CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE | | | | 189 | | | | (220 | ) | | | 179 | | |
Loss From Discontinued Operations, net of tax benefit of $4, $10, and $13 for the years ended 2003, 2002and 2001, respectively | | | | (12 | ) | | | (15 | ) | | | (12 | ) | |
Loss on Disposal of Discontinued Operations, net of tax benefit of $4 and $18 for the years ended 2003and 2002, respectively | | | | (32 | ) | | | (34 | ) | | | — | | |
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE | | | | 145 | | | | (269 | ) | | | 167 | | |
Cumulative Effect of a Change in Accounting Principle, net of tax (expense) benefit of $66 and ($8) for the years ended 2002 and 2001, respectively | | | | — | | | | (121 | ) | | | 10 | | |
NET INCOME (LOSS) | | | | 145 | | | | (390 | ) | | | 177 | | |
Preference Units Distributions/Preferred Stock Dividends | | | | (23 | ) | | | (23 | ) | | | (23 | ) | |
EARNINGS (LOSS) AVAILABLE TO PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED | | | $ | 122 | | | $ | (413 | ) | | $ | 154 | | |
See disclosures regarding PSEG Energy Holdings LLC included in the
Notes to Consolidated Financial Statements.
115
PSEG ENERGY HOLDINGS LLC
CONSOLIDATED BALANCE SHEETS
ASSETS
(Millions)
| | December 31, | |
| | | | | As Restated,
see Note 2 | |
| | | 2003 | | | | 2002 | | |
CURRENT ASSETS | | | | | | | | | |
Cash and Cash Equivalents | | $ | 161 | | | $ | 109 | | |
Accounts Receivable: | | | | | | | | | |
Trade—net of allowances of $6 and $15 in 2003 and 2002, respectively | | | 103 | | | | 78 | | |
Other Accounts Receivable | | | 19 | | | | 20 | | |
Affiliated Companies | | | 173 | | | | — | | |
Assets Held for Sale | | | — | | | | 83 | | |
Notes Receivable: | | | | | | | | | |
Affiliated Companies | | | 300 | | | | 62 | | |
Other | | | 2 | | | | 12 | | |
Inventory | | | 26 | | | | 17 | | |
Prepayments | | | 7 | | | | 4 | | |
Assets of Discontinued Operations | | | 298 | | | | 419 | | |
Total Current Assets | | | 1,089 | | | | 804 | | |
PROPERTY, PLANT AND EQUIPMENT | | | 1,362 | | | | 1,352 | | |
Less: Accumulated Depreciation and Amortization | | | (184 | ) | | | (154 | ) | |
Net Property, Plant and Equipment | | | 1,178 | | | | 1,198 | | |
INVESTMENTS | | | | | | | | | |
Capital Leases-net | | | 2,981 | | | | 2,844 | | |
Corporate Joint Ventures | | | 1,040 | | | | 865 | | |
Partnership Interests | | | 531 | | | | 468 | | |
Other Investments | | | 31 | | | | 38 | | |
Total Investments | | | 4,583 | | | | 4,215 | | |
OTHER ASSETS | | | | | | | | | |
Goodwill | | | 491 | | | | 430 | | |
Other | | | 116 | | | | 108 | | |
Total Other Assets | | | 607 | | | | 538 | | |
Total Assets | | $ | 7,457 | | | $ | 6,755 | | |
See disclosures regarding PSEG Energy Holdings LLC included in the
Notes to Consolidated Financial Statements.
116
PSEG ENERGY HOLDINGS LLC
CONSOLIDATED BALANCE SHEETS
LIABILITIES AND MEMBER'S EQUITY
(Millions)
| | December 31, | |
| | | | As Restated,
see Note 2 | |
| | 2003 | | 2002 | |
CURRENT LIABILITIES | | | | | | | | |
Long-Term Debt Due Within One Year | | $ | 303 | | $ | 301 | | |
Accounts Payable | | | 181 | | | 165 | | |
Accounts Payable—Affiliated Companies | | | — | | | 61 | | |
Notes Payable | | | 2 | | | 133 | | |
Liabilities of Discontinued Operations | | | 242 | | | 336 | | |
Total Current Liabilities | | | 728 | | | 996 | | |
NONCURRENT LIABILITIES | | | | | | | | |
Deferred Income Taxes and Investment and Energy Tax Credits | | | 1,487 | | | 1,022 | | |
Other Noncurrent Liabilities | | | 165 | | | 180 | | |
Total Noncurrent Liabilities | | | 1,652 | | | 1,202 | | |
COMMITMENTS AND CONTINGENT LIABILITIES (See Note 17) | | | | | | | | |
| | | | | | | | |
MINORITY INTERESTS | | | 35 | | | 70 | | |
LONG-TERM DEBT | | | | | | | | |
Project Level, Non-Recourse Debt | | | 938 | | | 739 | | |
Senior Notes | | | 1,800 | | | 1,725 | | |
Total Long-Term Debt | | | 2,738 | | | 2,464 | | |
MEMBER’S EQUITY | | | | | | | | |
Ordinary Unit | | | 1,888 | | | 1,888 | | |
Preference Units | | | 509 | | | 509 | | |
Retained Earnings | | | 178 | | | 56 | | |
Accumulated Other Comprehensive Loss | | | (271 | ) | | (430 | ) | |
Total Member’s Equity | | | 2,304 | | | 2,023 | | |
TOTAL LIABILITIES AND MEMBER’S EQUITY | | $ | 7,457 | | $ | 6,755 | | |
See disclosures regarding PSEG Energy Holdings LLC included in the
Notes to Consolidated Financial Statements.
117
PSEG ENERGY HOLDINGS LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Millions)
| | For The Years Ended
December 31, | |
| | | | As Restated,
see Note 2 | |
| | 2003 | | 2002 | | 2001 | |
CASH FLOWS FROM OPERATING ACTIVITIES | | | | | | | | | | |
Net Income (Loss) | | $ | 145 | | $ | (390 | ) | $ | 177 | |
Adjustments to Reconcile Net Income (Loss) to Net Cash Flows from Operating Activities: | | | | | | | | | | |
Write-down of Project Investments | | | — | | | 511 | | | 7 | |
Cumulative Effect of a Change in Accounting Principle, net of tax | | | — | | | 121 | | | (10 | ) |
Loss on Disposal of Discontinued Operations, net of tax | | | 32 | | | 34 | | | — | |
Depreciation and Amortization | | | 44 | | | 28 | | | 15 | |
Deferred Income Taxes (Other than Leases) | | | 82 | | | (212 | ) | | (21 | ) |
Leveraged Lease Income, Adjusted for Rents Received | | | 77 | | | (44 | ) | | (6 | ) |
Change in Fair Value of Derivative Financial Instruments | | | 5 | | | (12 | ) | | — | |
Undistributed Earnings from Affiliates | | | 40 | | | (5 | ) | | (96 | ) |
Gain on Sale of Investments | | | (45 | ) | | (6 | ) | | (74 | ) |
Foreign Currency Transaction (Gain) Loss | | | (16 | ) | | 77 | | | 11 | |
Other Non-Cash Charges | | | 48 | | | 5 | | | 34 | |
Net Changes in Certain Current Assets and Liabilities: | | | | | | | | | | |
Accounts Receivable | | | (12 | ) | | (6 | ) | | (60 | ) |
Inventory | | | (12 | ) | | | | | | |
Accounts Payable | | | (136 | ) | | (37 | ) | | 88 | |
Current Assets and Liabilties from Discontinued Operations | | | (21 | ) | | (62 | ) | | (35 | ) |
Other Current Assets and Liabilities | | | — | | | 57 | | | 55 | |
Proceeds from the Withdrawal of Partnership Interests and Other Distributions | | | 66 | | | 54 | | | 124 | |
Other | | | (1 | ) | | (5 | ) | | (22 | ) |
Net Cash Provided By Operating Activities | | | 296 | | | 108 | | | 187 | |
CASH FLOWS FROM INVESTING ACTIVITIES | | | | | | | | | | |
Additions to Property, Plant and Equipment | | | (271 | ) | | (113 | ) | | (105 | ) |
Investments in Joint Ventures and Partnerships | | | (36 | ) | | (191 | ) | | (136 | ) |
Investments in Capital Leases | | | — | | | (31 | ) | | (460 | ) |
Proceeds from the Sale of Investments and Return of Capital from Partnerships | | | 18 | | | 205 | | | 27 | |
Proceeds from Capital Leases | | | 11 | | | 183 | | | 103 | |
Acquisitions, Net of Cash Provided | | | — | | | (17 | ) | | (810 | ) |
Short-Term Loan Receivable—Affiliated Company | | | (238 | ) | | (62 | ) | | — | |
Other | | | (7 | ) | | (3 | ) | | (101 | ) |
Net Cash Used In Investing Activities | | | (523 | ) | | (29 | ) | | (1,482 | ) |
CASH FLOWS FROM FINANCING ACTIVITIES | | | | | | | | | | |
Short-Term Loan (Repayment)—Affiliate | | | — | | | (38 | ) | | 38 | |
Net Change in Short-Term Debt | | | — | | | (294 | ) | | 139 | |
Proceeds from Sale of Senior Notes | | | 350 | | | 139 | | | 324 | |
Proceeds from Project-Level Non-Recourse Long-Term Debt | | | 686 | | | 73 | | | 950 | |
Proceeds from Capital Contributions | | | — | | | 400 | | | 400 | |
Deferred Issuance Costs | | | (20 | ) | | (2 | ) | | (11 | ) |
Repayment of Medium-Term and Project-Level Non-Recourse Debt | | | (660 | ) | | (271 | ) | | (423 | ) |
Distributions to (Proceeds from) Minority Shareholders | | | (48 | ) | | 5 | | | (61 | ) |
Cash Dividends Paid on Common Stock | | | — | | | — | | | (3 | ) |
Cash Dividends Paid on Preferred Stock | | | (23 | ) | | (23 | ) | | (23 | ) |
Restricted Cash | | | (8 | ) | | — | | | 2 | |
Net Cash Provided By (Used In) Financing Activities | | | 277 | | | (11 | ) | | 1,332 | |
Effect of Exchange Rate Change | | | 2 | | | (13 | ) | | — | |
Net Change In Cash and Cash Equivalents | | | 52 | | | 55 | | | 37 | |
Cash and Cash Equivalents at Beginning of Period | | | 109 | | | 54 | | | 17 | |
Cash and Cash Equivalents at End of Period | | $ | 161 | | $ | 109 | | $ | 54 | |
Supplemental Disclosure of Cash Flow Information: | | | | | | | | | | |
Income Taxes Received | | $ | (154 | ) | $ | (126 | ) | $ | (178 | ) |
Interest Paid, Net of Amounts Capitalized | | $ | 166 | | $ | 193 | | $ | 155 | |
See disclosures regarding PSEG Energy Holdings LLC included in the
Notes to Consolidated Financial Statements.
118
PSEG ENERGY HOLDINGS LLC
CONSOLIDATED STATEMENTS OF MEMBER’S/STOCKHOLDER’S EQUITY
(Millions)
| | | | | | | | | | As
Restated,
see Note 2 Retained
Earnings | | As Restated,
see Note 2 | | As Restated,
see Note 2 Total Member’s/
Stockholder’s
Equity | |
| | Ordinary
Unit | | Preference
Units | | Preferred
Stock | | Additional
Paid-In
Capital | | | Accumulated
Other
Comprehensive
Loss | | |
Balance as of January 1, 2001 | | | $ | — | | | | $ | — | | | | $ | 509 | | | | $ | 1,090 | | | | $ | 318 | | | | $ | (218 | ) | | | $ | 1,699 | | |
Net Income | | | | — | | | | | — | | | | | — | | | | | — | | | | | 177 | | | | | — | | | | | 177 | | |
Other Comprehensive Income (Loss), net of tax: Currency Translation Adjustment, net of tax of $(7) | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | (68 | ) | | | | (68 | ) | |
Cumulative Effect of a Change in Accounting Principle, net of tax of $(14) | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | (15 | ) | | | | (15 | ) | |
Current Period Declines in Fair Value of Derivative Instruments—Net | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | (16 | ) | | | | (16 | ) | |
Reclassification Adjustments for Net Amounts Included in Net Income | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | 4 | | | | | 4 | | |
Other Comprehensive Loss | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | (95 | ) | |
Comprehensive Income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 82 | | |
Additional Contributed Capital | | | | — | | | | | — | | | | | — | | | | | 400 | | | | | — | | | | | — | | | | | 400 | | |
Preferred Stock Dividends | | | | — | | | | | — | | | | | — | | | | | — | | | | | (23 | ) | | | | — | | | | | (23 | ) | |
Other | | | | — | | | | | — | | | | | — | | | | | — | | | | | (3 | ) | | | | — | | | | | (3 | ) | |
Balance as of December 31, 2001 | | | $ | — | | | | $ | — | | | | $ | 509 | | | | $ | 1,490 | | | | $ | 469 | | | | $ | (313 | ) | | | $ | 2,155 | | |
Net Loss | | | | — | | | | | — | | | | | — | | | | | — | | | | | (390 | ) | | | | — | | | | | (390 | ) | |
Other Comprehensive Income (Loss), net of tax: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Currency Translation Adjustment, net of tax of ($45) | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | (140 | ) | | | | (140 | ) | |
Reclassification Adjustment for Losses Included in Net Income, net of tax of $37 | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | 68 | | | | | 68 | | |
Current Period Declines in Fair Value of Derivative Instruments, net of tax of $(10) | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | (45 | ) | | | | (45 | ) | |
Reclassification Adjustments for Net Amounts Included in Net Income | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | 9 | | | | | 9 | | |
Settlement Adjustments Related to Projects Under Construction | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | (3 | ) | | | | (3 | ) | |
Minimum Pension Liability Adjustment | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | (6 | ) | | | | (6 | ) | |
Other Comprehensive Loss | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | (117 | ) | |
Comprehensive Loss | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (507 | ) | |
Additional Contributed Capital | | | | 100 | | | | | — | | | | | — | | | | | 300 | | | | | — | | | | | — | | | | | 400 | | |
Recapitalization of Energy Holdings’ Assets and Liabilities | | | | 1,790 | | | | | 509 | | | | | (509 | ) | | | | (1,790 | ) | | | | — | | | | | | | | | | | | |
Preference Units/Preferred Stock Dividends | | | | — | | | | | — | | | | | — | | | | | — | | | | | (23 | ) | | | | — | | | | | (23 | ) | |
Dividend of Pantellos Corporation to PSEG | | | | (2 | ) | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | (2 | ) | |
Balance as of December 31, 2002 | | | $ | 1,888 | | | | $ | 509 | | | | $ | — | | | | $ | — | | | | $ | 56 | | | | $ | (430 | ) | | | $ | 2,023 | | |
Net Income | | | | — | | | | | — | | | | | — | | | | | — | | | | | 145 | | | | | — | | | | | 145 | | |
Other Comprehensive Income (Loss), net of tax: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Currency Translation Adjustment, net of tax of $4 | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | 164 | | | | | 164 | | |
Current Period Declines in Fair Value of Derivative Instruments, net of tax of $(11) | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | (22 | ) | | | | (22 | ) | |
Reclassification Adjustments for Net Amounts Included in Net Income | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | 23 | | | | | 23 | | |
Settlement Adjustments Related to Projects Under Construction | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | (11 | ) | | | | (11 | ) | |
Minimum Pension Liability Adjustment | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | 5 | | | | | 5 | | |
Other Comprehensive Income | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | — | | | | | 159 | | |
Comprehensive Income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 304 | | |
Preference Units/Preferred Stock Dividends | | | | — | | | | | — | | | | | — | | | | | — | | | | | (23 | ) | | | | — | | | | | (23 | ) | |
Balance as of December 31, 2003 | | | $ | 1,888 | | | | $ | 509 | | | | $ | — | | | | $ | — | | | | $ | 178 | | | | $ | (271 | ) | | | $ | 2,304 | | |
See disclosures regarding PSEG Energy Holdings LLC included in the
Notes to Consolidated Financial Statements.
119
Information contained herein relating to any individual company is filed by such company on its own behalf. PSE&G, Power and Energy Holdings each make representations only as to itself and make no other representations whatsoever as to any other company.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization and Summary of Significant Accounting Policies
Organization
Public Service Enterprise Group Incorporated (PSEG)
PSEG has four principal direct wholly-owned subsidiaries: Public Service Electric and Gas Company (PSE&G), PSEG Power LLC (Power), PSEG Energy Holdings LLC (Energy Holdings) and PSEG Services Corporation (Services).
PSE&G
PSE&G is a public utility providing electric and gas transmission and distribution service in certain areas within the State of New Jersey. Following the transfer of its generation-related assets and liabilities to Power in August 2000 and gas supply business to Power in May 2002, PSE&G continues to own and operate its transmission and distribution business. PSE&G owns PSE&G Transition Funding LLC (Transition Funding), a bankruptcy remote entity established for the purpose of purchasing intangible transition property and issuing transition bonds.
Power
Power is a multi-regional wholesale energy supply business that utilizes energy trading to manage its portfolio of electric generation assets, gas supply and storage contracts and electric and gas supply obligations. Power has three principal direct wholly-owned subsidiaries: PSEG Nuclear LLC (Nuclear), PSEG Fossil LLC (Fossil) and PSEG Energy Resources & Trade LLC (ER&T). Power and its subsidiaries were established to acquire, own and operate the electric generation-related business of PSE&G pursuant to the Final Decision and Order (Final Order) issued by the New Jersey Board of Public Utilities (BPU) under the New Jersey Electric Discount and Energy Competition Act (EDECA) discussed below.
Energy Holdings
Energy Holdings is the parent of PSEG Global LLC (Global), which invests and participates in the development and operation of international and domestic projects engaged in the generation and distribution of energy, including cogeneration and independent power production facilities and electric distribution companies; PSEG Resources LLC (Resources), which makes investments primarily in energy-related leveraged leases; and Enterprise Group Development Corporation (EGDC), a commercial real estate property management business. During the third quarter of 2003, Energy Holdings completed the sale of PSEG Energy Technologies Inc. (Energy Technologies) and its assets. For additional information relating to Energy Technologies, see Note 5. Discontinued Operations.
Services
Services provides management and administrative services to PSEG and its subsidiaries. These include accounting, legal, communications, human resources, information technology, treasury and financial, investor relations, stockholder services, real estate, insurance, risk management, tax, library and information services, security, corporate secretarial and certain planning, budgeting and forecasting services. Services charges PSEG and its subsidiaries for the cost of work performed and services provided pursuant to the terms and conditions of intercompany service agreements.
120
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Summary of Significant Accounting Policies
Principles of Consolidation
PSEG, PSE&G, Power and Energy Holdings
PSEG’s, PSE&G’s, Power’s and Energy Holdings’ consolidated financial statements include their respective accounts and consolidate those entities in which they have a controlling interest or are the primary beneficiary, except for certain of PSEG’s and PSE&G’s capital trusts which were deconsolidated in accordance with of Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 46, “Consolidation of Variable Interest Entities (VIE)” (FIN 46), as discussed in Note 3. Recent Accounting Standards. Entities over which PSEG, PSE&G, Power and Energy Holdings exhibit significant influence, but do not have a controlling interest and/or are not the primary beneficiary are accounted for under the equity method of accounting. For investments in which significant influence does not exist and it is not the primary beneficiary, the cost method of accounting is applied. All significant intercompany accounts and transactions are eliminated in consolidation.
PSE&G and Power
PSE&G and Power each has undivided interests in certain jointly owned facilities. PSE&G and Power are responsible to pay for their respective ownership share of additional construction costs, fuel inventory purchases and operating expenses. All revenues and expenses related to these facilities are consolidated at their respective pro-rata ownership share in the appropriate revenue and expense categories on the Consolidated Statements of Operations. For additional information regarding these jointly owned facilities, see Note 24. Property, Plant and Equipment and Jointly Owned Facilities.
Accounting for the Effects of Regulation
PSE&G
PSE&G prepares its financial statements in accordance with the provisions of Statement of Financial 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 economic effects of regulation. As a result, a regulated utility is required to defer the recognition of costs (a regulatory asset) or record the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs and recoveries, which are being amortized over various future periods. To the extent that collection of any 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 is charged or credited to income. PSE&G’s transmission and distribution business continues to meet the requirements for application of SFAS 71. For additional information, see Note 10. Regulatory Assets and Liabilities.
Derivative Financial Instruments
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings use derivative financial instruments to manage risk from changes in interest rates, congestion credits, emission credits, commodity prices and foreign currency exchange rates, pursuant to their business plans and prudent practices.
PSEG, PSE&G, Power and Energy Holdings recognize derivative instruments on the balance sheet at their fair value. Changes in the fair value of a derivative that is highly effective as, and that is designated and qualifies as, a fair-value hedge (including foreign currency fair-value hedges), along with changes of the fair value of the hedged asset or liability that are attributable to the hedged risk, are recorded in current-period earnings. Changes in the fair value of a derivative that is highly effective as
121
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
and that is designated and qualifies as a cash flow hedge (including foreign currency cash flow hedges) are recorded in Other Comprehensive Income (OCI) until earnings are affected by the variability of cash flows of the hedged transaction. Any hedge ineffectiveness is included in current-period earnings. In certain circumstances, PSEG, PSE&G, Power and/or Energy Holdings enter into derivative contracts that do not qualify as hedges or choose not to designate them as fair value or cash flow hedges, in such cases, changes in fair value are recorded in current period earnings.
For additional information regarding derivative financial instruments, see Note 16. Risk Management.
Revenue Recognition
PSE&G
PSE&G’s Operating Revenues are recorded based on services rendered to customers during each accounting period. PSE&G records unbilled revenues for the estimated amount customers will be billed for services rendered from the time meters were last read to the end of the respective accounting period. The unbilled revenue is estimated each month based on usage per day, the number of unbilled days in the period, estimated seasonal loads based upon the time of year and the variance of actual degree-days and temperature-humidity-index hours of the unbilled period from expected norms.
Power
The majority of Power’s revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. Power also records revenues and energy costs for physical energy delivered to and received from power pools. Power also records margins from energy trading on a net basis pursuant to accounting principles generally accepted in the U.S. (GAAP). See Note 16. Risk Management for further discussion.
Energy Holdings
Global records revenues from its investments in generation and distribution facilities. Certain of Global’s investments are majority owned, controlled and consolidated by Global and the revenues from these projects are recorded as Global’s revenues. Other investments are less than majority owned and are accounted for under the equity or cost methods as appropriate. Revenues for many of these investments are estimated on a monthly basis and trued up to actual results in the next accounting month. Gains or losses incurred as a result of exiting one of these businesses are typically recorded as a component of Operating Income.
The majority of Resources’ revenues relate to its investments in leveraged leases and are accounted for under SFAS No. 13 “Accounting for Leases” (SFAS 13). Income on leveraged leases is recognized by a method which produces a constant rate of return on the outstanding net investment in the lease, net of the related deferred tax liability, in the years in which the net investment is positive. Any gains or losses incurred as a result of a lease termination are recorded as revenues as these events occur in the ordinary course of business of managing the investment portfolio. Related to its equity securities, Resources records revenues from the changes in share prices of publicly-traded equity securities held within its leveraged buyout funds. See Note 12. Long-Term Investments for further discussion.
Depreciation and Amortization
PSE&G
PSE&G calculates depreciation under the straight-line method based on estimated average remaining lives of the several classes of depreciable property. These estimates are reviewed on a periodic basis and necessary adjustments are made as approved by the BPU. The depreciation rate
122
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
stated as a percentage of original cost of depreciable property was 3.30% for 2003, 3.37% for 2002 and 3.32% for 2001.
Power
Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful life which is determined based on planned operations. The estimated useful lives are from 3 years to 20 years for general plant assets. The estimated useful lives are 30 years to 55 years for fossil production assets, 49 years to 56 years for nuclear generation assets and 45 years for pumped storage facilities.
Energy Holdings
Energy Holdings calculates depreciation on property, plant and equipment under the straight-line method with estimated useful lives ranging from 3 years to 40 years.
Taxes Other Than Income Taxes
PSE&G
Excise taxes, transitional energy facilities assessment (TEFA) and gross receipts tax (GRT) collected from PSE&G customers are presented on the financial statements on a gross basis. As a result of New Jersey energy tax reform, effective January 1, 1998, TEFA and GRT are the residual of the prior excise tax, New Jersey gross receipts and franchise taxes. For the years ended December 31, 2003, 2002 and 2001, combined TEFA and GRT of approximately $152 million, $145 million and $142 million, respectively, are reflected in Operating Revenues and $136 million, $131 million and $121 million, respectively, are included in Taxes Other Than Income Taxes on the Consolidated Statements of Operations.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalized During Construction (IDC)
PSE&G
AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets under the guidance of SFAS 71. The amount of AFUDC capitalized was reported in the Consolidated Statements of Operations as a reduction of interest charges. PSE&G’s average rate used for calculating AFUDC in 2003, 2002, and 2001 was 3.43%, 8.34% and 6.65%, respectively. In 2003, 2002, and 2001, PSE&G’s AFUDC amounted to less than $1 million, $1 million and $2 million, respectively.
Power and Energy Holdings
IDC represents the cost of debt used to finance construction at Power and Energy Holdings. The amount of IDC capitalized is reported in the Consolidated Statements of Operations as a reduction of interest charges and is included in Property, Plant and Equipment on the Consolidated Balance Sheets. Power’s average rate used for calculating IDC in 2003, 2002 and 2001 was 7.07%, 7.01% and 8.59%, respectively. In 2003, 2002, and 2001, Power’s IDC amounted to $109 million, $95 million and $63 million, respectively. Energy Holdings’ average rate used for calculating IDC in 2003, 2002 and 2001 was 8.70%, 9.06% and 8.05%, respectively. In 2003, 2002, and 2001, Energy Holdings’ IDC amounted to $12 million, $13 million and $14 million, respectively.
123
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Income Taxes
PSEG, PSE&G, Power and Energy Holdings
PSEG and its subsidiaries file a consolidated Federal income tax return and income taxes are allocated to PSEG’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.
Foreign Currency Translation/Transactions
Energy Holdings
Revenues and expenses are translated at average exchange rates for the year. Transaction gains and losses that arise from exchange rate fluctuations on normal operating transactions denominated in a currency other than the functional currency are included in earnings as incurred.
The assets and liabilities of foreign operations are translated into U.S. Dollars at current exchange rates. Resulting translation adjustments are reflected in OCI, net of taxes, as a separate component of member’s/stockholders’ equity.
Cash and Cash Equivalents
PSEG, PSE&G, Power and Energy Holdings
Cash and cash equivalents consist primarily of working funds and highly liquid marketable securities (commercial paper and money market funds) with an original maturity of three months or less.
Materials and Supplies and Fuel
PSE&G
PSE&G’s materials and supplies are carried at average cost consistent with the rate-making process.
Power and Energy Holdings
The carrying value of the materials and supplies and fuel for Power and Energy Holdings is valued at the lower of average cost or market.
Property, Plant and Equipment
PSE&G
PSE&G’s additions to plant, property and equipment and replacements that are either retirement units or property record units are capitalized at original cost. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for salvage value, is charged to accumulated depreciation.
Power and Energy Holdings
Power and Energy Holdings only capitalize costs which increase the capacity or extend the life of an existing asset, represent a newly acquired or constructed asset or represent the replacement of a retired asset. The cost of maintenance, repair and replacement of minor items of property is charged to appropriate expense accounts as incurred. Environmental costs are capitalized if the costs mitigate or
124
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred.
Other Special Funds
PSEG, PSE&G, Power and Energy Holdings
Other Special Funds represents amounts deposited to fund the qualified pension plans and to fund a Rabbi Trust which was established to meet the obligations related to three non-qualified pension plans and a deferred compensation plan.
Nuclear Decommissioning Trust (NDT) Fund
Power
Prior to the adoption of SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS 143), amounts collected from PSE&G customers that have been deposited into the NDT Fund and realized and unrealized gains and losses in the trust were all recorded as changes in the NDT Fund with an offsetting charge to the nuclear decommissioning liability.
Effective January 1, 2003, Power adopted SFAS 143, which addresses accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. In addition, the BPU issued an order that PSE&G’s customers will no longer fund the NDT Fund. Therefore, deferral accounting is no longer appropriate. Beginning January 1, 2003, realized gains and losses were recorded in earnings and unrealized gains and losses were recorded as a component of OCI, as required under SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities” (SFAS 115). See Note 3. Recent Accounting Standards and Note 4. Adoption of SFAS 143 for a discussion of SFAS 143 and the impact of its adoption.
Investments in Corporate Joint Ventures and Partnerships
Energy Holdings
Generally, Global’s and Resources’ interests in active joint ventures and partnerships are accounted for under the equity method of accounting where its respective ownership interests are 50% or less, it is not the primary beneficiary, as defined under FIN 46, and significant influence over joint venture or partnership operating and management decisions exists. For investments in which significant influence does not exist and it is not the primary beneficiary, the cost method of accounting is applied. Interest is capitalized on investments during the construction and development of qualifying assets.
There are several investments recorded in accordance with the equity method of accounting for which there is a difference in the investment account when compared to the underlying equity in net assets. The reconciling items include amounts for loans to the operating entities, capitalized interest and capitalized expenses. From time to time, Global loans funds to certain operating entities in which it participates, which are used to construct generation facilities. Such loans earn interest at market rates. For additional information on these loans, see Note 26. Related-Party Transactions. In the instance of capitalized interest, to the extent borrowings on the part of Global were required to fund the underlying investment of the project, and such project is under construction, the interest accrued on such borrowings is recorded in the investment account. This is a temporary difference, as amortization of the amount of interest capitalized will begin upon commencement of the project. In the instance of capitalized expenses, all direct external and internal costs related to project development are capitalized once a project reaches certain milestones. When the project reaches financial closing, Global transfers the deferred project balance to the investment account. This is a temporary difference, as the capitalized expenses will amortize upon commencement of the project. For additional information related to these investments, see Note 12. Long-Term Investments.
125
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Resources carries its partnership investments in certain venture capital and leveraged buyout funds investing in securities at fair value where market quotations and an established liquid market of underlying securities in the portfolio are available. Fair value is determined based on the review of market price and volume data in conjunction with Resources’ invested liquid position in such securities. Changes in fair value are recorded in Operating Revenues in the Consolidated Statements of Operations.
Deferred Project Costs
Power and Energy Holdings
Power and Energy Holdings capitalize all direct external and direct incremental internal costs related to project development once a project reaches certain milestones. Once the project reaches financial closing, the deferred project balance is transferred to the investment account. These costs are amortized on a straight-line basis over the lives of the related project assets. Such amortization commences upon the date of commercial operation. Development costs related to unsuccessful projects are charged to expense. Deferred project costs are recorded in Construction Work in Progress on Power’s Consolidated Balance Sheets. Deferred project costs are recorded in Investments or Other Assets on Energy Holdings’ Consolidated Balance Sheets.
Stock Compensation
PSEG
PSEG applies Accounting Principles Board (APB) Opinion No. 25, “Accounting for Stock Issued to Employees,” and related interpretations in accounting for stock-based compensation plans, which are described below. Accordingly, no compensation cost has been recognized for fixed stock option grants since the exercise price of the stock options equaled the market price of the underlying stock on the date of grant. Had compensation costs for stock option grants been determined based on the fair value at the grant dates for awards under these plans in accordance with SFAS No. 123 “Accounting for Stock-Based Compensation,” there would have been a charge to Net Income of approximately $8 million, $10 million and $10 million in 2003, 2002 and 2001, respectively, with a $(0.04), $(0.05) and $(0.05) impact on diluted earnings per share in 2003, 2002, and 2001, respectively.
The following table illustrates the effect on Net Income and Earnings Per Share if PSEG had applied the fair value recognition provisions of SFAS No. 123 to stock-based employee compensation:
| | Years Ended
December 31, | |
| |
| |
| | 2003 | | 2002 | | 2001 | |
| | (Millions, except
Share Data) | |
| | | | | | | | | | |
Net Income, as reported | | $ | 1,160 | | $ | 235 | | $ | 764 | |
Deduct: Total stock-based employee compensation expense determined under
fair value based method for all awards, net of related tax effects | | | (8 | ) | | (10 | ) | | (10 | ) |
| |
| |
| |
| |
Pro forma Net Income | | $ | 1,152 | | $ | 225 | | $ | 754 | |
| |
| |
| |
| |
Earnings per share: | | | | | | | | | | |
Basic—as reported | | $ | 5.08 | | $ | 1.13 | | $ | 3.67 | |
Basic—pro forma | | $ | 5.05 | | $ | 1.08 | | $ | 3.62 | |
Diluted—as reported | | $ | 5.07 | | $ | 1.13 | | $ | 3.67 | |
Diluted—pro forma | | $ | 5.03 | | $ | 1.08 | | $ | 3.62 | |
See Note 11. Earnings Per Share for further information.
126
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Basis Adjustment
PSE&G and Power
PSE&G and Power have recorded a Basis Adjustment on their Consolidated Balance Sheets relating to the generation assets that were transferred from PSE&G to Power in August 2000 at the price specified by the BPU. Because the transfer was between affiliates, PSE&G and Power, the transaction was recorded at the net book value of the assets and liabilities rather than the transfer price. The difference between the total transfer price and the net book value of the generation-related assets and liabilities, approximately $986 million, net of tax, was recorded as a Basis Adjustment on PSE&G’s and Power’s Consolidated Balance Sheets. These amounts are eliminated on PSEG’s consolidated financial statements.
Use of Estimates
PSEG, PSE&G, Power and Energy Holdings
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 materially differ from estimated amounts.
Reclassifications
PSEG, PSE&G, Power and Energy Holdings
Certain reclassifications of amounts reported in prior periods have been made to conform with the current presentation.
Note 2. Restatement of Financial Statements
PSEG and Energy Holdings
Subsequent to the issuance of the Consolidated Financial Statements for the year ended December 31, 2002 and in preparation of the Consolidated Financial Statements for the year ended December 31, 2003, management determined that the recorded amount of Energy Holdings’ investment in Rio Grande Energia S.A. (RGE) was overstated due to a miscalculation of the amount of foreign currency translation adjustments. In addition, certain amounts related to this investment had been erroneously recorded as translation adjustments instead of foreign currency transactions. The impact on previously reported Net Income of PSEG and Energy Holdings of these adjustments resulted in a decrease of $7 million and $2 million for the years ended December 31, 2002 and 2001, respectively. As a result, the accompanying consolidated financial statements of PSEG and Energy Holdings for the years ended December 31, 2002 and 2001 have been restated from the amounts previously reported to reflect the correct amount of foreign currency translation adjustments and to record the effects of foreign currency transactions in earnings rather than as an adjustment to OCI. The effects of this miscalculation also resulted in a reduction of Retained Earnings and an increase to Accumulated Other Comprehensive Loss of $42 million and $29 million as of January 1, 2002. In addition to the adjustments described above, certain other adjustments, previously considered to be immaterial individually and in the aggregate, were also recorded in the restated financial statements for the years ended December 31, 2002 and 2001. The impact on previously reported Net Income of PSEG and Energy Holdings of these other adjustments resulted in a decrease of $3 million and $4 million for the years ended December 31, 2002 and 2001, respectively.
The effects on the financial statements of all adjustments and their related tax effects are detailed as follows:
127
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Statement of Operations
| | As Previously
Reported | | As Restated | |
| |
| |
| |
| | 2002 | | 2002 | |
| | (Millions, except for
Share Data) | |
PSEG | | | | | | | | | | | |
Energy Costs | | | $ | 3,769 | | | | $ | 3,706 | | |
Operation and Maintenance | | | $ | 1,896 | | | | $ | 1,899 | | |
Other Income | | | $ | 57 | | | | $ | 39 | | |
Other Deductions | | | $ | (79 | ) | | | $ | (80 | ) | |
Interest Expense | | | $ | (783 | ) | | | $ | (819 | ) | |
Income Taxes | | | $ | (248 | ) | | | $ | (254 | ) | |
Loss from Discontinued Operations, including Loss on Disposal, net of tax | | | $ | (51 | ) | | | $ | (49 | ) | |
Cumulative Effect of a Change in Accounting Principle, net of tax | | | $ | (120 | ) | | | $ | (121 | ) | |
Net Income | | | $ | 245 | | | | $ | 235 | | |
Earnings Per Share (Basic and Diluted) | | | $ | 1.17 | | | | $ | 1.13 | | |
Consolidated Statement of Operations
| | As Previously
Reported | | As Restated | |
| |
| |
| |
| | 2002 | | 2002 | |
| | (Millions) | |
Energy Holdings | | | | | | | |
Electric Distribution and Generation Revenues | | | $ | 364 | | | | $ | 304 | | |
Other Operating Revenues | | | $ | 30 | | | | $ | 45 | | |
Energy Costs | | | $ | 147 | | | | $ | 118 | | |
Operation and Maintenance | | | $ | 165 | | | | $ | 168 | | |
Other Income | | | $ | 25 | | | | $ | 26 | | |
Other Deductions | | | $ | (73 | ) | | | $ | (77 | ) | |
Interest Expense | | | $ | (214 | ) | | | $ | (217 | ) | |
Income Tax Benefit | | | $ | 150 | | | | $ | 144 | | |
Loss from Discontinued Operations, net of tax | | | $ | (16 | ) | | | $ | (15 | ) | |
Cumulative Effect of a Change in Accounting Principle, net of tax | | | $ | (120 | ) | | | $ | (121 | ) | |
Net Loss | | | $ | (380 | ) | | | $ | (390 | ) | |
128
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Statement of Operations
| | As Previously
Reported | | As Restated | |
| |
| |
| |
| | 2001 | | 2001 | |
| | (Millions, except for
Share Data) | |
PSEG | | | | | | | | | | | |
Operation and Maintenance | | | $ | 1,841 | | | | $ | 1,844 | | |
Other Income | | | $ | 50 | | | | $ | 33 | | |
Income Taxes | | | $ | (381 | ) | | | $ | (373 | ) | |
Loss from Discontinued Operations, including Loss on Disposal, net of tax | | | $ | (15 | ) | | | $ | (12 | ) | |
Net Income | | | $ | 770 | | | | $ | 764 | | |
Earnings Per Share (Basic and Diluted) | | | $ | 3.70 | | | | $ | 3.67 | | |
| | | | | | | | | | | |
Energy Holdings | | | | | | | | | | | |
Operation and Maintenance | | | $ | 119 | | | | $ | 122 | | |
Other Income | | | $ | 6 | | | | $ | 4 | | |
Income Tax Expense | | | $ | (65 | ) | | | $ | (58 | ) | |
Loss from Discontinued Operations, net of tax | | | $ | (15 | ) | | | $ | (12 | ) | |
Net Income | | | $ | 183 | | | | $ | 177 | | |
129
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Balance Sheet
| | As Previously
Reported | | As Restated | |
| |
| |
| |
| | 2002 | | 2002 | |
| | (Millions) | |
PSEG | | | | | | | | | | | |
Cash and Cash Equivalents | | | $ | 165 | | | | $ | 171 | | |
Accounts Receivable, net of allowances | | | $ | 1,370 | | | | $ | 1,404 | | |
Prepayments | | | $ | 74 | | | | $ | 73 | | |
Current Assets of Discontinued Operations | | | $ | 107 | | | | $ | 419 | | |
Property, Plant and Equipment | | | $ | 16,562 | | | | $ | 16,374 | | |
Accumulated Depreciation and Amortization | | | $ | (5,113 | ) | | | $ | (4,734 | ) | |
Long-Term Investments | | | $ | 4,581 | | | | $ | 4,468 | | |
Goodwill | | | $ | 452 | | | | $ | 446 | | |
Other Noncurrent Assets | | | $ | 236 | | | | $ | 225 | | |
Current Liabilities of Discontinued Operations | | | $ | 83 | | | | $ | 324 | | |
Deferred Income Taxes and Investment Tax Credits | | | $ | 2,924 | | | | $ | 2,903 | | |
Other Noncurrent Liabilities | | | $ | 638 | | | | $ | 623 | | |
Retained Earnings | | | $ | 1,601 | | | | $ | 1,554 | | |
Accumulated Other Comprehensive Loss | | | $ | (689 | ) | | | $ | (739 | ) | |
| | | | | | | | | | | |
Energy Holdings | | | | | | | | | | | |
Cash and Cash Equivalents | | | $ | 104 | | | | $ | 109 | | |
Accounts Receivable: | | | | | | | | | | | |
Trade—Net | | | $ | 91 | | | | $ | 78 | | |
Other Accounts Receivable—Net | | | $ | 24 | | | | $ | 20 | | |
Prepayments | | | $ | 4 | | | | $ | 4 | | |
Current Assets of Discontinued Operations | | | $ | 107 | | | | $ | 419 | | |
Property, Plant and Equipment | | | $ | 1,534 | | | | $ | 1,352 | | |
Accumulated Depreciation and Amortization | | | $ | (139 | ) | | | $ | (154 | ) | |
Corporate Joint Ventures | | | $ | 1,004 | | | | $ | 865 | | |
Goodwill | | | $ | 436 | | | | $ | 430 | | |
Other Assets | | | $ | 111 | | | | $ | 108 | | |
Current Liabilities of Discontinued Operations | | | $ | 95 | | | | $ | 336 | | |
Deferred Income Taxes and Investment and Energy Tax Credits | | | $ | 1,042 | | | | $ | 1,022 | | |
Other Noncurrent Liabilities | | | $ | 179 | | | | $ | 180 | | |
Retained Earnings | | | $ | 107 | | | | $ | 56 | | |
Accumulated Other Comprehensive Loss | | | $ | (380 | ) | | | $ | (430 | ) | |
The amounts as previously reported do not reflect certain reclassifications due to presentation of Energy Holdings’ investment in Carthage Power Company (CPC), a generating facility in Rades, Tunisia as a discontinued operations, as discussed in Note 5. Discontinued Operations and the effects of the adoption of FIN 46, as discussed in Note 3. Recent Accounting Standards and other reclassifications that have been made to conform with the current presentation.
Note 3. Recent Accounting Standards
SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity” (SFAS 150)
PSEG and PSE&G
SFAS 150, which became effective July 1, 2003, established standards for the classification and measurement of certain financial instruments with characteristics of both liabilities and equity. The
130
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
adoption of SFAS 150 did not have any effect on PSEG’s, PSE&G’s, Power’s or Energy Holdings’ financial statements.
SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149)
PSEG, PSE&G, Power and Energy Holdings
SFAS 149 amends and clarifies the accounting guidance for derivative instruments (including certain derivative instruments embedded in other contracts) and hedging activities that fall within the scope of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS 133). Under this standard, any non-power commodity contracts (e.g., gas contracts) and power contracts that do not meet the definition in SFAS 133 and SFAS 149 that are subject to unplanned netting, will be ineligible for “normal” treatment, which would result in those contracts being marked to market. SFAS 149 is effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. There was no impact on PSEG’s, PSE&G’s, Power’s or Energy Holdings’ respective financial statements due to the adoption of this standard.
SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities” (SFAS 146)
PSEG, PSE&G, Power and Energy Holdings
This Statement addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)” (EITF 94-3). The principal difference between SFAS 146 and EITF 94-3 relates to its requirements for recognition of a liability for a cost associated with an exit or disposal activity. SFAS 146 requires that a liability for a cost associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF 94-3, a liability for an exit cost as defined therein was recognized at the date of an entity’s commitment to an exit plan. A fundamental conclusion reached by the FASB was that an entity’s commitment to a plan, by itself, does not create a present obligation to others that meets the definition of a liability. Therefore, SFAS 146 eliminates the definition and requirements for recognition of exit costs in EITF 94-3. SFAS 146 also establishes that fair value is the objective for initial measurement of the liability. The adoption of SFAS 146 did not have any effect on PSEG’s, PSE&G’s, Power’s or Energy Holdings’ financial statements.
SFAS No. 145, “Rescission of FASB Statements Nos. 4, 44 and 64, Amendment of FASB Statement No. 13 and Technical Corrections” (SFAS 145)
PSEG, PSE&G, Power and Energy Holdings
Effective January 1, 2002, PSEG, PSE&G, Power and Energy Holdings adopted SFAS 145. This Statement rescinds SFAS No. 4, “Reporting Gains and Losses from Extinguishments of Debt,” (SFAS 4) and an amendment of that Statement, SFAS No. 64, “Extinguishments of Debt Made to Satisfy Sinking Fund Requirements” (SFAS 64). SFAS 4 required that gains and losses from extinguishments of debt that were included in the determination of Net Income be aggregated, and if material, classified as an Extraordinary Item. Under SFAS 145, companies are no longer permitted to classify the amounts as extraordinary and now must record these gains and losses in Other Income and Other Deductions. Energy Holdings recorded pre-tax gains of $14 million ($8 million, after-tax) from the early retirement of debt as a component of Other Income for the period ended December 31, 2002. Also, Energy Holdings reclassified a pre-tax loss of $3 million ($2 million after-tax) from the early retirement of debt to a component of Other Deductions for the period ended December 31, 2001.
SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS 144)
PSEG, PSE&G, Power and Energy Holdings
On January 1, 2002, SFAS 144, which provides guidance on the accounting for the impairment or disposal of long-lived assets, became effective. For long-lived assets to be held and used, the new rules
131
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
are similar to previous guidance, which required the recognition of an impairment when the undiscounted cash flows will not recover its carrying amount. The impairment to be recognized is measured as the difference between the carrying amount and fair value of the asset. There was no impact on the Consolidated Financial Statements of PSEG, PSE&G, Power or Energy Holdings upon adoption of these rules. For additional information, see Note 8. Asset Impairments.
SFAS 143
PSEG, PSE&G, Power and Energy Holdings
Effective January 1, 2003, PSEG, PSE&G, Power and Energy Holdings each adopted SFAS 143. SFAS 143 addresses accounting and reporting for legal obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. A legal obligation is a liability that a party is required to settle as a result of an existing or enacted law, statute, ordinance or contract. Under SFAS 143, a company must initially recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred and concurrently capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. A company is required to subsequently depreciate that asset retirement cost to expense over its useful life. In periods subsequent to initial measurement, an entity is required to recognize changes in the liability resulting from the passage of time (accretion) or due to revisions to either the timing or the amount of the originally estimated cash flows. Changes in the liability due to accretion are charged to Operation and Maintenance expense on the Consolidated Statements of Operations, whereas changes due to the timing or amount of cash flows are adjustments to the carrying amount of the related asset. See Note 4. Adoption of SFAS 143 for additional information.
SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142)
PSEG, PSE&G, Power and Energy Holdings
On January 1, 2002, PSEG, PSE&G, Power and Energy Holdings adopted SFAS 142. Under this standard, PSEG, PSE&G, Power and Energy Holdings were required to complete an impairment analysis of goodwill. Under SFAS 142, goodwill is a nonamortizable asset subject to an annual review for impairment and an interim review when certain events or changes in circumstances occur. At the time of adoption, PSE&G had no goodwill. The effect of no longer amortizing goodwill on an annual basis was not material to PSEG’s or Power’s financial position and results of operations upon adoption. Power and Energy Holdings evaluated the recoverability of the recorded amount of their goodwill based on certain operating and financial factors. Such impairment testing included discounted cash flow tests, which require broad assumptions and significant judgment to be exercised by management. In addition to goodwill, PSEG’s total intangible assets as of December 31, 2003 were $103 million, all of which are not subject to amortization. These intangible assets totaled $14 million, $49 million and $40 million and are related to defined benefit pension plans, emissions allowances, which are expensed as used, and various access rights, respectively. In addition to goodwill, PSEG’s total intangible assets as of December 31, 2002 were $206 million, all of which are not subject to amortization, of which $114 million, $52 million and $40 million, related to defined benefit pension plans, emissions allowances, which are expensed as used, and various access rights, respectively.
PSE&G
As of December 31, 2003 and December 31, 2002, PSE&G had intangible assets recorded related to defined benefit pension plans totaling $2 million and $60 million, respectively. These intangible assets are not subject to amortization.
Power
In addition to goodwill displayed in the table below, as of December 31, 2003, Power’s intangible assets were $92 million, of which $3 million, $49 million and $40 million, related to its defined benefit
132
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
pension plans, emissions allowances, which are expensed as used, and various access rights at its Albany Station, respectively. As of December 31, 2002, in addition to goodwill displayed in the table below, Power’s intangible assets were $125 million, of which $33 million, $52 million and $40 million, related to its defined benefit pension plans, emissions allowances, which are expensed as used, and various access rights, respectively.
Energy Holdings
In addition to goodwill displayed in the table below, Energy Holdings has an intangible asset related to its defined benefit pension plans of $4 million and $5 million as of December 31, 2003 and 2002, respectively, which is not subject to amortization.
On January 1, 2002, Energy Holdings recorded the results of its evaluation under SFAS 142. The total amount of goodwill impairments was $121 million, net of tax of $66 million, and was comprised of $36 million (after-tax) at Empresa Distribuidora de Electricidad de Entre Rios S.A. (EDEERSA), an Argentine distribution company, $35 million (after-tax) at RGE, a Brazilian distribution company, $32 million (after-tax) at Energy Technologies and $18 million (after-tax) at Tanir Bavi Power Company Ltd. (Tanir Bavi), a generating facility in India. All of the goodwill related to these companies, other than RGE, was fully impaired.
Power and Energy Holdings
Power and Energy Holdings evaluated the recoverability of the recorded amount of goodwill based on certain operating and financial factors. Such impairment testing included discounted cash flow tests which require broad assumptions and significant judgment to be exercised by management. As of December 31, 2003 and December 31, 2002, Power and Energy Holdings’ goodwill and pro-rata share of goodwill in equity method investments was as follows:
| | As of
December 31, | |
| |
| |
| | 2003 | | 2002 | |
| | (Millions) | |
| | | |
Consolidated Investments | | | | | | | |
Energy Holdings—Global | | | | | | | |
Sociedad Austral de Electricidad S.A. (SAESA)(A) | | $ | 352 | | $ | 290 | |
Empresa de Electricidad de los Andes S.A. (Electroandes)(B) | | | 133 | | | 134 | |
Elektrocieplownia Chorzow Sp. Z o.o. (ELCHO) | | | 6 | | | 6 | |
| |
|
| |
|
| |
Total Energy Holdings-Global | | | 491 | | | 430 | |
Power—Albany Steam Station | | | 16 | | | 16 | |
| |
|
| |
|
| |
Total PSEG Consolidated Goodwill | | | 507 | | | 446 | |
| |
|
| |
|
| |
Pro-Rata Share of Equity Method Investments | | | | | | | |
Energy Holdings-Global | | | | | | | |
Rio Grande Energia (RGE)(A) | | | 73 | | | 58 | |
Chilquinta Energia S.A. (Chilquinta)(A)(C) | | | 163 | | | 163 | |
Luz del Sur S.A.A(C) | | | 63 | | | 39 | |
Kalaeloa | | | 25 | | | 25 | |
| |
|
| |
|
| |
Pro-Rata Share of Equity Investment Goodwill | | | 324 | | | 287 | |
| |
|
| |
|
| |
Total PSEG Goodwill | | $ | 831 | | $ | 733 | |
| |
|
| |
|
| |
(A)
Changes relate to changes in foreign exchange rates.
(B)
Changes relate to purchase price allocation adjustments.
(C)
Changes relate to a realignment of existing investments in Chile and Peru.
133
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SFAS 133
PSEG, PSE&G, Power and Energy Holdings
On January 1, 2001, PSE&G, Power and Energy Holdings adopted SFAS 133. SFAS 133 established accounting and reporting standards for derivative instruments, including certain derivative instruments included in other contracts, and for hedging activities. The rules require an entity to recognize the fair value of derivative instruments held as assets or liabilities on the balance sheet. For cash flow and net investment hedging, changes in the fair value of the effective portion of the gain or loss on the derivative are reported in OCI or as a Regulatory Asset (Liability), net of tax for cash flow hedge amounts in OCI and are ultimately recognized in earnings simultaneously with the related hedged forecasted transaction. The change in the fair value of the ineffective portion of the gain or loss on a derivative instrument designated as a cash flow hedge is recorded in earnings. Derivative instruments that are not cash flow or net investment hedges or have not been designated as hedges are adjusted to fair value through earnings.
Energy Holdings
On January 1, 2001, Energy Holdings recorded a Cumulative Effect of a Change in Accounting Principle of $10 million, net of tax and a decrease to OCI of $15 million related to the adoption of SFAS 133.
FIN 46
PSEG, PSE&G, Power and Energy Holdings
FASB Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities”, or FIN 46R replaces FIN 46, which was issued July 1, 2003. FIN 46R clarifies the application of Accounting Research Bulletin No. 51, “Consolidated Financial Statements” to certain entities in which equity investors do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support.
FIN 46R requires the adoption of either FIN 46 or FIN 46R by the first period ended after December 15, 2003 for Special Purpose Entities (SPEs), however FIN 46R must be adopted no later than the first period ended after March 15, 2004. Non-SPEs are required to be accounted for under the provisions of FIN 46R no later than the first period ended after March 15, 2004. PSEG, PSE&G, Power and Energy Holdings adopted the provisions of FIN 46 as of July 1, 2003. There was no effect on Power due to the adoption of these rules.
The adoption of FIN 46 required PSEG and PSE&G to deconsolidate their capital trusts and Energy Holdings to consolidate its investments in four real estate partnerships. Prior period financial statements have been reclassified for comparability in accordance with FIN 46.
PSEG and PSE&G
PSEG and PSE&G evaluated their respective interests in PSEG Capital Trusts I-IV, PSEG Funding Trust I (trust holding Participating Equity Preference Securities (PEPS)), PSE&G Capital Trust LP and PSE&G Capital Trusts II and determined them to be VIEs under FIN 46. It was further determined that PSEG and PSE&G were not the primary beneficiaries of those entities and therefore are prohibited from consolidating them into the financial statements. Accordingly, these entities were deconsolidated as of July 1, 2003 and were recorded under the equity method of accounting. This resulted in the removal of the preferred securities issued by the trusts from the Consolidated Balance Sheet and the addition to the Consolidated Balance Sheet of long-term debt in an equal amount between PSEG and PSE&G and the respective trusts, which previously had been eliminated in consolidation. Additionally, PSEG’s and PSE&G’s Consolidated Balance Sheets will reflect their equity investment in these entities, which also was previously eliminated in consolidation and will result in equal amounts of additional assets and long-term debt of $36 million and $41 million for PSEG as of
134
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2003 and 2002, respectively. These amounts totaled $5 million for PSE&G as of December 31, 2002. The invested cash was loaned back to PSEG and PSE&G in connection with the issuance of the preferred securities. In December 2003, PSE&G redeemed the preferred securities mentioned above. See Note 15. Schedule of Consolidated Debt for additional information.
The following table displays the securities, and their original issuance amounts, held by the trusts that have now been deconsolidated.
| | As of
December 31, | |
| |
| |
| | 2003 | | 2002 | |
| | (Millions) | |
| | | |
PSEG | | | | | | | |
PSEG Quarterly Guaranteed Preferred Beneficial Interest in PSEG’s Subordinated Debentures | | | | | | | |
7.44% | | $ | 225 | | $ | 225 | |
Floating Rate | | | 150 | | | 150 | |
7.25% | | | 150 | | | 150 | |
8.75% | | | 180 | | | 180 | |
PSEG Participating Units | | | | | | | |
10.25% | | | 460 | | | 460 | |
| |
|
| |
|
| |
Total PSEG (Parent) | | | 1,165 | | | 1,165 | |
| |
|
| |
|
| |
PSE&G | | | | | | | |
PSE&G Monthly Guaranteed Preferred Beneficial Interest in PSE&G’s 8.000% Subordinated Debentures | | | — | | | 60 | |
PSE&G Quarterly Guaranteed Preferred Beneficial Interest in PSE&G’s 8.125% Subordinated Debentures | | | — | | | 95 | |
| |
|
| |
|
| |
Total PSE&G | | | — | | | 155 | |
| |
|
| |
|
| |
Total PSEG Consolidated | | $ | 1,165 | | $ | 1,320 | |
| |
|
| |
|
| |
PSEG and PSE&G now record interest expense (previously eliminated against the interest income of the trust) instead of preferred securities dividends (since the preferred dividends are in the trusts that are no longer consolidated). For PSEG, these amounts totaled $69 million, $53 million and $67 million for the years ended December 31, 2003, 2002 and 2001, respectively. For PSE&G, these amounts totaled $13 million, $13 million and $24 million for the years ended December 31, 2003, 2002 and 2001, respectively.
Energy Holdings
Energy Holdings evaluated its interests in four real estate partnerships previously accounted for under the equity method of accounting. These entities were determined to be VIEs and Energy Holdings was determined to be the primary beneficiary and therefore is required to consolidate these entities. The current presentation reflects these entities on a fully consolidated basis and all periods were restated in accordance with FIN 46.
The impact of consolidating the real estate partnerships on the Consolidated Balance Sheets is as follows:
135
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | As of
December 31, | |
| |
| |
| | 2003 | | 2002 | |
| | (Millions) | |
| | | |
Amount Previously Recorded Using Equity Method of Accounting | | | | | | | |
Investment in Real Estate Partnerships | | $ | 23 | | $ | 23 | |
| |
|
| |
|
| |
Amount Recorded Using Consolidation | | | | | | | |
Current Assets | | $ | 4 | | $ | 4 | |
Noncurrent Assets | | | 50 | | | 51 | |
| |
|
| |
|
| |
Total Assets | | $ | 54 | | $ | 55 | |
| |
|
| |
|
| |
Noncurrent Liabilities | | $ | 25 | | $ | 26 | |
Minority Interest | | | 6 | | | 6 | |
| |
|
| |
|
| |
Total Liabilities and Minority Interest | | $ | 31 | | $ | 32 | |
| |
|
| |
|
| |
There was no material impact of consolidating the real estate partnerships on Operating Revenues and Operating Expenses.
FIN No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45)
PSEG, PSE&G, Power and Energy Holdings
FIN 45 enhances the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing the guarantee. PSEG, PSE&G, Power and Energy Holdings do not anticipate the recording of such liabilities will be material to their respective consolidated financial statements. The initial recognition and initial measurement provisions of this Interpretation were applicable on a prospective basis to guarantees issued or modified after December 31, 2002. For further information regarding Power’s and Energy Holdings’ respective guarantees, refer to Note 17. Commitments and Contingent Liabilities.
EITF Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities”, and Not “Held for Trading Purposes” as Defined in EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 03-11)
PSEG, PSE&G, Power and Energy Holdings
The EITF has previously discussed the income statement presentation of gains and losses on contracts held for trading purposes in EITF 02-3. The EITF reached a consensus that gains and losses (realized and unrealized) on all derivative instruments within the scope of SFAS 133 should be shown net when recognized in the Consolidated Statement of Operations, whether or not settled physically, if the derivative instruments are “held for trading purposes” as defined in EITF 02-3. EITF 03-11 contemplates whether realized gains and losses should be shown gross or net in the Consolidated Statement of Operations for contracts that are not held for trading purposes, but are derivatives subject to SFAS 133. On July 31, 2003, the EITF indicated that the determination of whether realized gains and losses on physically settled derivative contracts not “held for trading purposes” should be reported on a gross or net basis is a matter of judgment. The EITF indicated that companies may base their judgment on existing authoritative guidance in gross/net presentation, such as EITF 99-19, “Reporting Revenue Gross as a Principal Versus Net as an Agent” (EITF 99-19). These rules, which are effective for transactions occurring after September 30, 2003, required PSEG and Power to reduce revenues and
136
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
costs by approximately $5 million since these transactions are required to be recorded as net revenue. EITF 03-11 had no impact on PSE&G and Energy Holdings.
EITF Issue No. 03-4, “Accounting for Cash Balance Pension Plans” (EITF 03-4)
PSEG, PSE&G, Power and Energy Holdings
EITF 03-4 requires that cash balance pension plans be accounted for as defined benefit plans. EITF 03-4 indicates that cash balance plans are forms of accumulation plans with variable crediting formulas and are therefore not pay-related. As a result, a company would apply a traditional unit credit method for determining the expense associated with these plans. PSEG, PSE&G, Power and Energy Holdings each have previously accounted for their cash balance pension plans as defined benefit plans, thus there will be no material impact on their respective financial statements.
EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” (EITF 02-3)
PSEG and Power
EITF 02-3 requires all gains and losses on energy trading derivatives to be reported on a net basis. Also, energy trading contracts that are not derivatives under SFAS 133 will no longer be marked to market. EITF 02-3 became fully effective January 1, 2003. The majority of Power’s energy trading contracts qualify as derivatives under SFAS 133 and will therefore continue to be marked to market. The impact of implementing these rules had no effect on PSEG’s or Power’s Net Income. Prior period Operating Revenues and Energy Costs on the Consolidated Statements of Operations have been reclassified on a net basis for comparability.
EITF Issue No. 01-8, “Determining Whether an Arrangement is a Lease” (EITF 01-8)
PSEG, PSE&G, Power and Energy Holdings
EITF 01-8 provides guidance in determining whether an arrangement should be considered a lease subject to the requirements of SFAS 13. EITF 01-8 states that the evaluation of whether an arrangement contains a lease within the scope of SFAS 13 should be based on the substance of the arrangement. EITF 01-8 is applied to arrangements agreed or committed to, modified, or acquired in business combinations initiated on or after October 1, 2003. There were no significant impacts on PSEG’s, PSE&G’s, Power’s and Energy Holdings respective results of operations, financial position and net cash flows as a result of the adoption of EITF 01-8.
Other
PSEG, PSE&G, Power and Energy Holdings
In connection with the January 2003 EITF meeting, the FASB was requested to reconsider an interpretation of SFAS 133. The interpretation, which is contained in the Derivatives Implementation Group’s (DIG) C-11 guidance, further clarified by the issuance of DIG Issue C-20, relates to the pricing of contracts that include broad market indices. In particular, that guidance discusses whether the pricing in a contract that contains broad market indices (e.g., Consumer Price Index) could qualify as a normal purchase or sale under SFAS 133. There were no significant impacts on PSEG’s, PSE&G’s, Power’s and Energy Holdings’ respective results of operations, financial position and net cash flows as a result of this interpretation.
137
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 4. Adoption of SFAS 143
PSEG and Power
In the first quarter of 2003, Power completed a review of potential obligations under SFAS 143 and determined that the obligations were primarily related to the decommissioning of its nuclear power plants. Power’s recorded liability for decommissioning as of December 31, 2002 was approximately $766 million and equaled the balance of its NDT Fund, as discussed below. As of January 1, 2003, this liability was recalculated under SFAS 143, and determined to be approximately $261 million. Concurrently, an asset was recorded of approximately $50 million and represented the fair value of the asset retirement obligation at adoption. This asset and liability were calculated using a probability-weighted average of multiple scenarios. The scenarios were each based on estimated cash flows, which were discounted using Power’s risk-adjusted interest rate at the required effective date of the standard and considering the expected time period of the cash outflows. The scenarios included estimates for inflation, contingencies and assumptions related to the timing of decommissioning costs, using the current license lives for each unit, as well as early shutdown and license extensions scenarios.
In addition to the $261 million nuclear decommissioning liability, Power identified certain other legal obligations that meet the criteria of SFAS 143, which are currently not quantifiable, but could be material in the future. These obligations relate to certain industrial establishments subject to the New Jersey Industrial Site Recovery Act (ISRA), underground storage tanks subject to closure requirements, permits and authorizations, the restoration of an area to be occupied by a reservoir at the end of its useful life, an obligation to retire certain plants prior to the start up of a new plant and the demolition and restoration of certain other plant sites once they are no longer in service. Because these legal obligations are not quantifiable, no amounts have been recorded.
Power also had $131 million of cost of removal liabilities recorded on its Consolidated Balance Sheet, as of December 31, 2002, which did not meet the requirements of an Asset Retirement Obligation (ARO) and were therefore reversed and included in the Cumulative Effect of a Change in Accounting Principle recorded in the first quarter of 2003.
As a result of adopting SFAS 143, PSEG and Power recorded a Cumulative Effect of a Change in Accounting Principle of $370 million, after-tax, in the first quarter of 2003. Of this amount, $292 million (after-tax) related to decommissioning at Nuclear and $78 million (after-tax) related to the cost of removal liabilities for the fossil units that were reversed.
The following table reflects pro forma results which include accretion and depreciation expense as if SFAS 143 had always been in effect.
| | Years Ended
December 31, | |
| |
| |
| | 2003 | | 2002 | | 2001 | |
| | (Millions) | |
| | | |
PSEG | | | | | | | | | | |
Net Income—as reported | | $ | 1,160 | | $ | 235 | | $ | 764 | |
Net Income—pro forma | | $ | 790 | | $ | 221 | | $ | 747 | |
| | | | | | | | | | |
Earnings per share: | | | | | | | | | | |
Basic—as reported | | $ | 5.08 | | $ | 1.13 | | $ | 3.67 | |
Basic—pro forma | | $ | 3.46 | | $ | 1.06 | | $ | 3.59 | |
| | | | | | | | | | |
Diluted—as reported | | $ | 5.07 | | $ | 1.13 | | $ | 3.67 | |
Diluted—pro forma | | $ | 3.45 | | $ | 1.06 | | $ | 3.59 | |
Power | | | | | | | | | | |
Net Income—as reported | | $ | 844 | | $ | 468 | | $ | 394 | |
Net Income—pro forma | | $ | 474 | | $ | 454 | | $ | 377 | |
The pro forma amount of the liability for Power’s asset retirement obligations for the period ended December 31, 2002, as well as the actual amount of the liability recorded on Power’s Consolidated
138
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Balance Sheets as of December 31, 2003 are presented in the following table. These amounts were calculated using current information, current assumptions and current interest rates.
| | As of
December 31, | |
| |
| |
| | 2003 | | 2002 | |
| | (Millions) | |
| | | |
PSEG and Power | | | | | | | |
Beginning of Period ARO Liability | | $ | 260 | | $ | 238 | |
Accretion Expense | | | 24 | | | 22 | |
| |
|
| |
|
| |
End of Period ARO Liability | | $ | 284 | | $ | 260 | |
| |
|
| |
|
| |
PSE&G
PSE&G identified certain legal obligations that meet the criteria of SFAS 143, which are currently not quantifiable and therefore are not recorded. These obligations relate to certain industrial establishments subject to the ISRA, underground storage tanks subject to closure requirements, leases and licenses and the requirement to seal natural gas pipelines when the pipelines are no longer in service.
PSE&G had $393 million of cost of removal liabilities recorded on its Consolidated Balance Sheet as of December 31, 2002, which did not meet the requirements of an Asset Retirement Obligation (ARO) and were therefore reclassified to a regulatory liability in 2003. See Note 10. Regulatory Assets and Liabilities for further discussion.
Energy Holdings
Energy Holdings has identified certain legal obligations that meet the criteria of SFAS 143. However, it has determined that they are not material to its financial position, results of operations or net cash flows.
SFAS 143 Effect on the NDT Fund
Power
Prior to the adoption of SFAS 143, amounts collected from PSE&G customers through rates were deposited into the NDT Fund and realized and unrealized gains and losses in the trust were all recorded as changes in the NDT Fund with an offsetting charge to the nuclear decommissioning liability. Prior to SFAS 143, this was appropriate under SFAS 71 and other related accounting guidance. Based on an order issued by the BPU, PSE&G’s customers are no longer required to fund the NDT Fund, and therefore deferral accounting is no longer appropriate for changes in the fair value of securities within the NDT Fund.
Beginning January 1, 2003, realized gains and losses were recorded in earnings and unrealized gains and losses were recorded as a component of OCI, net of tax, as required under SFAS 115. Additionally, because deferral accounting was no longer appropriate, as of January 1, 2003, Power recognized $68 million of pre-tax unrealized losses on securities in the NDT Fund, approximately $40 million of which were deemed other than temporarily impaired and recorded this amount against earnings in the Cumulative Effect of a Change in an Accounting Principle in the first quarter of 2003.
As of December 31, 2003, the fair market value of the NDT Fund was $985 million. For further information regarding the NDT Fund, refer to Note 18. Nuclear Decommissioning Trust.
139
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5. Discontinued Operations
Energy Holdings
CPC
Global has a controlling interest in CPC, which owns and operates a power plant located in Rades, Tunisia. In December 2003, Global entered into a definitive purchase and sale agreement related to its majority interest in CPC, for approximately $43 million. Global will receive approximately $17 million in cash and a promissory note of $26 million, bearing interest at 5%. The note will be payable in three annual installments following the close of the sale of approximately $5 million, $10 million and $11 million, plus interest. The completion of the sale is expected to occur in the latter part of 2004 and is subject to certain conditions, including government and lender approvals. If the sale is unable to be completed, Global will seek another buyer for this facility. CPC meets the criteria for classification as a component of discontinued operations and all prior periods have been reclassified to conform to the current year’s presentation. Global has reduced its carrying value of CPC to its fair value less cost to sell and recorded a loss on disposal for the year ended December 31, 2003 of $23 million. The operating results of CPC for the years ended December 31, 2003, 2002 and 2001 are summarized below.
| | Years Ended
December 31, | |
| |
| |
| | 2003 | | 2002 | | 2001 | |
| | (Millions) | |
| | | | | | | | | | | | | | | | |
Operating Revenues | | | $ | 95 | | | | $ | 57 | | | | $ | — | | |
Pre-Tax (Loss) Income | | | $ | (8 | ) | | | $ | 2 | | | | $ | 8 | | |
Net (Loss) Income | | | $ | (1 | ) | | | $ | 1 | | | | $ | 4 | | |
The carrying amounts of the assets and liabilities of CPC as of December 31, 2003 and 2002 are summarized in the following table:
| | As of December 31, | |
| |
| |
| | 2003 | | 2002 | |
| | (Millions) | |
| | | | | | | | | | | |
Current Assets | | | $ | 28 | | | | $ | 24 | | |
Noncurrent Assets | | | | 270 | | | | | 288 | | |
| | |
|
| | | |
|
| | |
Total Assets | | | $ | 298 | | | | $ | 312 | | |
| | |
|
| | | |
|
| | |
Current Liabilities | | | $ | 161 | | | | $ | 40 | | |
Noncurrent Liabilities | | | | 68 | | | | | 60 | | |
Long-Term Debt | | | | 13 | | | | | 141 | | |
| | |
|
| | | |
|
| | |
Total Liabilities | | | $ | 242 | | | | $ | 241 | | |
| | |
|
| | | |
|
| | |
Energy Holdings has been informed that its indirect subsidiary, CPC, has incurred a non-payment related default under its non-recourse project financing. There are no cross-defaults associated with this technical default. CPC is seeking a waiver and although no acceleration of the approximately $160 million of outstanding project debt is expected, no assurances can be given.
Energy Technologies
Energy Holdings reduced the carrying value of the investments in the 11 HVAC/mechanical operating companies to their fair value less costs to sell, and recorded a loss on disposal for the year ended December 31, 2002 or $20 million, net of $11 million in taxes. During 2003, Energy Holdings re-evaluated the carrying value of Energy Technologies’ assets and liabilities and determined that market conditions required an additional write-down to fair value less cost to sell and recorded an additional loss on disposal of Energy Technologies of $9 million, net of a $3 million tax benefit. The sale of the HVAC/mechanical operating companies and Energy Technologies was complete as of September 30, 2003.
140
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Energy Holdings has retained certain residual assets and liabilities. As of December 31, 2003, the value of these investments consisted of $60 million in assets and $25 million in liabilities. Of the $60 million in assets, approximately $39 million relates to tax assets associated with the sale of Energy Technologies’ HVAC/mechanical operating companies, with the remaining balance relating primarily to accounts receivable not sold with the HVAC/mechanical operating companies.
The revenues and results of operations of Energy Technologies for the periods ended December 31, 2003, 2002 and 2001, are displayed below:
| | Years Ended
December 31, | |
| |
| |
| | 2003 | | 2002 | | 2001 | |
| | (Millions) | |
| | | |
Operating Revenues | | $ | 68 | | $ | 378 | | $ | 441 | |
Pre-Tax Loss | | $ | (18 | ) | $ | (32 | ) | $ | (34 | ) |
Net Loss | | $ | (11 | ) | $ | (21 | ) | $ | (23 | ) |
The carrying amounts of the assets and liabilities as of December 31, 2002 are summarized in the following table:
| | As of
December 31,
2002 | |
| | (Millions) | |
| | | | | | |
Current Assets | | | $ | 82 | | |
Noncurrent Assets | | | | 25 | | |
| | |
|
| | |
Total Assets | | | $ | 107 | | |
| | |
|
| | |
Current Liabilities | | | $ | 85 | | |
Noncurrent Liabilities | | | | 5 | | |
Long-Term Debt | | | | 5 | | |
| | |
|
| | |
Total Liabilities | | | $ | 95 | | |
| | |
|
| | |
Tanir Bavi
In the fourth quarter of 2002, Global sold its interest in Tanir Bavi for approximately $45 million. Global reduced the carrying value of Tanir Bavi to the contracted sales price of $45 million and recorded a loss on disposal of $14 million (after-tax of $7 million) for the year ended December 31, 2002. The facility met the criteria for classification as a component of discontinued operations and all prior periods were reclassified to conform to that presentation. The operating results of Tanir Bavi for the years ended December 31, 2002 and 2001 are summarized below.
| | Years Ended
December 31, | |
| |
| |
| | 2002 | | 2001 | |
| | (Millions) | |
Operating Revenues | | | $ | 61 | | | | $ | 56 | | |
Pre-Tax Income | | | $ | 7 | | | | $ | 14 | | |
Net Income | | | $ | 5 | | | | $ | 7 | | |
Note 6. Extraordinary Item
PSE&G
In May 2002, PSE&G filed an Electric Base Rate Case with the BPU requesting an annual $250 million increase for its electric distribution business. In June 2003, a proposed settlement was filed with the Administrative Law Judge (ALJ) who recommended approval of the settlement to the BPU. In July
141
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2003, PSE&G received an oral decision from the BPU approving the proposed settlement with certain modifications. As a result of the oral decision and subsequent summary written order, in the second quarter of 2003, PSE&G recorded certain adjustments in connection with the resolution of various issues relating to the Final Order PSE&G received from the BPU in 1999 relating to PSE&G’s rate unbundling, stranded costs and restructuring proceedings. These amounts include a $30 million pre-tax refund to customers related to revenues previously collected in rates for nuclear decommissioning. Because this amount reflects the final accounting for PSEG’s generation-related business pursuant to the four-year transition plan mandated by the Final Order, the adjustment has been recorded as an $18 million, after-tax, Extraordinary Item as required under APB No. 30, “Reporting the Results of Operations—Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions” (APB 30) and SFAS No. 101, “Regulated Enterprises—Accounting for the Discontinuation of Application of FASB Statement No. 71”.
Note 7. Change in Accounting Principle
PSE&G and Power
In 2002, PSE&G and Power each changed its method of accounting for the classification of assets and liabilities arising from transactions related to energy trading contracts when the right of set-off exists, from a separate presentation of assets and liabilities to a net presentation. PSE&G and Power believe that the right of set-off exists when all of the following conditions are met:
•
PSE&G or Power and its respective counterparty owes the other determinable amounts;
•
PSE&G or Power have the right to set off the amount owed with the amount owed by its respective counterparty;
•
PSE&G or Power intend to set-off; and
•
the right of set-off is enforceable by law.
PSE&G and Power each believe that this change in method of accounting and classification is preferable and more closely represents the economic substance of such transactions. Additionally, this method reflects PSE&G’s and Power’s existing practice of settling amounts net and is consistent with the classification of trading revenues and trading costs on a net basis on the Consolidated Statements of Operations.
There was no effect on revenues, expenses, net income or cash flows as a result of this change. Affected amounts on the Consolidated Balance Sheets have been reclassified for all periods presented.
Note 8. Asset Impairments
Energy Holdings
In 2002, Energy Holdings determined that the carrying value of its investments in EDEERSA; minority interests in three distribution companies, Empresa Distribuidora de Energia Norte S.A. (EDEN), Empresa Distribuidora de Energia Sur S.A. (EDES) and Empresa Distribuidora La Plata S.A. (EDELAP); and two generating companies, Central Termica San Nicolas S.A. (CTSN) and AES Parana S.C.A. (Parana) were impaired. The combination of the year-to-date operating losses, goodwill impairment at EDEERSA, write-down of $497 million for all Argentine assets, and certain loss contingencies resulted in a pre-tax charge to earnings of $621 million ($404 million after-tax), as discussed further below. In connection with the write-down of Energy Holdings’ Argentine assets, Energy Holdings recorded a net deferred tax asset of $217 million. Energy Holdings has reviewed this deferred tax asset for recoverability and no reserve is required. For a discussion of certain contingencies related to Argentine investments, see Note 17. Commitments and Contingent Liabilities.
142
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The tables below provide pre-tax and after-tax impacts of the various impairment charges, results of operations and accruals of loss contingencies recorded with respect to Energy Holdings’ investments in Argentina for the periods ended December 31, 2002 and 2001.
| | (Pre-Tax)
Years Ended
December 31, | | (After-Tax)
Years Ended
December 31, | |
| |
| |
| |
| | 2002 | | 2001 | | 2002 | | 2001 | |
| | (Millions) | |
| | | | | | | | | | | | | |
(Losses) Earnings Before Local Taxes—EDEERSA | | $ | (57 | ) | $ | 19 | | $ | (38 | ) | $ | 11 | |
Write-down of EDEERSA | | | (94 | ) | | — | | | (61 | ) | | — | |
Write-down of Assets Held for Sale to AES | | | (403 | ) | | — | | | (262 | ) | | — | |
Loss Contingencies and Other | | | (11 | ) | | — | | | (7 | ) | | — | |
Goodwill Impairment—EDEERSA | | | (56 | ) | | — | | | (36 | ) | | — | |
| |
|
| |
|
| |
|
| |
|
| |
Total | | $ | (621 | ) | $ | 19 | | $ | (404 | ) | $ | 11 | |
| |
|
| |
|
| |
|
| |
|
| |
EDEERSA
In January 2002, the Argentine Federal government enacted a temporary emergency law that imposed various changes to the concession contracts in effect between electric distributors and local and federal regulators. The Province of Entre Rios enjoined in the emergency law impacting operations at EDEERSA. The Argentine government and regulators made unilateral decisions to abrogate key components of the tariff concessions related to public utilities. Such laws significantly restricted Global’s ability to control the operations of EDEERSA, as unilateral changes enacted by the government restricted Global’s ability to manage its operations to reduce the financial losses incurred as a result of such actions.
Based on actual and projected operating losses at EDEERSA and the continued economic uncertainty in Argentina, Energy Holdings determined that it was necessary to test these assets for impairment. Such impairment analyses were completed as of June 30, 2002. As a result of these analyses, Energy Holdings determined that these assets were completely impaired under SFAS 144.
In March 2003, PSEG formally and irrevocably renounced, and effectively abandoned, its entire economic and legal interest in EDEERSA. The shares were relinquished and ownership was assumed by an Argentine trust benefiting current EDEERSA employees and minority shareholders. The regulator in the Province has requested that 51% of the EDEERSA shares be transferred from the trust to the Province. The matter is pending in the courts. A representative of the labor union representing EDEERSA filed a criminal complaint against the transaction alleging that the union should have been allocated more interest in EDEERSA than the trust arrangement currently provides. Energy Holdings believes that it will have no additional exposure as a result of these legal proceedings but no assurances can be given.
Stock Purchase Agreement
During 2002, Energy Holdings determined that its minority interests in EDEN, EDES, EDELAP, CTSN and Parana were impaired and wrote them down to net realizable value. This resulted in a pre-tax charge $403 million, which was recorded in Write-down of Project Investments on the Consolidated Statement of Operations. On August 24, 2001, Global entered into a Stock Purchase Agreement with The AES Corporation (AES) to sell these investments to certain subsidiaries of AES. AES paid Global $15 million in 2002 and issued promissory notes for an additional $15 million, plus interest at 12%, maturing through July 2003. In July 2003, Energy Holdings received the final note payment from AES.
In connection with the completion of the sale, certain contingent obligations Global had with respect to the project loans relating to EDELAP were terminated by agreement with the lenders.
143
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In August 2003, the shares held by Global in the AES Parana companies were transferred to AES. In connection with the transfer, all contingent obligations Global had with respect to the project loans relating to the AES Parana project were terminated by agreement with the lenders.
Note 9. Restructuring Charges
PSE&G
In April 2003, PSE&G implemented a plan, approved by management, to reduce its work force by approximately 40 positions. These employees voluntarily elected for separation and, thus, was accounted for under SFAS No. 88, “Employers’ Accounting for Settlements and Curtailments of Defined Benefit Pension Plans and for Termination Benefits” (SFAS 88). The cost associated with the restructuring was approximately $3 million and primarily related to termination benefits, all of which have been paid as of December 31, 2003.
Power
In 2003, Power implemented a plan, approved by management, to reduce its work force by approximately 190 positions. The plan was carried out in several phases, which included voluntary and involuntary separations being offered to both represented and non-represented employees. The major cost associated with the restructuring relates to benefits that are to be paid to the employees upon termination. The total cost estimated and recorded is approximately $14 million. The communications included sufficient detail to enable employees to determine the type and amount of benefits they would receive if they elected to be terminated. Amounts relating to voluntary separations were accounted for under SFAS 88, whereas the involuntary separations were accounted for under SFAS 146. The total cost and remaining accrual related to the restructuring charges are detailed below.
Energy Holdings
In 2002, Energy Holdings’ management approved a plan to consolidate some of its locations in order to improve the efficiency of its worldwide reporting processes and eliminate certain redundant administrative functions in North America, South America, England and India. As a result of this plan, Energy Holdings recognized a pre-tax restructuring charge of $7 million in 2002, consisting of $2 million in employee separation costs, a $3 million loss on impairment of leasehold improvements and furniture and equipment, and $2 million in facility exit costs related to subleasing certain offices. The $2 million in facility exit costs relates to the estimated difference in rents with respect to the sub-leased offices. Subsequent to the initial measurement, Energy Holdings revised its estimated cash flows related to these subleases as it was able to sublease these spaces and recognized an adjustment to the liability in 2003 for an additional $3 million.
PSEG, PSE&G, Power and Energy Holdings
The following table illustrates amounts charged against the restructuring reserve during the period ended December 31, 2003 which are included in Operation and Maintenance Expense on the Consolidated Statements of Operations:
| | PSE&G | | Power | | Energy
Holdings | | Total | |
| |
| |
| |
| |
| |
| | (Millions) | |
| | | |
Restructuring Accrual as of December 31, 2002 | | | $ | — | | | | $ | — | | | | $ | 2 | | | | $ | 2 | | |
Accrued For in 2003 | | | | 3 | | | | | 14 | | | | | 3 | | | | | 20 | | |
Total Paid in 2003 | | | | (3 | ) | | | | (8 | ) | | | | (1 | ) | | | | (12 | ) | |
| | |
|
| | | |
|
| | | |
|
| | | |
|
| | |
Remaining Accrual as of December 31, 2003 | | | $ | — | | | | $ | 6 | | | | $ | 4 | | | | $ | 10 | | |
| | |
|
| | | |
|
| | | |
|
| | | |
|
| | |
144
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 10. Regulatory Assets and Liabilities
PSE&G
PSE&G prepares its financial statements in accordance with the provisions of SFAS 71. A regulated utility is required to defer the recognition of costs (a regulatory asset) or the recognition of obligations (a regulatory liability) if it is probable that, through the rate-making process, there will be a corresponding increase or decrease in future rates. Accordingly, PSE&G has deferred certain costs, which will be amortized over various future periods. These costs are deferred based on rate orders issued by the BPU or the Federal Energy Regulatory Commission (FERC) or PSE&G’s experience with prior rate cases. As of December 31, 2003 and 2002, approximately 87% and 88%, respectively, of PSE&G’s regulatory assets were deferred based on written rate orders. Regulatory assets recorded on a basis other than by an issued rate order have less certainty of recovery since they can be disallowed in the future by regulatory authorities. PSE&G believes that all of its regulatory assets are probable of recovery. To the extent that collection of any regulatory assets or payments of regulatory liabilities is no longer probable, the amounts would be charged or credited to income.
PSE&G had the following regulatory assets and liabilities on the Consolidated Balance Sheets:
| | As of
December 31, | | | |
| |
| | | |
| | 2003 | | 2002 | | Recovery/Refund Period | |
| | (Millions) | | | | |
Regulatory Assets | | | | | | | | | | |
Securitized Stranded Costs | | $ | 3,659 | | $ | 3,885 | | | Through December 2015(1)(2) | |
Deferred Income Taxes | | | 368 | | | 326 | | | Various | |
OPEB-Related Costs | | | 174 | | | 193 | | | Through December 2012(2) | |
Manufactured Gas Plant Remediation Costs | | | 123 | | | 115 | | | Various(2) | |
Unamortized Loss on Reacquired Debt and Debt Expense | | | 94 | | | 86 | | | Over remaining debt life(1) | |
Underrecovered Gas Costs | | | 53 | | | 154 | | | Through September 2004(1) | |
Non-Utility Generation Transition Charge (NTC) | | | 112 | | | — | | | Through December 31, 2005(1) | |
Unrealized Losses on Interest Rate Swap | | | 51 | | | 66 | | | Through December 2015(2) | |
Repair Allowance Taxes | | | 82 | | | 93 | | | Through August 2013(1)(2) | |
Decontamination and Decommissioning Costs | | | 16 | | | 22 | | | Through December 2007(2) | |
Plant and Regulatory Study Costs | | | 23 | | | 26 | | | Through December 2021(2) | |
Regulatory Restructuring Costs | | | 42 | | | 31 | | | Through August 2013(1)(2) | |
Other | | | 4 | | | 5 | | | To be determined(1) | |
| |
|
| |
|
| | | | |
Total Regulatory Assets | | $ | 4,801 | | $ | 5,002 | | | | |
| |
|
| |
|
| | | | |
Regulatory Liabilities | | | | | | | | | | |
Cost of Removal | | $ | 395 | | $ | — | | | Various | |
Excess Depreciation Reserve | | | 127 | | | 171 | | | Through December 31, 2005(2) | |
NTC | | | — | | | 27 | | | Through December 31, 2005(1) | |
Societal Benefits Charges (SBC) | | | 7 | | | 50 | | | Through December 31, 2005(1)(2) | |
Other | | | 7 | | | 4 | | | Various(1) | |
| |
|
| |
|
| | | | |
Total Regulatory Liabilities | | $ | 536 | | $ | 252 | | | | |
| |
|
| |
|
| | | | |
(1)
Recovered/Refunded with interest.
(2)
Recoverable/Refundable per specific rate order.
All regulatory assets and liabilities are excluded from PSE&G’s rate base unless otherwise noted. The descriptions below define certain regulatory items.
145
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Securitized Stranded Costs: This reflects deferred costs, which are being recovered through the securitization transition charge that was authorized by the BPU. Funds collected through the securitization transition charge are remitted to Transition Funding and are solely to be used for interest and principal payments on the transition bonds, and the related costs and taxes.
Deferred Income Taxes:This amount represents the portion of deferred income taxes that will be recovered through future rates, based upon established regulatory practices, which permit the recovery of current taxes. Accordingly, this regulatory asset is offset by a deferred tax liability and is expected to be recovered, without interest, over the period the underlying book-tax timing differences reverse and become current taxes.
OPEB-Related Costs:Includes costs associated with the adoption of SFAS No. 106. “Employers’ Accounting for Benefits Other Than Pensions” which were deferred in accordance with EITF Issue No. 92-12, “Accounting for OPEB Costs by Rate Regulated Enterprises.”
Manufactured Gas Plant Remediation Costs: Represents a three-year estimate of the environmental investigation and remediation program costs that are probable of recovery in future rates.
Unamortized Loss on Reacquired Debt and Debt Expense: Represents long-term debt issuance costs, premiums, discounts and losses on reacquired long-term debt.
Underrecovered Gas Costs: Represents PSE&G’s gas costs in excess of the amount included in rates and probable of recovery in the future. The current portion of the balance does not accrue interest.
NTC: This clause was established by the EDECA to account for above market costs related to non-utility generation (NUG) contracts, as approved by the BPU. Costs or benefits associated with the restructuring of these contracts are deferred. This clause also includes Basic Generation Service (BGS) costs in excess of current rates, as approved by the BPU.
Unrealized Losses on Interest Rate Swap: This represents the costs related to Transition Funding’s interest rate swap that will be recovered without interest over the life of Transition Funding’s transition bonds. This asset is offset by a derivative liability on the balance sheet.
Repair Allowance Taxes: This represents tax, interest and carrying charges relating to disallowed tax deductions for repair allowance as authorized by the BPU with recovery over 10 years effective August 1, 2003.
Decontamination and Decommissioning Costs: These costs are related to PSE&G’s portion of the obligation for nuclear decontamination and decommissioning costs of U.S. Department of Energy nuclear sites dating back prior to the generation asset transfer to Power in 2000.
Plant and Regulatory Study Costs: These are costs incurred by PSE&G required by the BPU related to current and future operations, including safety, planning, management and construction.
Regulatory Restructuring Costs: These are costs related to the restructuring of the energy industry in New Jersey through the EDECA and include such items as the system design work necessary to transition PSE&G to a transmission and distribution only company, as well as costs incurred to transfer and establish the generation function as a separate corporate entity with recovery over 10 years beginning August 1, 2003.
Other Regulatory Assets: This includes consolidated billing start up costs that have been deferred for future recovery based on a BPU order.
Cost of Removal: PSE&G collects for cost of removal liabilities, which totaled $395 million as of December 31, 2003, which was reclassified from a Cost of Removal liability to a regulatory liability pursuant to the adoption of SFAS 143. This liability is reduced as removal costs are incurred. Cost of removal is a reduction to the rate base.
Excess Depreciation Reserve: As required by the BPU in 1999, PSE&G reduced its depreciation reserve for its electric distribution assets and recorded such amount as a regulatory liability. The original liability was fully amortized in July 2003. In June 2003, PSE&G recorded an additional $155 million
146
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
liability as a result of the oral decision issued by the BPU in PSE&G’s Electric Base Rate Case. This $155 million will be amortized from August 1, 2003 through December 31, 2005.
SBC: The SBC, as authorized by the BPU and the EDECA, includes costs related to PSE&G’s electric and gas business as follows: 1) the universal service fund; 2) amortization of previous overrecovery of nuclear plant decommissioning; 3) Demand Side Management (DSM) programs; 4) social programs which include bad debt expense; 5) consumer education; 6) the New Jersey Clean Energy Program costs payable in 2004; and 7) amortization of the market transition charge (MTC) overrecovery. All components except for MTC and Clean Energy accrue interest.
Other Regulatory Liabilities:This includes the following: 1) amounts collected from customers in order for Transition Funding to obtain a AAA rating on its transition bonds; 2) amounts available to fund consumer education discounts; and 3) a retail adder was included in the BGS charges beginning on August 1, 2003. The BPU will determine the disposition of this amount in the future.
Note 11. Earnings Per Share (EPS)
PSEG
Diluted earnings per share are calculated by dividing Net Income by the weighted average number of shares of common stock outstanding, including shares issuable upon exercise of stock options outstanding under PSEG’s stock option plans. The following table shows the effect of these stock options on the weighted average number of shares outstanding used in calculating diluted earnings per share:
| | Years Ended December 31, | |
| |
| |
| | 2003 | | 2002 | | 2001 | |
| |
| |
| |
| |
| | Basic | | Diluted | | Basic | | Diluted | | Basic | | Diluted | |
| | | | | | | | | | | | | |
EPS Numerator: | | | | | | | | | | | | | | | | | | | |
Earnings (Millions) | | | | | | | | | | | | | | | | | | | |
Continuing Operations | | $ | 852 | | $ | 852 | | $ | 405 | | $ | 405 | | $ | 766 | | $ | 766 | |
Discontinued Operations | | | (44 | ) | | (44 | ) | | (49 | ) | | (49 | ) | | (12 | ) | | (12 | ) |
Extraordinary Item | | | (18 | ) | | (18 | ) | | — | | | — | | | — | | | — | |
Cumulative Effect of a Change in Accounting Principle | | | 370 | | | 370 | | | (121 | ) | | (121 | ) | | 10 | | | 10 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Net Income | | $ | 1,160 | | $ | 1,160 | | $ | 235 | | $ | 235 | | $ | 764 | | $ | 764 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
EPS Denominator (Thousands): | | | | | | | | | | | | | | | | | | | |
Weighted Average Common Shares Outstanding | | | 228,222 | | | 228,222 | | | 208,647 | | | 208,647 | | | 207,737 | | | 207,737 | |
Effect of Stock Options | | | — | | | 602 | | | — | | | 166 | | | — | | | 489 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Total Shares | | | 228,222 | | | 228,824 | | | 208,647 | | | 208,813 | | | 207,737 | | | 208,226 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Earnings Per Share: | | | | | | | | | | | | | | | | | | | |
Continuing Operations | | $ | 3.73 | | $ | 3.72 | | $ | 1.94 | | $ | 1.94 | | $ | 3.68 | | $ | 3.68 | |
Discontinued Operations | | | (0.19 | ) | | (0.19 | ) | | (0.23 | ) | | (0.23 | ) | | (0.06 | ) | | (0.06 | ) |
Extraordinary Item | | | (0.08 | ) | | (0.08 | ) | | — | | | — | | | — | | | — | |
Cumulative Effect of a Change in Accounting Principle | | | 1.62 | | | 1.62 | | | (0.58 | ) | | (0.58 | ) | | 0.05 | | | 0.05 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Net Income | | $ | 5.08 | | $ | 5.07 | | $ | 1.13 | | $ | 1.13 | | $ | 3.67 | | $ | 3.67 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
There were approximately 5.3 million, 6.3 million and 2.2 million stock options not included in the weighted average common shares calculation used for diluted earnings per share due to their antidilutive effect for the years ended December 31, 2003, 2002 and 2001, respectively. There were approximately 9.2 million participating units not included in the weighted average common shares calculation used for diluted earnings per share due to their antidilutive effect for the years ended December 31, 2003 and 2002.
147
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 12. Long-Term Investments
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings had the following Long-Term Investments as of December 31, 2003 and 2002:
| | As of December 31, | |
| |
| |
| | 2003 | | 2002 | |
| | (Millions) | |
Energy Holdings: | | | | | | | |
Leveraged Leases | | $ | 2,981 | | $ | 2,844 | |
Partnerships: | | | | | | | |
General Partnerships | | | 25 | | | 28 | |
Limited Partnerships | | | 506 | | | 440 | |
| |
|
| |
|
| |
Total Partnerships | | | 531 | | | 468 | |
| |
|
| |
|
| |
Corporate Joint Ventures | | | 1,040 | | | 865 | |
Securities | | | 4 | | | 5 | |
Other Investments(A) | | | 27 | | | 33 | |
| |
|
| |
|
| |
Total Long-Term Investments of Energy Holdings | | | 4,583 | | | 4,215 | |
PSE&G(B) | | | 131 | | | 128 | |
Power(C) | | | 43 | | | 78 | |
Other Investments(D) | | | 51 | | | 47 | |
| |
|
| |
|
| |
Total Long-Term Investments | | $ | 4,808 | | $ | 4,468 | |
| |
|
| |
|
| |
(A)
Primarily relates to DSM investments at Resources.
(B)
Primarily relates to life insurance and supplemental benefits of $123 million and $113 million as of December 31, 2003 and 2002, respectively.
(C)
Amounts represent SO2 and NOx emission credits held for future use.
(D)
Amounts represent investments at PSEG (parent company), primarily related to investments in its Capital Trusts.
Energy Holdings
Leveraged Leases
Energy Holdings’ net investment, through Resources, in leveraged leases is comprised of the following elements:
| | As of December 31, | |
| |
| |
| | 2003 | | 2002 | |
| | (Millions) | |
Lease rents receivable | | $ | 3,373 | | $ | 3,429 | |
Estimated residual value of leased assets | | | 1,405 | | | 1,414 | |
| |
|
| |
|
| |
| | | 4,778 | | | 4,843 | |
Unearned and deferred income | | | (1,797 | ) | | (1,999 | ) |
| |
|
| |
|
| |
Total investments in leveraged leases | | | 2,981 | | | 2,844 | |
Deferred taxes | | | (1,563 | ) | | (1,325 | ) |
| |
|
| |
|
| |
Net investment in leveraged leases | | $ | 1,418 | | $ | 1,519 | |
| |
|
| |
|
| |
148
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Resources’ pre-tax income and income tax effects related to investments in leveraged leases are as follows:
| | Years Ended
December 31, | |
| |
| |
| | 2003 | | 2002 | | 2001 | |
| | (Millions) | |
Pre-tax income of leveraged leases | | | $ | 206 | | | | $ | 251 | | | | $ | 206 | | |
| | |
|
| | | |
|
| | | |
|
| | |
Income tax effect on pre-tax income of leveraged leases | | | $ | 74 | | | | $ | 92 | | | | $ | 62 | | |
Amortization of investment tax credits of leveraged leases | | | $ | (1 | ) | | | $ | (1 | ) | | | $ | (1 | ) | |
Of the $45 million increase in leveraged lease income in 2002, $29 million resulted from a gain due to a recalculation of certain leveraged leases. A change in an essential assumption which affects the estimated total net income over the life of a leveraged lease requires a recalculation of the leveraged lease, from inception, using the revised information. The change in the net investment in the leveraged leases is recognized as a gain or loss in the year the assumption is changed. The change in assumption that occurred was related to a change in New Jersey tax rates applied in the leveraged lease calculations. This was due to the restructuring of Resources from a corporation to a limited liability company, which resulted in the ability to more efficiently match state tax expenses of an affiliate company with the state tax benefits associated with Resources’ lease portfolio. The remaining $16 million increase in leveraged lease income was due to additional investments in leveraged lease transactions in 2002 and 2001.
In November 2003, Resources sold its interest in Chelsea Historic Properties. Resources received net cash proceeds of $9 million, recognizing an after-tax gain of approximately $4 million. As a result of the sales of these leases, Resources will pay income taxes of approximately $3 million.
In November 2002, Resources terminated two lease transactions due to an uncured default under the lease financial covenants. Resources received cash proceeds of $183 million, recognizing an after-tax gain of $4 million. As a result of these lease terminations, Resources paid income taxes of $115 million in 2003.
Partnership Investments and Corporate Joint Ventures
Energy Holdings’ partnership investments of $531 million and $468 million as of December 31, 2003 and December 31, 2002, respectively, and corporate joint ventures of approximately $1.0 billion and $865 million as of December 31, 2003 and December 31, 2002, respectively, are those of Resources, Global and EGDC. These investments are accounted for under the equity method of accounting.
Resources also has limited partnership investments in two leveraged buyout funds, a collateralized bond obligation structure, a clean air facility and solar electric generating systems. Resources’ total investment in limited partnerships was $94 million and $118 million as of December 31, 2003 and 2002, respectively.
The leveraged buyout funds mentioned above hold publicly traded securities, which are managed by a third party. The book value of the investment in the leveraged buyout funds was $75 million and $93 million as of December 31, 2003 and December 31, 2002, respectively. The largest single investment within the funds is the investment in privately held Borden, Inc., having a book value of $28 million and $48 million as of December 31, 2003 and December 31, 2002, respectively.
Resources applies fair value accounting to investments within the funds where publicly traded market prices are available. Approximately $26 million and $24 million represent the fair value of Resources’ share of the publicly traded securities in the funds as of December 31, 2003 and December 31, 2002, respectively. For a discussion of other than temporary impairments of securities of privately held interests in certain companies held within certain leveraged buyout funds at Resources, see Note 16. Risk Management.
149
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Investments in and Advances to Affiliates
Investments in net assets of affiliated companies accounted for under the equity method of accounting by Global amounted to $1.5 billion and $1.3 billion as of December 31, 2003 and December 31, 2002, respectively. During the three years ended December 31, 2003, 2002 and 2001, the amount of dividends from these investments was $130 million, $64 million and $51 million, respectively. Global’s share of income and cash flow distribution percentages ranged from 20% to 75% as of December 31, 2003. Interest is earned on loans made to various projects. Such loans earn interest that ranged from 8% to 20% during 2003.
Global has the following equity method investments as of December 31, 2003:
Name | | Location | | %
Owned | |
| | | | | | |
Texas Independent Energy | | | | | |
Guadalupe | | TX | | 50 | % | |
Odessa | | TX | | 50 | % | |
Kalaeloa | | HI | | 50 | % | |
GWF | | | | | | |
Bay Area I | | CA | | 50 | % | |
Bay Area II | | CA | | 50 | % | |
Bay Area III | | CA | | 50 | % | |
Bay Area IV | | CA | | 50 | % | |
Bay Area V | | CA | | 50 | % | |
Hanford | | CA | | 50 | % | |
Tracy | | CA | | 35 | % | |
GWF Energy | | | | | | |
Hanford-Peaker Plant | | CA | | 75 | % | |
Henrietta-Peaker Plant | | CA | | 75 | % | |
Tracy-Peaker Plant | | CA | | 75 | % | |
Bridgewater | | NH | | 40 | % | |
Conemaugh | | PA | | 50 | % | |
MPC | | | | | | |
Jingyuan—Units 5 & 6 | | China | | 15 | % | |
Tongzhou | | China | | 40 | % | |
Nantong | | China | | 46 | % | |
Jinqiao (Thermal Energy) | | China | | 30 | % | |
Zuojiang—Units 1, 2 & 3 | | China | | 30 | % | |
Fushi—Units 1, 2 & 3 | | China | | 35 | % | |
Shanghai BFG | | China | | 33 | % | |
Huangshi Unit I | | China | | 25 | % | |
Hexie | | China | | 50 | % | |
Mianyang—Unit 1 | | China | | 38 | % | |
Qujing—Phase II—Unit 3 | | China | | 19 | % | |
Kuo Kuang | | Taiwan | | 18 | % | |
PPN | | India | | 20 | % | |
Prisma | | | | | | |
Crotone | | Italy | | 25 | % | |
Bando D’Argenta I | | Italy | | 50 | % | |
Strongoli | | Italy | | 25 | % | |
Turboven | | | | | | |
Maracay | | Venezuela | | 50 | % | �� |
Cagua | | Venezuela | | 50 | % | |
RGE | | Brazil | | 33 | % | |
Chilquinta | | Chile | | 50 | % | |
LDS | | Peru | | 44 | % | |
150
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Summarized results of operations and financial position of affiliates in which Global applies the equity method of accounting are presented below:
| | Foreign | | Domestic | | Total | |
| | | | | (Millions) | | | | |
December 31, 2003 | | | | | | | | | | |
Condensed Statement of Operations Information | | | | | | | | | | |
Revenue | | | $ | 1,042 | | | | $ | 747 | | | | $ | 1,789 | | |
Gross Profit | | | $ | 415 | | | | $ | 231 | | | | $ | 646 | | |
Minority Interest | | | $ | (5 | ) | | | $ | — | | | | $ | (5 | ) | |
Net Income | | | $ | 138 | | | | $ | 67 | | | | $ | 205 | | |
Condensed Balance Sheet Information | | | | | | | | | | | | | | | | |
Assets: | | | | | | | | | | | | | | | | |
Current Assets | | | $ | 562 | | | | $ | 168 | | | | $ | 730 | | |
Property, Plant and Equipment | | | | 1,853 | | | | | 1,465 | | | | | 3,318 | | |
Goodwill | | | | 681 | | | | | 50 | | | | | 731 | | |
Other Noncurrent Assets | | | | 473 | | | | | 35 | | | | | 508 | | |
| | |
|
| | | |
|
| | | |
|
| | |
Total Assets | | | $ | 3,569 | | | | $ | 1,718 | | | | $ | 5,287 | | |
| | |
|
| | | |
|
| | | |
|
| | |
Liabilities: | | | | | | | | | | | | | | | | |
Current Liabilities | | | $ | 579 | | | | $ | 154 | | | | $ | 733 | | |
Debt* | | | | 1,075 | | | | | 785 | | | | | 1,860 | | |
Other Noncurrent Liabilities | | | | 217 | | | | | 124 | | | | | 341 | | |
Minority Interest | | | | 80 | | | | | — | | | | | 80 | | |
| | |
|
| | | |
|
| | | |
|
| | |
Total Liabilities | | | | 1,951 | | | | | 1,063 | | | | | 3,014 | | |
Equity | | | | 1,618 | | | | | 655 | | | | | 2,273 | | |
| | |
|
| | | |
|
| | | |
|
| | |
Total Liabilities and Equity | | | $ | 3,569 | | | | $ | 1,718 | | | | $ | 5,287 | | |
| | |
|
| | | |
|
| | | |
|
| | |
December 31, 2002 | | | | | | | | | | | | | | | | |
Condensed Statement of Operations Information | | | | | | | | | | | | | | | | |
Revenue | | | $ | 1,022 | | | | $ | 516 | | | | $ | 1,538 | | |
Gross Profit | | | $ | 413 | | | | $ | 166 | | | | $ | 579 | | |
Minority Interest | | | $ | (10 | ) | | | $ | — | | | | $ | (10 | ) | |
Net Income | | | $ | 45 | | | | $ | 20 | | | | $ | 65 | | |
Condensed Balance Sheet Information | | | | | | | | | | | | | | | | |
Assets: | | | | | | | | | | | | | | | | |
Current Assets | | | $ | 494 | | | | $ | 110 | | | | $ | 604 | | |
Property, Plant and Equipment | | | | 1,597 | | | | | 1,193 | | | | | 2,790 | | |
Goodwill | | | | 586 | | | | | 50 | | | | | 636 | | |
Other Noncurrent Assets | | | | 489 | | | | | 24 | | | | | 513 | | |
| | |
|
| | | |
|
| | | |
|
| | |
Total Assets | | | $ | 3,166 | | | | $ | 1,377 | | | | $ | 4,543 | | |
| | |
|
| | | |
|
| | | |
|
| | |
Liabilities: | | | | | | | | | | | | | | | | |
Current Liabilities | | | $ | 464 | | | | $ | 56 | | | | $ | 520 | | |
Debt* | | | | 868 | | | | | 641 | | | | | 1,509 | | |
Other Noncurrent Liabilities | | | | 183 | | | | | 72 | | | | | 255 | | |
Minority Interest | | | | 43 | | | | | — | | | | | 43 | | |
| | |
|
| | | |
|
| | | |
|
| | |
Total Liabilities | | | | 1,558 | | | | | 769 | | | | | 2,327 | | |
Equity | | | | 1,608 | | | | | 608 | | | | | 2,216 | | |
| | |
|
| | | |
|
| | | |
|
| | |
Total Liabilities and Equity | | | $ | 3,166 | | | | $ | 1,377 | | | | $ | 4,543 | | |
| | |
|
| | | |
|
| | | |
|
| | |
December 31, 2001 | | | | | | | | | | | | | | | | |
Condensed Statement of Operations Information | | | | | | | | | | | | | | | | |
Revenue | | | $ | 972 | | | | $ | 473 | | | | $ | 1,445 | | |
Gross Profit | | | $ | 416 | | | | $ | 165 | | | | $ | 581 | | |
Minority Interest | | | $ | (20 | ) | | | $ | — | | | | $ | (20 | ) | |
Net Income | | | $ | 180 | | | | $ | 91 | | | | $ | 271 | | |
*
Debt is non-recourse to PSEG, Energy Holdings and Global.
151
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 13. Purchase Business Combinations/Asset Acquisitions
Power
On December 6, 2002, Power purchased Wisvest Connecticut LLC, which owned the Bridgeport Harbor Station (BHS), the New Haven Harbor Station (NHHS) and the related assets and liabilities, from Wisvest Corporation (Wisvest), a subsidiary of Wisconsin Energy Corporation. The name of Wisvest Connecticut LLC was subsequently changed to PSEG Power Connecticut LLC (Power Connecticut).
The aggregate purchase price was approximately $271 million, which consisted of approximately $269 million of cash paid to Wisvest and approximately $2 million of direct acquisition costs which were paid to third parties.
During 2003, Power finalized the allocation of the purchase price. Power Connecticut’s results of operations were reflected in the Consolidated Statements of Operations beginning December 6, 2002.
| | As of December 6, 2002 | |
| |
| |
| | Initial
Amounts
Recorded | | Adjustments | | Final
Amounts
Recorded | |
| | | | (Millions) | | | |
Current Assets | | | $ | 26 | | | | $ | (1 | ) | | | $ | 25 | | |
Property, Plant and Equipment | | | | 237 | | | | | (2 | ) | | | | 235 | | |
Intangible Assets | | | | 44 | | | | | 3 | | | | | 47 | | |
| | |
|
| | | |
|
| | | |
|
| | |
Total Assets Acquired | | | | 307 | | | | | — | | | | | 307 | | |
Current Liabilities | | | | 16 | | | | | 1 | | | | | 17 | | |
Noncurrent Liabilities | | | | 19 | | | | | — | | | | | 19 | | |
| | |
|
| | | |
|
| | | |
|
| | |
Total Liabilities Assumed | | | | 35 | | | | | 1 | | | | | 36 | | |
| | |
|
| | | |
|
| | | |
|
| | |
Net Assets Acquired | | | $ | 272 | | | | $ | (1 | ) | | | $ | 271 | | |
| | |
|
| | | |
|
| | | |
|
| | |
Approximately $44 million of the intangible assets consisted of SO2 allowances, which can be sold on the open market or used to offset plant emissions. These allowances have an indefinite life.
Energy Holdings
In June 2002, Global completed a 35% acquisition of the 590 MW (electric) and 618 MW (thermal) coal-fired Skawina CHP Plant (Skawina), located in Poland, and subsequently purchased an additional equity interest of approximately 15%, increasing its ownership to approximately 50%. The aggregate purchase price of this ownership interest was $31 million and was allocated $18 million to Current Assets, $51 million to Property, Plant and Equipment, $14 million to Current Liabilities, $9 million to Noncurrent Liabilities and $15 million to Minority Interest. In accordance with the original purchase agreement, Global increased its equity interest in Skawina to approximately 63% in August 2003. Additionally, the agreement obligates Global to offer to purchase an additional 12% from Skawina’s employees in 2004, increasing Global’s potential ownership interest to approximately 75%. For additional information, see Note 17. Commitments and Contingent Liabilities.
Prior to the fourth quarter of 2002, GWF Energy LLC (GWF Energy) was accounted for in accordance with the equity method of accounting. Pursuant to the partnership agreement, a partner is required to have at least 75% interest in the partnership to have control. During the fourth quarter of 2002, Global increased its interest in GWF Energy to 76%, acquiring control pursuant to the partnership agreement. Due to this change, Global’s investment in GWF Energy was consolidated on the Consolidated Financial Statements as of December 31, 2002 and for the three months ended December 31, 2002 and for each quarterly period thereafter through September 30, 2003. Global’s investment in GWF Energy decreased to 74.9% during the fourth quarter of 2003 and accordingly, GWF Energy was deconsolidated and recorded under the equity method of accounting as of December
152
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
31, 2003. In February 2004, Harbinger repurchased a 14.9% ownership interest from Global for approximately $14 million. See Note 17. Commitments and Contingent Liabilities for additional information.
Note 14. Schedule of Consolidated Capital Stock and Other Securities
PSEG and PSE&G
The adoption of FIN 46 required PSEG and PSE&G to deconsolidate their capital trusts. In December 2003, PSE&G redeemed $155 million of its debt obligations which required the debtholder’s redemption of the mandatorily redeemable securities. See Note 3. Recent Accounting Standards and Note 15. Schedule of Consolidated Debt.
| | Outstanding
Shares
As of
December 31,
2003 | | Current
Redemption Price
Per Share | | As of
December 31, | |
|
2003 | | | 2002 |
| | | | | | | | (Millions) | |
PSEG Common Stock (no par value)(A) | | | | | | | | | | | | |
Authorized 500,000,000 shares; (outstanding as of December 31, 2002, 225,267,347 shares) | | | 236,133,442 | | | | | | $ | 3,509 | | | | | $ | 3,070 | | |
| | | | | | | | |
|
| | | | |
|
| | |
PSE&G Cumulative Preferred Stock(B) without Mandatory Redemption(C) $100 par value series | | | | | | | | | | | | | | | | | | |
4.08% | | | 146,221 | | | 103.00 | | | | $ | 15 | | | | | $ | 15 | | |
| | | | | | | | | | | | | | | | | | | |
4.18% | | | 116,958 | | | 103.00 | | | | | 12 | | | | | | 12 | | |
4.30% | | | 149,478 | | | 102.75 | | | | | 15 | | | | | | 15 | | |
5.05% | | | 104,002 | | | 103.00 | | | | | 10 | | | | | | 10 | | |
5.28% | | | 117,864 | | | 103.00 | | | | | 12 | | | | | | 12 | | |
6.92% | | | 160,711 | | | — | | | | | 16 | | | | | | 16 | | |
| |
|
| | | | | | |
|
| | | | |
|
| | |
Total Preferred Stock without Mandatory Redemption | | | 795,234 | | | | | | | $ | 80 | | | | | $ | 80 | | |
| |
|
| | | | | | |
|
| | | | |
|
| | |
(A)
In 1999, PSEG’s Board of Directors authorized the repurchase of up to 30 million shares of its common stock in the open market. As of December 31, 2001, PSEG repurchased approximately 26.5 million shares of common stock at a cost of approximately $997 million. No shares were repurchased in either 2003 or 2002. The repurchased shares have been held as treasury stock or used for other corporate purposes. In October 2003, PSEG issued approximately 8.8 million shares of its common stock for $356 million. In November 2002, PSEG issued 17.25 million shares of common stock for approximately $458 million, with net proceeds of $443 million. In addition, in 2002, PSEG began issuing new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) and the Employee Stock Purchase Plan (ESPP), rather than purchasing them on the open market. For the years ended December 31, 2003 and December 31, 2002, PSEG issued approximately 2.1 million and 2.2 million shares for approximately $85 million and $78 million, respectively, under these plans. Total authorized and unissued shares of common stock available for issuance through PSEG’s DRASPP, ESPP and various employee benefit plans amounted to 5,588,886 as of December 31, 2003.
(B)
As of December 31, 2003, there were an aggregate of 6,704,766 shares of $100 par value and 10,000,000 shares of $25 par value Cumulative Preferred Stock, which were authorized and unissued and which, upon issuance, may or may not provide for mandatory sinking fund redemption. If dividends upon any shares of Preferred Stock are in arrears for four consecutive quarters, holders receive voting rights for the election of a majority of PSE&G’s Board of Directors and continue until all accumulated and unpaid dividends thereon have been paid, whereupon all
(footnotes continued on next page)
153
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(footnotes continued from previous page)
such voting rights cease. There are no arrearages in cumulative preferred stock and hence currently not any voting rights for preferred shares. No preferred stock agreement contains any liquidation preferences in excess of par values or any “deemed” liquidation events.
(C)
As of December 31, 2003 and 2002, the annual dividend requirement and embedded dividend rate for PSE&G’s Preferred Stock without mandatory redemption was $3,987,867 and 5.03%, respectively for each year.
Fair Value of Preferred Securities
The estimated fair value of PSE&G’s Cumulative Preferred Stock were $70 million and $59 million as of December 31, 2003 and 2002, respectively. The estimated fair value was determined using market quotations.
Note 15.
Schedule of Consolidated Debt
Long-Term Debt
| | | | As of December 31, | |
| | | |
| |
| | Maturity | | 2003 | | 2002 | |
| | | | (Millions) | |
PSEG | | | | | | | | | | |
Senior Note—6.89% | | | 2005–2009 | | $ | 245 | | $ | 245 | |
Debt Supporting Trust Preferred Securities(A) | | | 2007–2047 | | | 1,201 | | | 1,201 | |
Other | | | | | | 16 | | | 3 | |
| | | | |
|
| |
|
| |
Total Long-Term Debt of PSEG (Parent) | | | | | $ | 1,462 | | $ | 1,449 | |
| | | | |
|
| |
|
| |
PSE&G | | | | | | | | | | |
Debt Supporting Trust Preferred Securities(A) | | | 2044–2046 | | $ | — | | $ | 160 | |
First and Refunding Mortgage Bonds: | | | | | | | | | | |
5.70%(F) | | | 2003 | | | — | | | 64 | |
6.875%(C) | | | 2003 | | | — | | | 150 | |
8.875%(D) | | | 2003 | | | — | | | 150 | |
5.55%(F) | | | 2003 | | | — | | | 145 | |
6.50% | | | 2004 | | | 286 | | | 286 | |
9.125% | | | 2005 | | | 125 | | | 125 | |
6.75% | | | 2006 | | | 147 | | | 147 | |
6.25% | | | 2007 | | | 113 | | | 113 | |
7.375% | | | 2014 | | | 159 | | | 159 | |
6.75% | | | 2016 | | | 171 | | | 171 | |
6.45% | | | 2019 | | | 5 | | | 5 | |
9.25% | | | 2021 | | | 134 | | | 134 | |
6.38% | | | 2023 | | | 157 | | | 157 | |
7.00% | | | 2024 | | | 254 | | | 254 | |
5.20% | | | 2025 | | | 23 | | | 23 | |
1.10% Auction Rate(F) | | | 2028 | | | 64 | | | — | |
6.55% | | | 2029 | | | 93 | | | 93 | |
6.20% | | | 2030 | | | 88 | | | 88 | |
6.25% | | | 2031 | | | 104 | | | 104 | |
5.45% | | | 2032 | | | 50 | | | 50 | |
6.40% | | | 2032 | | | 100 | | | 100 | |
1.14% Auction Rate(F) | | | 2033 | | | 50 | | | — | |
1.10% Auction Rate(F) | | | 2033 | | | 50 | | | — | |
1.15% Auction Rate(F) | | | 2033 | | | 45 | | | — | |
8.00% | | | 2037 | | | 7 | | | 7 | |
(table continued on next page)
154
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(table continued from previous page)
| | | | As of December 31, | |
| | | |
| |
| | Maturity | | 2003 | | 2002 | |
| | | | (Millions) | |
5.00% | | | 2037 | | | 8 | | | 8 | |
Medium-Term Notes: | | | | | | | | | | |
4.00%(E) | | | 2008 | | | 250 | | | — | |
8.16% | | | 2009 | | | 16 | | | 16 | |
8.10% | | | 2009 | | | 44 | | | 44 | |
5.125% | | | 2012 | | | 300 | | | 300 | |
5.00%(C) | | | 2013 | | | 150 | | | — | |
5.375%(D) | | | 2013 | | | 300 | | | — | |
7.04% | | | 2020 | | | 9 | | | 9 | |
7.18% | | | 2023 | | | 5 | | | 5 | |
7.15% | | | 2023 | | | 34 | | | 34 | |
| | | | |
|
| |
|
| |
Total First and Refunding Mortgage Bonds | | | | | | 3,341 | | | 2,941 | |
Amounts Due Within One Year(B) | | | | | | (286 | ) | | (300 | ) |
Net Unamortized Discount | | | | | | (11 | ) | | (14 | ) |
| | | | |
|
| |
|
| |
Total Long-Term Debt of PSE&G (Parent) | | | | | $ | 3,044 | | $ | 2,787 | |
| | | | |
|
| |
|
| |
Transition Funding (PSE&G) | | | | | | | | | | |
Securitization Bonds: | | | | | | | | | | |
5.74% | | | 2007 | | $ | 171 | | $ | 300 | |
5.98% | | | 2008 | | | 183 | | | 183 | |
LIBOR plus 0.30% | | | 2011 | | | 496 | | | 496 | |
6.45% | | | 2013 | | | 328 | | | 328 | |
6.61% | | | 2015 | | | 454 | | | 454 | |
6.75% | | | 2016 | | | 220 | | | 220 | |
6.89% | | | 2017 | | | 370 | | | 370 | |
| | | | |
|
| |
|
| |
Principal Amount Outstanding | | | | | | 2,222 | | | 2,351 | |
Amounts Due Within One Year(B) | | | | | | (137 | ) | | (129 | ) |
| | | | |
|
| |
|
| |
Total Securitization Debt of Transition Funding | | | | | $ | 2,085 | | $ | 2,222 | |
| | | | |
|
| |
|
| |
Total Long-Term Debt of PSE&G | | | | | $ | 5,129 | | $ | 5,009 | |
| | | | |
|
| |
|
| |
Power | | | | | | | | | | |
Senior Notes: | | | | | | | | | | |
6.875% | | | 2006 | | $ | 500 | | $ | 500 | |
7.75% | | | 2011 | | | 800 | | | 800 | |
6.95% | | | 2012 | | | 600 | | | 600 | |
5.50%(G) | | | 2015 | | | 300 | | | — | |
8.625% | | | 2031 | | | 500 | | | 500 | |
| | | | |
|
| |
|
| |
Total Senior Notes | | | | | $ | 2,700 | | $ | 2,400 | |
Pollution Control Notes: | | | | | | | | | | |
5.00% | | | 2012 | | $ | 66 | | $ | 66 | |
5.50% | | | 2020 | | | 14 | | | 14 | |
5.85% | | | 2027 | | | 19 | | | 19 | |
5.75% | | | 2031 | | | 25 | | | 25 | |
| | | | |
|
| |
|
| |
Total Pollution Control Notes | | | | | $ | 124 | | $ | 124 | |
Net Unamortized Discount | | | | | | (8 | ) | | (8 | ) |
| | | | |
|
| |
|
| |
Total Long-Term Debt of Power (Parent) | | | | | $ | 2,816 | | $ | 2,516 | |
Non-Recourse Debt: | | | | | | | | | | |
Variable (3.00% to 5.00%) | | | 2005 | | $ | 800 | | $ | 800 | |
| | | | |
|
| |
|
| |
Total Long-Term Debt of Power | | | | | $ | 3,616 | | $ | 3,316 | |
| | | | |
|
| |
|
| |
(table continued on next page)
155
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(table continued from previous page)
| | | | As of December 31, | |
| | | |
| |
| | Maturity | | 2003 | | 2002 | |
| | | | (Millions) | |
Energy Holdings (Parent) | | | | | | | | | | |
Senior Notes: | | | | | | | | | | |
9.125%(I) | | | 2004 | | $ | 267 | | $ | 279 | |
7.75%(H) | | | 2007 | | | 350 | | | — | |
8.625% | | | 2008 | | | 507 | | | 507 | |
10.00% | | | 2009 | | | 400 | | | 400 | |
8.50% | | | 2011 | | | 544 | | | 544 | |
| | | | |
|
| |
|
| |
Principal Amount Outstanding | | | | | | 2,068 | | | 1,730 | |
Amounts Due Within One Year(B) | | | | | | (267 | ) | | — | |
Net Unamortized Discount and Senior Note Rate Swap | | | | | | (1 | ) | | (5 | ) |
| | | | |
|
| |
|
| |
Total Long-Term Debt of Energy Holdings (Parent) | | | | | $ | 1,800 | | $ | 1,725 | |
| | | | |
|
| |
|
| |
Global (Energy Holdings) | | | | | | | | | | |
Non-recourse Debt: | | | | | | | | | | |
Skawina–5.60% | | | 2004–2005 | | $ | 3 | | $ | — | |
Salalah–6.27% | | | 2004–2018 | | | 201 | | | 131 | |
Elcho (Chorzow)–9.550% — 13.225% | | | 2004–2019 | | | 285 | | | 237 | |
SAESA–3.807% | | | 2004–2023 | | | 167 | | | 211 | |
Electroandes–4.090%–6.438% | | | 2005–2016 | | | 100 | | | — | |
Chilquinta–5.58%–6.62% | | | 2008–2011 | | | 161 | | | 161 | |
| | | | |
|
| |
|
| |
Principal Amount Outstanding | | | | | | 917 | | | 740 | |
Amounts Due Within One Year(B) | | | | | | (33 | ) | | (47 | ) |
| | | | |
|
| |
|
| |
Total Long-Term Debt of Global | | | | | $ | 884 | | $ | 693 | |
| | | | |
|
| |
|
| |
Resources (Energy Holdings) | | | | | | | | | | |
8.60%–9.30%—Non-Recourse Bank Loan | | | 2004–2020 | | $ | 32 | | $ | 22 | |
Amounts Due Within One Year(B) | | | | | | (1 | ) | | (1 | ) |
| | | | |
|
| |
|
| |
Total Long-Term Debt of Resources | | | | | $ | 31 | | $ | 21 | |
| | | | |
|
| |
|
| |
EGDC (Energy Holdings) | | | | | | | | | | |
8.27%—Non-recourse Mortgage | | | 2004–2013 | | $ | 25 | | $ | 26 | |
Amounts Due Within One Year(B) | | | | | | (2 | ) | | (1 | ) |
| | | | |
|
| |
|
| |
Total Long-Term Debt of EGDC | | | | | $ | 23 | | $ | 25 | |
| | | | |
|
| |
|
| |
PSEG Capital Corporation (Energy Holdings) | | | | | | | | | | |
6.25% Medium-Term Notes | | | 2003 | | $ | — | | $ | 252 | |
| | | | |
|
| |
|
| |
Principal Amount Outstanding | | | | | | — | | | 252 | |
Amounts Due Within One Year(B) | | | | | | — | | | (252 | ) |
| | | | |
|
| |
|
| |
Total Long-Term Debt of PSEG Capital | | | | | $ | — | | $ | — | |
| | | | |
|
| |
|
| |
Total Long-Term Debt of Energy Holdings | | | | | $ | 2,738 | | $ | 2,464 | |
| | | | |
|
| |
|
| |
Total PSEG Consolidated Long-Term Debt | | | | | $ | 12,945 | | $ | 12,238 | |
| | | | |
|
| |
|
| |
(A)
The adoption of FIN 46 required PSEG and PSE&G to deconsolidate their capital trusts. In December 2003, PSE&G paid the trusts $155 million and offset its $5 million debt to the trusts against PSE&G’s remaining investment in conjunction with the redemption of the mandatorily redeemable securities. See Note 3. Recent Accounting Standards and Note 14. Schedule of Consolidated Capital Stock and Other Securities.
In December 2003, PSE&G Capital, L.P., a limited partnership of which PSE&G is sole general partner, redeemed all of its outstanding 8% Cumulative Monthly Income Preferred Securities, Series B at a price of $25.00 per preferred security. In December 2003, PSE&G Capital Trust II, a
(footnotes continued on next page)
156
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(footnotes continued from previous page)
statutory trust of which PSE&G is sole depositor, redeemed all of its outstanding 8.125% Cumulative Quarterly Income Preferred Securities, Series B at a price of $25.00 per preferred security.
As of December 31, 2003 and 2002, the annual dividend requirement of PSEG’s Trust Preferred Securities (Guaranteed Preferred Beneficial Interest in PSEG’s Subordinated Debentures) including those issued in connection with the Participating Units and their embedded costs was $103,563,284 and 8.98%. As of December 31, 2003 and 2002, the annual dividend requirement and embedded cost of the Monthly Income Preferred Securities (Guaranteed Preferred Beneficial Interest in PSE&G’s Subordinated Debentures) was $4,948,454 and 8.29%. As of December 31, 2003 and 2002, the annual dividend requirement of the Quarterly Income Preferred Securities (Guaranteed Preferred Beneficial Interest in PSE&G’s Subordinated Debentures) and their embedded costs were $7,957,475 and 8.41%.
Enterprise Capital Trust I, Enterprise Capital Trust II, Enterprise Capital Trust III, Enterprise Capital Trust IV and PSEG Funding Trust II were formed and are controlled by PSEG for the purpose of issuing Quarterly Trust Preferred Securities (Quarterly Guaranteed Preferred Beneficial Interest in PSEG’s Subordinated Debentures). The proceeds were loaned to PSEG and are evidenced by Deferrable Interest Subordinated Debentures. If and for as long as payments on the Deferrable Interest Subordinated Debentures have been deferred, or PSEG had defaulted on the indentures related thereto or its guarantees thereof, PSEG may not pay any dividends on its common and preferred stock. The Subordinated Debentures support the Preferred Securities issued by the trusts.
In September 2002, PSEG Funding Trust I issued 9.2 million Participating Units with a stated amount of $50 per unit. Each unit consists of a 6.25% trust preferred security due 2007 having a liquidation value of $50, and a stock purchase contract obligating the purchasers to purchase shares of PSEG Common Stock in an amount equal to $50 on November 16, 2005. In exchange for the obligations under the purchase contract, the purchasers will receive quarterly contract adjustment payments at the annual rate of 4.00% through the purchase date. The number of new shares to be issued on November 16, 2005 will depend upon the average closing price per share of PSEG Common Stock for the 20 consecutive trading days ending the third trading day immediately preceding November 16, 2005. Based on the formula described in the purchase contract, at that time PSEG will issue between 11,429,139 and 13,714,967 shares of its common stock. The net proceeds from the sale of the Participating Units was $446 million. In connection with the issuance of the Participating Units, PSEG recorded a $54 million reduction to equity associated with the stock purchase contracts. For additional information, see Note 22. Stock Options and Employee Stock Purchase Plan.
(B)
The aggregate principal amounts of mandatory requirements for sinking funds and maturities for each of the five years following December 31, 2003 are as follows:
| | | | PSE&G | | | | Energy Holdings | | | |
| | | |
| | | |
| | | |
Year | | PSEG | | PSE&G | | Transition
Funding | | Power | | Energy
Holdings | | Global | | Resources | | EGDC | | Total | |
| | | | | | | | | | (Millions) | | | | | | | | | |
2004 | | $ | — | | $ | 286 | | $ | — | | $ | — | | $ | 267 | | $ | 33 | | $ | 1 | | $ | 2 | | $ | 589 | |
2005 | | | 49 | | | 125 | | | — | | | 800 | | | — | | | 46 | | | 2 | | | 2 | | | 1,024 | |
2006 | | | 49 | | | 147 | | | — | | | 500 | | | — | | | 45 | | | 2 | | | 2 | | | 745 | |
2007 | | | 509 | | | 113 | | | 171 | | | — | | | 350 | | | 37 | | | 1 | | | 2 | | | 1,183 | |
2008 | | | 49 | | | 250 | | | 183 | | | — | | | 507 | | | 104 | | | 1 | | | 2 | | | 1,096 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
| | $ | 656 | | $ | 921 | | $ | 354 | | $ | 1,300 | | $ | 1,124 | | $ | 265 | | $ | 7 | | $ | 10 | | $ | 4,637 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
(C)
In January 2003, PSE&G issued $150 million of 5.00% Medium-Term Notes due 2013. The proceeds of this issuance were used to repay $150 million of 6.875% Series MM Mortgage Bonds which matured in January 2003.
157
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(D)
In September 2003, PSE&G issued $300 million of 5.375% Medium-Term Notes due 2013. The proceeds of this issuance were used to refinance the previously matured $150 million of Series DD Mortgage Bonds, as well as to reduce short-term debt.
(E)
In November 2003, PSE&G issued $250 million of 4.000% Medium-Term Notes due 2008. The proceeds of this issuance were used to retire $60 million and $95 million of Cumulative Monthly Income Preferred Securities and Cumulative Quarterly Income Preferred Securities, respectively, in December 2003 and to reduce short-term debt.
(F)
In December 2003, PSE&G redeemed $64 million of its 5.700% First and Refunding Mortgage Bonds, Pollution Control Series L due 2028 (Series L Bonds) and $145 million of its 5.550% First and Refunding Mortgage Bonds, Pollution Control Series N due 2033 (Series N Bonds). Each of these series of mortgage bonds serviced and secured like principal amounts of pollution control revenue refunding bonds of The Pollution Control Financing Authority of Salem County, New Jersey (Salem Authority). The Series L Bonds and the Series N Bonds were refinanced through the issuance of new series of mortgage bonds that are multi-mode and that were initially issued in a floating rate 35-day auction mode. The Series L Bonds were refinanced by the issuance of $64 million of First and Refunding Mortgage Bonds, Pollution Control Series Y due 2028, with an initial auction rate of 1.100%. The Series N Bonds were refinanced by the issuance of three separate series of mortgage bonds: $50 million First and Refunding Mortgage Bonds, Pollution Control Series Z due 2033 with an initial auction rate of 1.140%, $50 million First and Refunding Mortgage Bonds, Pollution Control Series AA due 2033 with an initial auction rate of 1.100%, and a $45.2 million First and Refunding Mortgage Bonds, Pollution Control Series AB due 2033 with an initial auction rate of 1.150%. Similarly, these new mortgage bonds service and secure like principal amounts of pollution control revenue refunding bonds of the Salem Authority.
(G)
In December 2003, Power issued $300 million of 5.500% Senior Notes due 2015. The proceeds of this issuance were used to repay intercompany debt and for general corporate purposes.
(H)
In April 2003, Energy Holdings, in a private placement, issued $350 million of its 7.75% Senior Notes due in 2007. The proceeds were used in part to repay PSEG Capital Corporation’s (PSEG Capital) remaining $252 million of 6.25% Medium-Term Notes that matured in May 2003. The remaining proceeds were used for general corporate purposes. In July 2003, Energy Holdings completed an exchange of these securities for registered securities.
(I)
In September 2003, Energy Holdings repurchased approximately $12 million of its outstanding Senior Notes that matured in February 2004, reducing that maturity to $267 million as of December 31, 2003. In February 2004, Energy Holdings redeemed the remaining $267 million of these Senior Notes at maturity.
158
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Short-Term Liquidity
PSEG, PSE&G, Power and Energy Holdings
As of December 31, 2003, PSEG and its principal subsidiaries had an aggregate of approximately $1.9 billion of committed credit facilities. Each facility is restricted to availability and use to the specific companies as listed below.
Company | | Expiration Date | | Total
Facility | | Primary Purpose | | Usage as of
12/31/2003 | | Available
Liquidity as of
12/31/2003 | |
| | | | | (Millions) | | | | | | | | | | | | | |
PSEG: | | | | | | | | | | | | | | | | | | | |
364-day Credit Facility | | | March 2004 | | $ | 350 | | CP Support | | | $ | 299 | | | | $ | 51 | | |
5-year Credit Facility | | | March 2005 | | $ | 280 | | CP Support | | | $ | — | | | | $ | 280 | | |
3-year Credit Facility | | | December 2005 | | $ | 350 | | CP Support/
Funding/
Letters of Credit | | | $ | 10 | (C) | | | $ | 340 | | |
Uncommitted Bilateral Agreement | | | N/A | | | N/A | | Funding | | | $ | — | | | | | N/A | | |
PSE&G: | | | | | | | | | | | | | | | | | | | |
364-day Credit Facility | | | June 2004 | | $ | 200 | | CP Support | | | $ | — | | | | $ | 200 | | |
3-year Credit Facility | | | June 2005 | | $ | 200 | | CP Support | | | $ | — | | | | $ | 200 | | |
Uncommitted Bilateral Agreement | | | N/A | | | N/A | | Funding | | | $ | — | | | | | N/A | | |
PSEG and Power: | | | | | | | | | | | | | | | | | | | |
364-day Credit Facility(A) | | | March 2004 | | $ | 250 | | CP Support/
Funding | | | $ | — | | | | $ | 250 | | |
Power: | | | | | | | | | | | | | | | | | | | |
3-year Credit Facility | | | August 2005 | | $ | 25 | | Funding/
Letters of Credit | | | $ | 19 | (C) | | | $ | 6 | | |
Energy Holdings: | | | | | | | | | | | | | | | | | | | |
3-year Credit Facility (B) | | | October 2006 | | $ | 200 | | Funding/
Letters of Credit | | | $ | 56 | (C) | | | $ | 144 | | |
| (A) | PSEG/Power joint and several co-borrower facility |
| (B) | The facility could be reduced to a total of $100 million on June 30, 2004 if available liquidity during the period, after repayment of the Energy Holdings’ Senior Notes due in February 2004 to June 30, 2004 does not reach $100 million for 15 days. |
| (C) | These amounts relate to letters of credit outstanding. |
Energy Holdings
As of December 31, 2003, in addition to amounts outstanding under Energy Holdings’ credit facilities shown in the above table, subsidiaries of Global had $2 million of short-term non-recourse financing at the project level. As of December 31, 2003, Energy Holdings had loaned $300 million of excess cash to PSEG. For information regarding affiliate borrowings, see Note 26. Related-Party Transactions.
Fair Value of Debt
The estimated fair values were determined using the market quotations or values of instruments with similar terms, credit ratings, remaining maturities and redemptions as of December 31, 2003 and December 31, 2002, respectively.
| | December 31, 2003 | | December 31, 2002 | |
| |
| |
| |
| | Carrying
Amount | | Fair
Value | | Carrying
Amount | | Fair
Value | |
| | (Millions) | |
Long-Term Debt: | | | | | | | | | | | | | |
PSEG | | $ | 1,462 | | $ | 1,586 | | $ | 1,449 | | $ | 1,381 | |
Energy Holdings | | | 3,041 | | | 3,230 | | | 2,765 | | | 2,597 | |
PSE&G | | | 3,330 | | | 3,601 | | | 3,087 | | | 3,375 | |
Transition Funding (PSE&G) | | | 2,222 | | | 2,474 | | | 2,351 | | | 2,543 | |
Power | | | 3,616 | | | 4,034 | | | 3,316 | | | 3,372 | |
| |
|
| |
|
| |
|
| |
|
| |
| | $ | 13,671 | | $ | 14,925 | | $ | 12,968 | | $ | 13,268 | |
| |
|
| |
|
| |
|
| |
|
| |
Because their maturities are less than one year, fair values approximate carrying amounts for cash and cash equivalents, short-term debt and accounts payable. For additional information related to interest rate derivatives, see Note 16. Risk Management.
159
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 16. Risk Management
PSEG, PSE&G, Power and Energy Holdings
The operations of PSEG, PSE&G, Power and Energy Holdings are exposed to market risks from changes in commodity prices, foreign currency exchange rates, interest rates and equity prices that could affect their results of operations and financial conditions. PSEG, PSE&G, Power and Energy Holdings manage exposure to these market risks through their regular operating and financing activities and, when deemed appropriate, hedge these risks through the use of derivative financial instruments. PSEG, PSE&G, Power and Energy Holdings use the term “hedge” to mean a strategy designed to manage risks of volatility in prices or rate movements on certain assets, liabilities or anticipated transactions and by creating a relationship in which gains or losses on derivative instruments are expected to counterbalance the losses or gains on the assets, liabilities or anticipated transactions exposed to such market risks. Each of PSEG, PSE&G, Power and Energy Holdings use derivative instruments as risk management tools consistent with their respective business plans and prudent business practices.
Derivative Instruments and Hedging Activities
Energy Trading Contracts
Power
Power actively trades energy and energy-related products, including electricity, natural gas, electric capacity, fixed transmission rights (FTRs), coal and emission allowances in the spot, forward and futures markets, primarily in the PJM Interconnection LLC (PJM), but also in the surrounding region, which extends from Maine to the Carolinas and the Atlantic Coast to Indiana and natural gas in the producing region.
Power maintains a strategy of entering into trading positions to optimize the value of its portfolio of generation assets, gas supply contracts and its electric and gas supply obligations. Power engages in physical and financial transactions in the electricity wholesale markets and executes an overall risk management strategy to mitigate the effects of adverse movements in the fuel and electricity markets. These contracts also involve financial transactions including swaps, options and futures.
Power marks its energy trading contracts to market in accordance with SFAS 133 with changes in fair value charged to the Consolidated Statement of Operations. Wherever possible, fair values for these contracts are obtained from quoted market sources. For contracts where no quoted market exists, modeling techniques are employed using assumptions reflective of current market rates, yield curves and forward prices as applicable to interpolate certain prices. The effect of using such modeling techniques is not material to Power’s financial results.
Power routinely enters into exchange-traded futures and options transactions for electricity and natural gas as part of its operations. Generally, exchange-traded futures contracts require a deposit of margin cash, the amount of which is subject to change based on market movement and in accordance with exchange rules. The aggregate amount of Power’s margin deposits as of December 31, 2003 and 2002 was approximately $36 million and $13 million, respectively.
Commodity Contracts
Power
The availability and price of energy commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market conditions and other events. Power manages its risk of fluctuations of energy price and availability through derivative instruments, such as forward purchase or sale contracts, swaps, options, futures and FTRs.
160
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cash Flow Hedges
Power uses forward sale and purchase contracts, swaps and FTR contracts to hedge forecasted energy sales from its generation stations and to hedge related load obligations. Power also enters into swaps, options and futures transactions to hedge the price of fuel to meet its fuel purchase requirements for generation. These derivative transactions are designated and effective as cash flow hedges under SFAS 133. As of December 31, 2003 and 2002, the fair values of these hedges were $(37) million and $5 million, respectively. During the next 12 months, $17 million of unrealized losses (net of taxes) on these commodity derivatives in Accumulated OCI is expected to be reclassified to earnings. As defined in SFAS 133, hedge ineffectiveness associated with these hedges was insignificant. The maximum term of these cash flow hedges will expire in 2008.
Effective with the transfer of PSE&G’s gas contracts to Power on May 1, 2002, Power acquired all of the gas-related derivatives entered into by PSE&G. The derivatives used to hedge the forecasted purchase and sale of natural gas are designated and effective as cash flow hedges. Gains or losses from the derivatives entered into to hedge residential customer requirements are deferred and recovered from PSE&G’s customers and therefore do not affect earnings. Unrealized gains or losses on the derivatives entered to hedge commercial and industrial customer requirements are recorded to OCI. As of December 31, 2003, $4 million of losses were recorded to OCI related to gas hedges for commercial and industrial customers, all of which will be reclassed to earnings over the next twelve months. Hedge ineffectiveness associated with these hedges was insignificant. As of December 31, 2003 and 2002, the fair values of hedge instruments associated with hedging residential customer requirements were $20 million and $1 million, respectively. These hedges will mature through 2005.
Other Derivatives
Power also enters into certain other contracts which are derivatives, but do not qualify for hedge accounting under SFAS 133. Most of these contracts are used for fuel purchases for generation requirements. Therefore, the changes in fair market value of these derivative contracts are recorded in Energy Costs on the Consolidated Statements of Operations. The fair value of these instruments as of December 31, 2003 and 2002 was $7 million and $9 million.
Interest Rates
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings are subject to the risk of fluctuating interest rates in the normal course of business. PSEG’s policy is to manage interest rate risk through the use of fixed and floating rate debt and interest rate derivatives.
Fair Value Hedges
Energy Holdings
In April 2003, Energy Holdings, in a private placement, issued $350 million of 7.75% Senior Notes due in 2007. Energy Holdings used interest rate swaps to convert a portion of this fixed-rate debt into variable-rate debt. The interest rate swaps are designated and effective as fair value hedges. The fair value changes of these interest rate swaps are fully offset by the fair value changes in the underlying debt. As of December 31, 2003, the fair value of these hedges was $(1) million. There was no ineffectiveness related to these hedges.
161
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cash Flow Hedges
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings use interest rate swaps and other interest rate derivatives to manage their exposures to the variability of cash flows, primarily related to variable-rate debt instruments. The interest rate derivatives used are designated and effective as cash flow hedges.
The fair value changes of these derivatives are initially recorded in OCI. As of December 31, 2003, the fair value of these cash flow hedges was $(186) million, including $(16) million, $(51) million, $(7) million and $(112) million at PSEG, PSE&G, Power and Energy Holdings, respectively. The $(51) million at PSE&G is deferred and is expected to be recovered from PSE&G’s customers. As of December 31, 2002, the fair value of these cash flow hedges was $(223) million, including $(21) million, $(66) million, $(9) million and $(127) million at PSEG, PSE&G, Power and Energy Holdings, respectively. During the next 12 months, $31 million of unrealized loss (net of taxes) on interest rate derivatives accumulated in OCI is expected to be reclassified to earnings, including $4 million, $3 million and $24 million at PSEG, Power and Energy Holdings, respectively. Hedge ineffectiveness associated with these hedges was immaterial.
Other Derivatives
Energy Holdings
Foreign subsidiaries and affiliates of Energy Holdings entered into interest rate forward contracts, which effectively converted Energy Holdings’ variable rate debt to fixed rate. Changes in the fair value of these derivative instruments are recorded directly to interest expense. The fair value of these instruments as of December 31, 2003 was immaterial.
Foreign Currencies
Energy Holdings
Global is exposed to foreign currency risk and other foreign operations risk that arise from investments in foreign subsidiaries and affiliates. A key component of this risk is that some of its foreign subsidiaries and affiliates have functional currencies other than the consolidated reporting currency, the U.S. Dollar. Additionally, certain of Global’s foreign subsidiaries and affiliates have entered into monetary obligations and maintain receipts/receivables in U.S. Dollars or currencies other than their own functional currencies. Global, a U.S. Dollar functional currency entity, is primarily exposed to changes in the Brazilian Real, the Euro, the Polish Zloty, the Peruvian Nuevo Sol and the Chilean Peso. With respect to the foreign currency risk associated with the Brazilian Real, there has already been significant devaluation since the initial acquisition of these investments, which has resulted in reduced U.S. Dollar earnings and cash flows relative to initial projections. These subsidiaries and affiliates have attempted to limit potential foreign exchange exposure by entering into revenue contracts that adjust for changes in foreign exchange rates. Global also uses foreign currency forward, swap and option agreements to manage risk related to certain foreign currency fluctuations.
As of December 31, 2003, net cumulative foreign currency devaluations have reduced the total amount of Energy Holdings’ Member’s Equity by $193 million, of which $228 million was caused by the devaluation of the Brazilian Real. As of December 31, 2002, these devaluations reduced Energy Holdings’ Member’s Equity by $358 million, of which $248 million and $105 million were caused by the devaluation of the Brazilian Real and the Chilean Peso, respectively.
162
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Equity Securities
Energy Holdings
For the year ended December 31, 2003, Resources recognized a $11 million (pre-tax) loss from other than temporary impairments of non-publicly traded equity securities, which are held within its investments in certain leveraged buyout funds. For the year ended December 31, 2003, Resources has recognized a $5 million gain on the publicly traded equity securities within those funds. These gains and losses are included in Operating Revenues in the Consolidated Statements of Operations. As of December 31, 2003, Resources had investments in leveraged buyout funds of approximately $75 million, of which $26 million was comprised of public securities with available market prices and $49 million was comprised of privately-held interests in certain companies. As of December 31, 2002, Resources had investments in leveraged buyout funds of approximately $93 million, of which $24 million was comprised of public securities with available market prices and $69 million was comprised of privately held interests in certain companies.
Note 17. Commitments and Contingent Liabilities
Nuclear Insurance Coverages and Assessments
Power
Power is a member of an industry mutual insurance company, Nuclear Electric Insurance Limited (NEIL), which provides the primary property and decontamination liability insurance at Salem Nuclear Generating Station (Salem), Hope Creek Generating Station (Hope Creek) and Peach Bottom Atomic Power Station (Peach Bottom). NEIL also provides excess property insurance through its decontamination liability, decommissioning liability and excess property policy and replacement power coverage through its accidental outage policy. NEIL policies may make retrospective premium assessments in case of adverse loss experience. Power’s maximum potential liabilities under these assessments are included in the table and notes below. 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 Nuclear Regulatory Commission (NRC) suspends or revokes the operating license for any unit on that site, issues a shutdown order with respect to such unit or issues a confirmatory order keeping such unit down.
The American Nuclear Insurers (ANI) and NEIL policies both include coverage for claims arising out of acts of terrorism. Both ANI and NEIL make a distinction between certified and non-certified acts of terrorism, as defined under Terrorism Risk Insurance Act (TRIA) (Sec. 102 (1) and Sec. 102 (5)), and thus their policies respond accordingly. For non-certified acts of terrorism, ANI policies are subject to an industry aggregate limit of $300 million, subject to one reinstatement, provided the reinstatement does not exceed the balance in the Industry Credit Rating Plan (ICRP) Reserve Fund. Similarly, NEIL policies are subject to an industry aggregate limit of $3.2 billion plus any amounts available through reinsurance or indemnity for non-certified acts of terrorism. For certified acts, Power’s nuclear liability ANI and nuclear property NEIL policies will respond in the same manner as for that resulting from other covered events.
The Price-Anderson Act sets the “limit of liability” for claims that could arise from an incident involving any licensed nuclear facility in the U.S. 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 $10.9 billion. All utilities owning a nuclear reactor, including Power, 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 $101 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
163
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
additional compensation to the injured parties. Congress could impose further revenue raising measures on the nuclear industry to pay claims. Power’s maximum aggregate assessment per incident is $317 million (based on Power’s ownership interests in Hope Creek, Peach Bottom and Salem) and its maximum aggregate annual assessment per incident is $32 million. This does not include the $11 million that could be assessed under the nuclear worker policies. Further, a decision by the U.S. Supreme Court, not involving Power, has held that the Price-Anderson Act did not preclude awards based on state law claims for punitive damages.
Power’s insurance coverages and maximum retrospective assessments for its nuclear operations are as follows:
| | | Total Site
Coverage | | | Retrospective
Assessments |
| | | (Millions) |
Type and Source of Coverages | | | | | | | | | |
Public and Nuclear Worker Liability (Primary Layer): | | | | | | | | | |
ANI | | $ | 300.0 | (A) | | | $ | 10.7 | |
Nuclear Liability (Excess Layer): | | | | | | | | | |
Price-Anderson Act | | | 10,562.0 | (B) | | | | 316.7 | |
Nuclear Liability Total | | $ | 10,862.0 | (C) | | | $ | 327.4 | |
Property Damage (Primary Layer): | | | | | | | | | |
NEIL | | | | | | | | | |
Primary (Salem/Hope Creek/Peach Bottom) | | $ | 500.0 | | | | $ | 19.7 | |
Property Damage (Excess Layers): | | | | | | | | | |
NEIL II (Salem/Hope Creek/Peach Bottom) | | | 600.0 | | | | | 8.0 | |
NEIL Blanket Excess (Salem/Hope Creek/Peach Bottom) | | | 1,000.0 | (D) | | | | 2.9 | |
Property Damage Total (Per Site) | | $ | 2,100.0 | | | | $ | 30.6 | |
Accidental Outage: | | | | | | | | | |
NEIL I (Peach Bottom) | | $ | 245.0 | (E) | | | $ | 9.3 | |
NEIL I (Salem). | | | 281.4 | (E) | | | | 11.1 | |
NEIL I (Hope Creek). | | | 490.0 | (E) | | | | 9.4 | |
Replacement Power Total | | $ | 1,016.4 | | | | $ | 29.8 | |
______________
| (A) | The primary limit for Public Liability is a per site aggregate limit with no potential for assessment. The Nuclear Worker Liability represents the potential liability from workers claiming exposure to the hazard of nuclear radiation. This coverage is subject to an industry aggregate limit, includes annual automatic reinstatement if the ICRP Reserve Fund exceeds $600 million, and has an assessment potential under former canceled policies. |
| (B) | Retrospective premium program under the Price-Anderson liability provisions of the Atomic Energy Act of 1954, as amended. Power is subject to retrospective assessment with respect to loss from an incident at any licensed nuclear reactor in the U.S. This retrospective assessment can be adjusted for inflation every five years. The last adjustment was effective as of August 20, 2003. This retrospective program is in excess over the Public and Nuclear Worker Liability primary layers. |
| (C) | Limit of liability under the Price-Anderson Act for each nuclear incident. |
| (D) | For property limits in excess of $1.1 billion, Power participates in a Blanket Limit policy where the $1.0 billion limit is shared by Power with Amergen Energy Company, LLC and Exelon Generation Company, LLC among the Braidwood, Byron, Clinton, Dresden, La Salle, Limerick, Oyster Creek, Quad Cities, TMI-1 facilities owned by Amergen and Exelon and the Peach Bottom, Salem and Hope Creek facilities. This limit is not subject to reinstatement in the event of a loss. Participation in this program materially reduces Power’s premium and the associated potential assessment. |
(footnotes continued on next page)
164
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(footnotes continued from previous page)
| (E) | Peach Bottom has an aggregate indemnity limit based on a weekly indemnity of $2.3 million for 52 weeks followed by 80% of the weekly indemnity for 68 weeks. Salem has an aggregate indemnity limit based on a weekly indemnity of $2.5 million for 52 weeks followed by 80% of the weekly indemnity for 75 weeks. Hope Creek has an aggregate indemnity limit based on a weekly indemnity of $4.5 million for 52 weeks followed by 80% of the weekly indemnity for 71 weeks. |
Old Dominion Electric Cooperative (ODEC)
PSE&G and Power
In 1995, PSE&G entered into a ten-year wholesale power contract with ODEC. The contract was transferred to Power in conjunction with the generation asset transfer in 2000. The contract provided for PSE&G to supply ODEC with capacity and energy for a bundled rate that includes a component to recover multiple transmission charges (referred to as “pancaked transmission rates”).
In November 1997, FERC issued the PJM Restructuring Order, which required PSE&G to modify its contract with ODEC to remove pancaked transmission rates. While PSE&G sought rehearing of this order, it was nonetheless required to reduce its rate to ODEC by approximately $6 million per year, effective April 1, 1998.
In 2000, FERC issued its order denying PSE&G’s request for rehearing. Thereafter, PSE&G appealed to the U.S. Court of Appeals for judicial review of the matter. On December 19, 2002, based on a court ruling, FERC reversed its November 1997 order, thereby reinstating the original contract terms. This allowed Power to collect amounts for April 1998 through December 2002 pursuant to the original contract. Power billed ODEC for this amount in January 2003. Power has been billing, recording and receiving payment on the higher rate for services provided since January 2003. ODEC is paying such increased rates currently under protest, but has refused to pay past due amounts aggregating $31 million. On October 22, 2003, FERC issued its order affirming the prices in the original contract and denying ODEC’s request for reconsideration and its request for a stay. ODEC sought rehearing of that order on November 21, 2003. Nevertheless, ODEC continues to withhold payment of the amounts due for the past period. Accordingly, on November 26, 2003, ER&T filed suit against ODEC for breach of contract in U.S. district court in Newark, New Jersey. On January 29, 2004, ODEC filed a motion to dismiss claiming that the ongoing FERC proceeding must be completed before any judicial intervention. On February 13, 2004, ER&T filed a motion for summary judgment. These motions are returnable in April 2004.
The difference in revenues between the contracted rate and the FERC-ordered reduced rate of approximately $31 million, inclusive of back interest, was recorded as Operating Revenues in the fourth quarter of 2003.
Guaranteed Obligations
Power
Power has guaranteed certain commodity related transactions for ER&T’s energy marketing activities. These guarantees were provided to counterparties in order to facilitate physical and financial agreements in gas, pipeline capacity, transportation, oil, electricity and related commodities and services. These Power guarantees support the current exposure, interest and other costs on sums due and payable by ER&T under these agreements. Guarantees offered for trading and marketing cover the granting of lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can go either direction. The face value of the guarantees outstanding as of December 31, 2003 and December 31, 2002 was $1.4 billion and $1.1 billion, respectively. In order for Power to experience a liability for the face value of the outstanding guarantees, ER&T would have to fully utilize the credit granted to it by every counterparty to whom Power has provided a guarantee and all of ER&T’s contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would
165
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
owe money to the counterparties). The probability of all contracts at ER&T being simultaneously “out-of-the-money” is highly unlikely. For this reason, the current exposure at any point in time is a more meaningful representation of the potential liability to Power under these guarantees. The current exposure consists of the net of accounts receivable and accounts payable (AR/AP) and the forward value on open positions, less any margins posted. The current exposure from such liabilities was $228 million and $268 million as of December 31, 2003 and December 31, 2002, respectively. Of the $228 million, $167 million is recorded on Power’s Consolidated Balance Sheets as of December 31, 2003.
In addition, all supply contracts contain margin and/or other collateral requirements that, as of December 31, 2003, could require Power to post additional collateral of approximately $377 million if: a) Power were to lose its investment grade credit rating and b) all counterparties with whom Power is “out-of-the money” under such contracts, were entitled to, and called for, collateral.
As of December 31, 2003, letters of credit issued by Power were outstanding in the amount of approximately $74 million in support of various contractual obligations, environmental liabilities and to satisfy trading collateral obligations.
Power has also guaranteed equity contributions by its subsidiaries relating to its Lawrenceburg and Waterford facilities, as discussed below in New Generation and Development. Should Power lose its investment grade credit rating, it would be required to post $86 million in letters of credit for these facilities. This guarantee will be cancelled upon satisfaction of the equity commitment, which is included in Power’s anticipated capital expenditures through the second quarter 2004.
Energy Holdings
Energy Holdings and/or Global have guaranteed certain obligations of their subsidiaries or affiliates, including the successful completion, performance or other obligations related to certain projects, in an aggregate amount of approximately $180 million as of December 31, 2003. The guarantees include a $49 million standby equity commitment for Skawina, a $10 million equity commitment for Elcho and a $25 million contingent guarantee related to debt service obligations of Chilquinta. Additional guarantees consist of a $37 million leasing agreement guarantee for Prisma, $24 million of performance guarantees related to Energy Technologies that are supported by letters of credit discussed below and various other guarantees comprising the remaining $35 million.
As a result of Energy Holdings’ ratings falling below investment grade, Energy Holdings has letters of credit outstanding of approximately $10 million for certain of its equity commitments as of December 31, 2003. Under existing agreements Energy Holdings will not need to post any additional letters of credit.
In September 2003, Energy Holdings completed the sale of Energy Technologies and nearly all of its assets. However, Energy Holdings retained certain outstanding construction and warranty obligations related to ongoing construction projects previously performed by Energy Technologies. These construction obligations have performance bonds issued by insurance companies. As of December 31, 2003, there were $87 million of such bonds outstanding, of which $21 million related to uncompleted construction projects. These performance bonds are not included in the $180 million of guaranteed obligations discussed above. In January 2003, Energy Holdings provided an indemnification agreement and $31 million of letters of credit in support of Energy Technologies’ obligations. As of December 31, 2003, $24 million in letters of credit remain, including obligations relating to certain of the HVAC/mechanical operating companies that have been previously sold. These amounts are expected to decrease over time as each of the HVAC/mechanical operating companies completes the work in process.
166
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Environmental Matters
PSE&G and Power
Hazardous Waste
The New Jersey Department of Environmental Protection (NJDEP) adopted regulations concerning site investigation and remediation that require an ecological evaluation of potential damages to natural resources in connection with an environmental investigation of contaminated sites. These regulations may materially increase the costs of environmental investigations and remediation, where necessary, particularly at sites situated on surface water bodies. PSE&G, Power and their respective predecessor companies own or owned and/or operate or operated certain facilities situated on surface water bodies, certain of which are currently the subject of remedial activities. The financial impact of these regulations on these projects is not currently estimable. PSE&G and Power do not anticipate that compliance with these regulations will have a material adverse effect on their respective financial positions, results of operations or net cash flows.
Passaic River Site
The U.S. Environmental Protection Agency (EPA) has determined that a six-mile stretch of the Passaic River in the area of Newark, New Jersey is a “facility” within the meaning of that term under Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA). PSE&G and certain of its predecessors conducted industrial operations at properties adjacent to the Passaic River facility. The operations included one operating and one former generating station and four former Manufactured Gas Plants (MGPs). PSE&G’s costs to clean up former MGPs are recoverable from utility customers through the SBC. PSE&G has sold the site of the former generating station and obtained releases and indemnities for liabilities arising out of that site in connection with the sale. The operating generating station was transferred to Power in August 2000.
In September 2003, the EPA notified 41 potentially responsible parties (PRPs), including PSE&G, that it was expanding its assessment of the Passaic River Study Area to the entire 17-mile tidal reach of the lower Passaic River. The EPA further indicated, with respect to PSE&G, that it believed that hazardous substances were being released from the Essex Generating Station, an operating electric generating station, and a former MGP located in Harrison, New Jersey, which also includes facilities for PSE&G’s ongoing gas operations. The EPA estimated that its study would require five to seven years and would cost approximately $20 million, of which it would seek to recover $10 million from the PRPs. Power assumed all environmental liabilities associated with the electric generating stations that PSE&G transferred to it, including the Essex Generating Station.
Also, in September 2003, PSEG, PSE&G and 56 other PRPs received a Directive and Notice to Insurers from the NJDEP for the PRPs to arrange for a natural resource damage assessment and interim compensatory restoration of natural resource injuries along the lower Passaic River and its tributaries pursuant to the New Jersey Spill Act. The NJDEP alleged in the Directive that it had determined that hazardous substances had been discharged from the Essex Site and the Harrison Site. NJDEP announced in a meeting of the parties who received the directive that it had estimated the cost of interim natural resource injury restoration activities along the lower Passaic River to approximate $950 million. PSE&G and Power have indicated to both EPA and NJDEP that they are willing to work with the agencies in an effort to resolve their claims. Most of the other PRPs notified by the EPA or the NJDEP have responded similarly. None of PSEG, PSE&G or Power can predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to the Passaic River, however, such costs could be material.
167
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSE&G
MGP Remediation Program
PSE&G is currently working with the NJDEP under a program (Remediation Program) to assess, investigate and, if necessary, remediate environmental conditions at PSE&G’s former MGP sites. To date, 38 sites have been identified. The Remediation Program is periodically reviewed and revised by PSE&G based on regulatory requirements, experience with the Remediation Program and available remediation technologies. The long-term costs of the Remediation Program cannot be reasonably estimated at this time, but experience to date indicates that at least $20 million per year could be incurred over a period of about 30 years since the inception of the program in 1988 and that the overall cost could be material. The costs for this remediation effort are recovered through SBC charges to utility customers.
As of December 31, 2003, PSE&G’s estimated net liability for remediation costs through 2006 totaled $123 million. Expenditures beyond 2006 cannot be reasonably estimated at this time and are therefore not accrued.
In September 2003, the EPA and NJDEP notified PRPs, including PSE&G, that they were expanding their assessment of the Passaic River Study Area to the entire 17-mile tidal reach of the lower Passaic River. The EPA and NJDEP both indicated that they believed that hazardous substances were being released from a former MGP located in Harrison, NJ, among other locations. For further discussion related to this matter see “Passaic River Site” above.
Power
Prevention of Significant Deterioration (PSD)/New Source Review (NSR)
In November 1999, the Federal government announced the filing of lawsuits against several companies operating power plants in the Midwest and Southeast U.S., charging that 32 coal-fired plants in ten states violated the PSD/NSR requirements of the Clean Air Act (CAA). Several states, environmental groups and public interest organizations have filed or given notice of their intent to file similar lawsuits. Generally, the PSD/NSR regulations require major sources of certain air pollutants to obtain permits, install pollution control technology and obtain offsets in some circumstances when those sources undergo a “major modification,” as defined in the regulations. The Federal government is seeking to order these companies to install the best available air pollution control technology at the affected plants and to pay monetary penalties of up to $27,500 for each day of continued violation.
The EPA and the NJDEP issued a demand in March 2000 under the CAA requiring information to assess whether projects completed since 1978 at the Hudson and Mercer coal-fired units were implemented in accordance with applicable PSD/NSR regulations. Power completed its response to the information request in November 2000. In January 2002, Power reached an agreement with New Jersey and the Federal government to resolve allegations of noncompliance with Federal and State of New Jersey PSD/NSR regulation. Under that agreement, over the course of 10 years, Power must install advanced air pollution controls that are designed to reduce emissions of NOx, SO2, particulate matter and mercury. Power also paid a $1.4 million civil penalty and has agreed to spend up to $6 million on supplemental environmental projects. The agreement resolving the NSR allegations concerning the Hudson and Mercer coal-fired units also resolved a dispute over Bergen 2 regarding the applicability of PSD requirements and allowed construction of the unit to be completed and operation to begin.
Power has recently notified the EPA and the NJDEP that it is evaluating the continued operation of the Hudson coal unit beyond 2006, in light of changes in the energy and capacity markets and increases in the cost of pollution control equipment and other necessary modifications to the unit. A decision is expected to be made in 2004 as to the Hudson unit’s continued operation. The related costs associated with these modifications have not been included in Power’s capital expenditure projections. Future environmental initiatives are expected to require reduced emissions of NOx, SO2, mercury, and
168
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
possibly CO2 from electric generating facilities. The emission reductions to be achieved are expected to assist in complying with such future requirements.
ISRA
Potential environmental liabilities related to subsurface contamination at certain generating stations have been identified as a result of compliance with ISRA, which applies to the sale of certain assets. In the second quarter of 1999, in anticipation of the transfer of PSE&G’s generation-related assets to Power, a study was conducted to identify potential environmental liabilities and PSEG had a $51 million liability as of December 31, 2003 related to these obligations, which is recorded on the Consolidated Balance Sheets.
New Generation and Development
Power and Energy Holdings
Completion of the projects discussed below, within the estimated time frames and cost estimates cannot be assured. Construction delays, cost increases and various other factors could result in changes in the operational dates or ultimate costs to complete.
Power
Through an indirect, wholly-owned subsidiary, Power is developing the Bethlehem Energy Center that will replace the Albany, NY Steam Station. Total costs for this project are expected to be approximately $500 million with expenditures to date of approximately $303 million. Construction began in 2002 with the expected completion date in 2005, at which time the existing station will be retired.
Power is constructing a generation plant in Linden, New Jersey. Total costs are estimated to be approximately $775 million with expenditures to date of approximately $621 million. Completion is expected in 2005, at which time 451 MW of existing generating capacity at the site will be retired.
Power has constructed, through an indirect, wholly-owned subsidiary, a natural gas-fired generation plant in Waterford, Ohio which achieved commercial operation in August 2003. Power is constructing, through a separate indirect, wholly-owned subsidiary, a natural gas-fired generation plant in Lawrenceburg, Indiana. Both plants combined have an estimated aggregate total cost of $1.2 billion. Expenditures on these projects are nearly complete, with approximately $372 million of the total estimated equity of $416 million invested. The $800 million remainder has been financed with non-recourse bank financing, the terms of which provide for cross collateralization of cash flows between the two projects.
In connection with these projects, ER&T entered into a five-year tolling agreement for each project pursuant to which ER&T, with support from Fossil and Power under tolling make-whole agreements, is obligated to purchase the output of these facilities. The “all-in” payment under these agreements is currently materially above market. These agreements may be terminated upon repayment of the existing financing, which currently matures in August 2005. Under the tolling make whole agreements, Fossil and Power are required under certain circumstances to make additional equity investments into Lawrenceburg and Waterford.
The Lawrenceburg facility’s commercial operation date is now expected in the first half of 2004. Power has successfully negotiated amendments to its $800 million loan agreements with the banks, which initially required the Lawrenceburg facility to achieve commercial operation by December 31, 2003.
Power also has contracts with outside parties to purchase upgraded turbines for the Salem Units 1 and 2 and to purchase upgraded turbines and complete a power uprate for Hope Creek to increase its generating capacity. The power uprate for Hope Creek is currently scheduled to be completed by 2006,
169
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
assuming timely approval from the Nuclear Regulatory Commission (NRC). The turbine replacements are currently scheduled to be complete during planned refueling outages by 2004 for Salem Unit 1, 2006 for Hope Creek and 2008 for Salem Unit 2. Power’s aggregate estimated costs for these projects are $211 million, with expenditures to date of approximately $101 million.
Power has renegotiated certain of its contracts relating to commitments of approximately $110 million for purchases of hardware and services, for which Power would have been subject to cancellation penalties of up to $24 million. As a result of these negotiations, Power has entered into long-term contractual services agreement with a vendor who will provide the outage and service needs for certain of Power’s generating units at market rates. The contract covers approximately twenty-five years and could result in annual payments ranging from approximately $10 million to $50 million per year for services, parts and materials rendered.
Energy Holdings
California
GWF Energy, which is jointly owned by Global and Harbinger GWF LLC (Harbinger), owns and operates three peaker plants in California. In 2003, Harbinger filed an action alleging that Global wrongfully diluted Harbinger’s membership interest percentage in GWF Energy and sought an injunction to prevent Global from converting or maintaining the conversion of optional loans made to GWF Energy by Global into capital contributions and thus diluting Harbinger’s membership interest percentage. In June 2003, Global and Harbinger agreed that the issues and claims raised by Harbinger were to be resolved through arbitration. As of December 31, 2003, Global’s ownership interest in GWF Energy was approximately 74.9%. Pursuant to the arbitration in February 2004, Harbinger repurchased 14.9% interest in GWF Energy for approximately $14 million decreasing Global’s interest to 60%. The reduction in Global’s ownership interest in GWF Energy is not expected to have a material impact on Energy Holdings’ consolidated financial statements.
Poland
In 2002, Global acquired a 50% interest in the electric and thermal coal-fired Skawina plant. In accordance with the original purchase agreement, Global increased its equity interest in Skawina to approximately 63% in August 2003. Additionally, the agreement obligates Global to offer to purchase an additional 12% from Skawina’s employees in 2004, increasing Global’s potential ownership interest to approximately 75%. Global’s total equity investment is expected to be approximately $50 million. In addition, Global has approximately $49 million of equity commitment guarantees related to the modernization of the plant for environmental upgrades over an eight-year period, which could increase Global’s total equity investment to $99 million. Global expects that cash generated from Skawina’s operations will be sufficient to fund all modernization costs.
Minimum Energy Related Purchase Requirements
Power
Power purchases coal for certain of its fossil generation stations through various contracts and in the spot market. The total minimum purchase requirements included in these contracts amount to approximately $280 million through 2008.
Power has several long-term purchase contracts with uranium suppliers, converters, enrichers and fabricators to meet the currently projected fuel requirements for Salem and Hope Creek nuclear power plants. On average, Power has various multi-year requirements-based purchase commitments that total approximately $97 million per year to meet Salem’s and Hope Creek’s fuel needs, of which Power’s share is approximately $70 million per year through 2008. Power has been advised by Exelon, the co-owner and operator of Peach Bottom, that it has similar purchase contracts to satisfy the fuel
170
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
requirements for Peach Bottom, through 2008; of which Power’s share is approximately $35 million per year.
In addition to its fuel requirements, Power has entered into various multi-year contracts for firm transportation and storage capacity for natural gas. As of December 31, 2003, the total minimum fixed cost commitments under these contracts was approximately $850 million through 2016.
BGS Supply
PSE&G and Power
Power’s objective is to enter into load serving contracts and trading positions for at least 75% of its anticipated output over an 18-month to 24-month horizon. PSE&G’s objective is to obtain all of its energy supply needs for its customers through the BGS auction. As a result of the conclusion of the BGS auction in February 2004, the contracts Power has entered into in Pennsylvania and Connecticut and other firm sales and trading positions, commitments were entered into to achieve these objectives.
Nuclear Fuel Disposal
Power
Under the Nuclear Waste Policy Act of 1982, as amended (NWPA), the Federal government has entered into contracts with the operators of nuclear power plants for transportation and ultimate disposal of spent nuclear fuel. To pay for this service, nuclear plant owners are required to contribute to a Nuclear Waste Fund at a rate of one mil ($0.001) per Kilowatt-hour (kWh) of nuclear generation, subject to such escalation as may be required to assure full cost recovery by the Federal government. Under the NWPA, the U.S. Department of Energy (DOE) was required to begin taking possession of the spent nuclear fuel by no later than 1998. The DOE has announced that it does not expect a facility for this purpose to be available earlier than 2010.
Pursuant to NRC rules, spent nuclear fuel generated in any reactor can be stored in reactor facility storage pools or in independent spent fuel storage installations located at reactors or away-from-reactor sites for at least 30 years beyond the licensed life for reactor operation (which may include the term of a revised or renewed license). The availability of adequate spent fuel storage capacity is estimated through 2011 for Salem 1, 2015 for Salem 2 and 2007 for Hope Creek. Power presently expects to construct an on-site storage facility that would satisfy the spent fuel storage needs of both Salem and Hope Creek through the end of their respective license lives. This construction will require certain regulatory approvals, the timely receipt of which cannot be assured. Exelon has advised Power that it has constructed an on-site storage facility at Peach Bottom that is now licensed and operational. This on-site storage facility will satisfy Peach Bottom’s fuel storage until at least 2014.
Exelon had previously advised Power that it had signed an agreement with the DOE applicable to Peach Bottom under which Exelon would be reimbursed for costs incurred resulting from the DOE’s delay in accepting spent nuclear fuel. Under this agreement, Power’s portion of Peach Bottom’s Nuclear Waste Fund fees have been reduced by approximately $18 million through August 31, 2002, at which point the credits were fully utilized and covered the cost of Exelon’s storage facility. In 2000, a petition was filed against the DOE in the U.S. Court of Appeals for the Eleventh Circuit, seeking to set aside the receipt of credits by Exelon. In September 2002, the Court issued an opinion upholding the challenge by the petitioners. The DOE and Exelon are required to meet and discuss alternative funding sources for the settlement credits. The Eleventh Circuit’s opinion suggests that the federal judgment fund should be available as an alternate source. On August 14, 2003, Exelon received a letter from the DOE demanding repayment of previously received credits from the Nuclear Waste Fund. The letter also demanded a total of approximately $1.5 million of accrued interest (100% share). PSEG and Power continue to believe that it is the Federal government’s obligation to pay for storage related costs due to DOE’s failure to take possession of the spent nuclear fuel. Further, PSEG and Power also believe that any current payments potentially required relating to the past Nuclear Waste Fund fees will ultimately
171
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
be recovered and accordingly no amounts have been accrued. Exelon has advised Power that it filed suit in January 2004 in the U.S. Court of Federal Claims seeking damages caused by the DOE not taking possession of spent nuclear fuel in 1998.
In September 2001, Nuclear filed a complaint in the U.S. Court of Federal Claims seeking damages caused by the DOE not taking possession of spent nuclear fuel in 1998. No assurances can be given as to any damage recovery or the ultimate availability of a disposal facility.
In October 2001, Power filed a complaint in the U.S. Court of Federal Claims, along with a number of other plaintiffs, seeking $28 million in relief from past overcharges by the DOE for enrichment services. No assurances can be given as to any damage recovery.
Spent Fuel Pool Leakage
Power
The spent fuel pool at each Salem unit has an installed leakage collection system. This normal leakage path was recently found to be obstructed, causing concern about the extent of leakage contact with the fuel handling building’s concrete structure. Nuclear is developing a solution to maintain the design function of the leakage collection system and is investigating the extent of any structural degradation caused by the previous leakage. The investigation should take approximately one year. If any significant degradation is identified, the repair costs could be material. PSEG believes that the NRC will soon distribute an information notice on this emerging industry issue and PSEG cannot predict what further actions the NRC may take on this matter.
Elevated concentrations of tritium in the shallow groundwater near Salem Unit 1 were detected in early 2003. This information was reported to the NJDEP and the NRC, as required. Nuclear is conducting a comprehensive investigation in accordance with NJDEP site remediation regulations to determine the source and extent of the tritium in the groundwater. Currently, the source of the tritium contamination is believed to be the Salem Unit 1 Spent Fuel Pool. The investigation is ongoing and therefore the costs necessary to address this groundwater contamination issue are not known fully, however, such costs are not expected to be material.
Other
PSEG and PSE&G
ITC
As of June 1999, the Internal Revenue Service (IRS) had issued several private letter rulings that concluded that the refunding of excess deferred tax and ITC balances to utility customers was permitted only over the related assets’ regulatory lives, which were terminated upon deregulation. Based on this fact, in 1999, PSEG and PSE&G reversed the deferred tax and ITC liability relating to its generation assets that were transferred to Power and recorded a $235 million reduction as a component of the extraordinary charge recorded in 1999 due to the deregulation in New Jersey. PSE&G was directed by the BPU to seek a ruling from the IRS to determine if the ITC included in the impairment write-down of generation assets could be credited to customers without violating the tax normalization rules of the Internal Revenue Code. PSE&G filed for a private letter ruling request in 2002, which is still pending.
In January 2003, the IRS proposed for comment regulations that, if adopted, would allow utilities to elect retroactive application over periods equivalent to the ones in place prior to deregulation. While PSEG cannot predict the outcome of this matter, a requirement to refund such amounts to customers could have a material impact on PSEG’s and PSE&G’s financial condition, results of operations and net cash flows.
172
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSE&G
Placement of Gas Meters
In 2003, a proposed class action lawsuit was filed against PSE&G and PSEG alleging that PSE&G’s installation of outdoor gas meters within three feet of driveways or garages at residential locations is negligent. The suit also requests the court to order PSE&G to establish a fund for the purposes of remediating the allegedly improper meter installations.
In August 2003, the Judge in the case granted PSE&G’s and the BPU’s motions to transfer the matter to the BPU to review regulatory issues within the agency’s primary jurisdiction. The case was transferred prior to the court ruling on whether the proposed class would be certified. The court retained jurisdiction over the negligence-based issues. The BPU initiated an evidentiary hearing process in the case in September 2003. In December 2003, the parties filed testimony with the BPU. Evidentiary hearings, which were scheduled for early January 2004, have been postponed to allow the parties to initiate settlement discussions. PSE&G cannot predict the ultimate outcome of this matter.
Energy Holdings
Argentina
Empresa Distribuidora La Plata S.A. (EDELAP) and AES Parana Project
During 2003, the shares formerly held by Global in EDELAP and AES Parana were transferred to AES. In connection with that transfer, certain contingent obligations of Global with respect to project loans were terminated by agreement with the lenders.
Empresa Distribuidora de Electricidad Norte (EDEN) and Empresa Distribuidora de
Electricidad Sur (EDES)
In December 2003, the shares held by Global in EDEN and in EDES were transferred to AES. In connection with these transfers, certain contingent obligations Global had with respect to the projects were transferred to the purchaser.
EDEERSA
Energy Holdings completed the process of exiting from the EDEERSA electric distribution company in the Province of Entre Rios, Argentina. In March 2003, PSEG formally and irrevocably renounced, and effectively abandoned, its entire economic and legal interest in EDEERSA. The shares were relinquished and ownership was assumed by an Argentine trust benefiting current EDEERSA employees, including all of the existing EDEERSA Class C shareholders who received their shares from the Province as part of the initial privatization process. The regulator in the Province has requested that 51% of the EDEERSA shares be transferred from the trust to the Province. The matter is pending in the courts. A representative of the labor union representing EDEERSA filed a criminal complaint against the transaction alleging that the union should have been allocated more interest in EDEERSA than the trust arrangement currently provides. Energy Holdings believes that it will have no additional exposure to these legal proceedings, but no assurances can be given.
Peru
Electroandes
In November 2002, the Peruvian Government created a subsidy in favor of the construction of the Camisea gas pipeline, in the form of a surcharge to the electric transmission tariffs paid by all end users. Two of Electroandes’ largest customers (representing about 67% of its contracted capacity) refused to pay the surcharge, thus preventing Electroandes, in its role as collection agent, from transferring the
173
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
associated funds to the beneficiaries of the surcharge. In July 2003, Electroandes made a filing with the courts to determine which party was responsible for payment of this subsidy. Subsequent to this filing, the dispute was favorably resolved with the customers and the local electric regulatory agency. Electroandes has since requested a withdrawal of its filing and expects an official conclusion from the courts on the resolution of this matter in the first quarter of 2004.
Luz del Sur (LDS)
The Superintendencia Nacional de Administracion Tributaria (SUNAT), the governing tax authority in Peru, claimed past-due taxes for the period between 1996-1999, plus penalties and interest, resulting from an interpretation of the law that allowed LDS to restate its assets to fair market value and take advantage of the resulting higher deductions from depreciation. While LDS prevailed on this issue in arbitration proceedings that ended in December 2001, SUNAT pursued the claim in the local Tax Court. The Tax Court ordered SUNAT to rule according to the arbitration, which was favorable to LDS. The Tax Court did make a reference a provision of law, which requires consideration of the legitimacy of the business motives leading to a corporate reorganization, such as the one made by LDS and which gave rise to the original dispute. LDS believes it had legitimate business motives to reorganize when it did and management believed that it acted in accordance with the applicable law and, accordingly, LDS’s position prevailed as SUNAT agreed that this provision of law did not apply.
Further, SUNAT stated that the revaluation study, performed in 1996, was not performed correctly and is therefore invalid. It is LDS’s position that laws and regulations did not define the methodology to be used in these matters and its study was based on generally accepted practices. LDS’s total potential liability relating to this matter is approximately $55 million, of which $18 million is currently recorded as a deferred tax liability at LDS. Global’s share of the net potential liability related to the claim by SUNAT is estimated at $16 million.
In July 2003, SUNAT presented its claims before the Fiscal Court. In January 2004, the Fiscal Court ruled in favor of LDS in respect of the 1999 matter. LDS believes the 1996-1998 years will be decided consistent with this ruling.
Minimum Lease Payments
PSEG, PSE&G and Energy Holdings
PSE&G, Services and Energy Holdings lease administrative office space under various operating leases. For the years ended December 31, 2003, 2002 and 2001, PSEG’s lease expenses were approximately $10 million per year, primarily related to Energy Holdings. Total future minimum lease payments as of December 31, 2003 are:
| | 2004 | | 2005 | | 2006 | | | 2007 | | | 2008 | | After
2008 | | Total | |
| | | | | | | | | | | (Millions) | | | | | | | | | | |
PSE&G | | $ | 3 | | $ | 3 | | $ | 2 | | | $ | 2 | | | $ | 1 | | $ | — | | $ | 11 | |
Services | | | 1 | | | 1 | | | 1 | | | | 1 | | | | 1 | | | 3 | | | 8 | |
Energy Holdings | | | 8 | | | 7 | | | 6 | | | | 6 | | | | 5 | | | 16 | | | 48 | |
Total PSEG | | $ | 12 | | $ | 11 | | $ | 9 | | | $ | 9 | | | $ | 7 | | $ | 19 | | $ | 67 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
174
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Power and Services have entered into capital leases for administrative office space. The total future minimum payments and present value of these capital leases as of December 31, 2003 are:
| | Services | | Power | |
| | (Millions) | |
2004 | | $ | 6 | | $ | 1 | |
2005 | | | 6 | | | 1 | |
2006 | | | 7 | | | 1 | |
2007 | | | 7 | | | 2 | |
2008 | | | 7 | | | 2 | |
Thereafter | | | 43 | | | 11 | |
Total Minimum Lease Payments | | $ | 76 | | $ | 18 | |
Less: Imputed Interest | | | (35 | ) | | (7 | ) |
Present Value of net Minimum Lease Payments | | $ | 41 | | $ | 11 | |
Note 18. Nuclear Decommissioning Trust
Power
In accordance with NRC regulations, entities owning an interest in nuclear generating facilities are required to determine the costs and funding methods necessary to decommission such facilities upon termination of operation. As a general practice, each nuclear owner places funds in independent external trust accounts it maintains to provide for decommissioning.
For information relating to cost responsibility for nuclear decommissioning subsequent to July 31, 2003, see Note 4. Adoption of SFAS 143.
Power maintains the external master nuclear decommissioning trust previously established by PSE&G. This trust contains two separate funds: a qualified fund and a non-qualified fund. Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a “qualified“ fund. Contributions made into a qualified fund are tax deductible. In the most recent study the total cost of decommissioning, Power’s share of its five nuclear units was estimated at approximately $2.1 billion, including contingencies.
Power’s policy is that, except for investments tied to market indexes or other non-nuclear sector common trust funds or mutual funds (e.g., an S&P 500 mutual fund), assets of the trust shall not be invested in the securities or other obligations of PSEG or its affiliates, or its successors or assigns; and assets shall not be invested in securities of any entity owning one or more nuclear power plants.
Effective January 1, 2003, Power began accounting for the assets in the NDT Fund under SFAS 115. Power classifies investments in the NDT Fund as available-for-sale under SFAS 115. The
175
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in the NDT Fund.
| | As of December 31, 2003 | |
| | Cost | | Gross
Unrealized
Gains | | Gross
Unrealized
Losses | | Estimated
Fair Value | |
| | (Millions) | |
Equity Securities | | $ | 447 | | | $ | 186 | | | | $ | (14 | ) | | | $ | 619 | | |
Debt Securities | | | | | | | | | | | | | | | | | | | |
Government Obligations | | | 136 | | | | 3 | | | | | (1 | ) | | | | 138 | | |
Other Debt Securities | | | 200 | | | | 11 | | | | | (5 | ) | | | | 206 | | |
Total Debt Securities | | | 336 | | | | 14 | | | | | (6 | ) | | | | 344 | | |
Other Securities | | | 25 | | | | — | | | | | (3 | ) | | | | 22 | | |
Total Available-for-Sale Securities | | $ | 808 | | | $ | 200 | | | | $ | (23 | ) | | | $ | 985 | | |
| | As of December 31, 2002 | |
| | Cost | | Gross
Unrealized
Gains | | Gross
Unrealized
Losses | | Estimated
Fair Value | |
| | (Millions) | |
Equity Securities | | $ | 424 | | | $ | 74 | | | | $ | (47 | ) | | | $ | 451 | | |
Debt Securities | | | | | | | | | | | | | | | | | | | |
Government Obligations | | | 83 | | | | 6 | | | | | — | | | | | 89 | | |
Other Debt Securities | | | 206 | | | | 9 | | | | | (21 | ) | | | | 194 | | |
Total Debt Securities | | | 289 | | | | 15 | | | | | (21 | ) | | | | 283 | | |
Other Securities | | | 32 | | | | — | | | | | — | | | | | 32 | | |
Total Available-for-Sale Securities | | $ | 745 | | | $ | 89 | | | | $ | (68 | ) | | | $ | 766 | | |
| | | Years Ended | |
| | December 31, | |
| | 2003 | | 2002 | | 2001 | |
| | (Millions) | |
Proceeds from Sales | | $ | 1,229 | | $ | 491 | | $ | 589 | |
Gross Realized Gains | | $ | 115 | | $ | 45 | | $ | 45 | |
Gross Realized Losses | | $ | 64 | | $ | 62 | | $ | 52 | |
| | | | | | | | | | | |
Net realized gains of $51 million were recognized in Other Income and Other Deductions on Power’s Consolidated Statement of Operations for the year ended December 31, 2003. Net unrealized gains of $118 million were recognized in Other Comprehensive Income on Power’s Consolidated Balance Sheet as of December 31, 2003. Of the $23 million of the gross 2003 unrealized losses, $6 million have been in an unrealized loss position for less than twelve months. The available-for-sale debt securities held as of December 31, 2003, had the following maturities: $78 million less than one year, $62 million one to five years, $81 million five to ten years, $40 million ten to fifteen years, $16 million fifteen to twenty years, and $67 million over twenty years. The cost of these securities was determined on the basis of specific identification.
176
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 19. Other Income and Deductions
Other Income
| | PSE&G | | Power | | Energy
Holdings | | Other(A) | | Consolidated
Total | |
| | (Millions) | |
For the Year Ended December 31, 2003: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Interest Income | | | $ | (7 | ) | | | $ | 7 | | | | $ | — | | | | $ | 1 | | | | $ | 1 | | |
Gain on Disposition of Property | | | | 11 | | | | | — | | | | | — | | | | | — | | | | | 11 | | |
NDT Fund Realized Gains | | | | — | | | | | 115 | | | | | — | | | | | — | | | | | 115 | | |
NDT Interest and Dividend Income | | | | — | | | | | 26 | | | | | — | | | | | — | | | | | 26 | | |
Foreign Currency Gains | | | | — | | | | | — | | | | | 16 | | | | | — | | | | | 16 | | |
Other | | | | 2 | | | | | 1 | | | | | 4 | | | | | 2 | | | | | 9 | | |
Total Other Income | | | $ | 6 | | | | $ | 149 | | | | $ | 20 | | | | $ | 3 | | | | $ | 178 | | |
For the Year Ended December 31, 2002: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Interest Income | | | $ | 4 | | | | $ | — | | | | $ | — | | | | $ | — | | | | $ | 4 | | |
Gain on Disposition of Property | | | | 10 | | | | | — | | | | | — | | | | | — | | | | | 10 | | |
Change in Derivative Fair Value | | | | — | | | | | — | | | | | 11 | | | | | — | | | | | 11 | | |
Gain on Early Retirement of Debt | | | | — | | | | | — | | | | | 14 | | | | | — | | | | | 14 | | |
Minority Interest | | | | — | | | | | — | | | | | — | | | | | 1 | | | | | 1 | | |
Other | | | | 1 | | | | | 1 | | | | | 1 | | | | | (4 | ) | | | | (1 | ) | |
Total Other Income | | | $ | 15 | | | | $ | 1 | | | | $ | 26 | | | | $ | (3 | ) | | | $ | 39 | | |
For the Year Ended December 31, 2001: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Interest Income | | | $ | 88 | | | | $ | — | | | | $ | — | | | | $ | (66 | ) | | | $ | 22 | | |
Gain on Disposition of Property | | | | 4 | | | | | — | | | | | — | | | | | — | | | | | 4 | | |
Other | | | | 3 | | | | | — | | | | | 4 | | | | | — | | | | | 7 | | |
Total Other Income | | | $ | 95 | | | | $ | — | | | | $ | 4 | | | | $ | (66 | ) | | | $ | 33 | | |
177
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Other Deductions
| | PSE&G | | Power | | Energy
Holdings | | Other(A) | | Consolidated
Total | |
| | (Millions) | |
For the Year Ended December 31, 2003: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Donations | | | $ | 1 | | | | $ | — | | | | $ | — | | | | $ | 4 | | | | $ | 5 | | |
NDT Fund Realized Losses and Expenses | | | | — | | | | | 77 | | | | | — | | | | | — | | | | | 77 | | |
Minority Interest | | | | — | | | | | — | | | | | — | | | | | 13 | | | | | 13 | | |
Change in Derivative Fair Value | | | | — | | | | | — | | | | | 5 | | | | | — | | | | | 5 | | |
Other | | | | — | | | | | 1 | | | | | — | | | | | — | | | | | 1 | | |
Total Other Income | | | $ | 1 | | | | $ | 78 | | | | $ | 5 | | | | $ | 17 | | | | $ | 101 | | |
For the Year Ended December 31, 2002: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Donations | | | $ | 2 | | | | $ | — | | | | $ | — | | | | $ | — | | | | $ | 2 | | |
Foreign Currency Losses | | | | — | | | | | — | | | | | 77 | | | | | — | | | | | 77 | | |
Other | | | | — | | | | | 1 | | | | | — | | | | | — | | | | | 1 | | |
Total Other Deductions | | | $ | 2 | | | | $ | 1 | | | | $ | 77 | | | | $ | — | | | | $ | 80 | | |
For the Year Ended December 31, 2001: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Donations | | | $ | 3 | | | | $ | — | | | | $ | — | | | | $ | — | | | | $ | 3 | | |
Foreign Currency Losses | | | | — | | | | | — | | | | | 11 | | | | | — | | | | | 11 | | |
Change in Derivative Fair Value | | | | — | | | | | — | | | | | 3 | | | | | — | | | | | 3 | | |
Loss on Early Retirement of Debt | | | | — | | | | | — | | | | | 3 | | | | | — | | | | | 3 | | |
Other | | | | 1 | | | | | — | | | | | — | | | | | — | | | | | 1 | | |
Total Other Deductions | | | $ | 4 | | | | $ | — | | | | $ | 17 | | | | $ | — | | | | $ | 21 | | |
______________
| (A) | Other primarily consists of activity at PSEG (parent company), Services and intercompany eliminations. |
178
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 20. Income Taxes
A reconciliation of reported income tax expense with the amount computed by multiplying pre-tax income by the statutory Federal income tax rate of 35% is as follows:
| | PSE&G | | Power | | Energy
Holdings | | Other | | Consolidated
Total | |
| | (Millions) | |
2003 | | | | | | | | | | | | | | | | | | | | | | | |
Net Income (Loss) | | | $ | 225 | | | $ | 844 | | | $ | 122 | | | $ | (31 | ) | | | $ | 1,160 | | |
Extraordinary Item, net of tax benefit of $12 | | | | (18 | ) | | | — | | | | — | | | | — | | | | | (18 | ) | |
Loss from Discontinued Operations, (Including Loss on Disposal, net of tax—$10) | | | | — | | | | — | | | | (44 | ) | | | — | | | | | (44 | ) | |
Cumulative Effect of a Change in Accounting Principle, (net of tax benefit—$255) | | | | — | | | | 370 | | | | — | | | | — | | | | | 370 | | |
Minority Interest in Earnings of Subsidiaries | | | | — | | | | — | | | | (13 | ) | | | — | | | | | (13 | ) | |
Income from Continuing Operations, less Preferred Dividends | | | | 243 | | | | 474 | | | | 179 | | | | (31 | ) | | | | 865 | | |
Preferred Dividends (net) | | | | (4 | ) | | | — | | | | (23 | ) | | | 23 | | | | | (4 | ) | |
Income (Loss) from Continuing Operations excluding Minority Interest and Preferred Dividends | | | $ | 247 | | | $ | 474 | | | $ | 202 | | | $ | (54 | ) | | | $ | 869 | | |
Income Taxes: | | | | | | | | | | | | | | | | | | | | | | | |
Federal — Current | | | | 1 | | | | 134 | | | | (299 | ) | | | (43 | ) | | | | (207 | ) | |
Deferred | | | | 91 | | | | 121 | | | | 331 | | | | 4 | | | | | 547 | | |
ITC | | | | (2 | ) | | | — | | | | (1 | ) | | | — | | | | | (3 | ) | |
Total Federal | | | | 90 | | | | 255 | | | | 31 | | | | (39 | ) | | | | 337 | | |
State — Current | | | | (2 | ) | | | 41 | | | | (57 | ) | | | (10 | ) | | | | (28 | ) | |
Deferred | | | | 41 | | | | 30 | | | | 70 | | | | (1 | ) | | | | 140 | | |
Total State | | | | 39 | | | | 71 | | | | 13 | | | | (11 | ) | | | | 112 | | |
Foreign — Current | | | | — | | | | — | | | | — | | | | — | | | | | — | | |
Deferred | | | | — | | | | — | | | | 15 | | | | — | | | | | 15 | | |
Total Foreign | | | | — | | | | — | | | | 15 | | | | — | | | | | 15 | | |
Total | | | | 129 | | | | 326 | | | | 59 | | | | (50 | ) | | | | 464 | | |
Pre-tax Income | | | $ | 376 | | | $ | 800 | | | $ | 261 | | | $ | (104 | ) | | | $ | 1,333 | | |
Tax computed at the statutory rate | | | $ | 131 | | | $ | 280 | | | $ | 91 | | | $ | (36 | ) | | | $ | 466 | | |
Increase (decrease) attributable to flow through of certain tax adjustments: | | | | | | | | | | | | | | | | | | | | | | | |
Plant Related Items | | | | (18 | ) | | | — | | | | — | | | | — | | | | | (18 | ) | |
Amortization of investment tax credits | | | | (2 | ) | | | — | | | | (1 | ) | | | | | | | | (3 | ) | |
Other | | | | (8 | ) | | | (1 | ) | | | 1 | | | | (7 | ) | | | | (15 | ) | |
Tax Effects Attributable to Foreign Operations | | | | — | | | | — | | | | (40 | ) | | | — | | | | | (40 | ) | |
State Income Tax (net of Federal Income Tax) | | | | 26 | | | | 47 | | | | 8 | | | | (7 | ) | | | | 74 | | |
Subtotal | | | | (2 | ) | | | 46 | | | | (32 | ) | | | (14 | ) | | | | (2 | ) | |
Total income tax provisions | | | $ | 129 | | | $ | 326 | | | $ | 59 | | | $ | (50 | ) | | | $ | 464 | | |
Effective income tax rate | | | | 34.3 | % | | | 40.8 | % | | | 22.6 | % | | | 48.1 | % | | | | 34.8 | % | |
179
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | PSE&G | | Power | | Energy
Holdings | | Other | | Consolidated
Total | |
| | (Millions) | |
2002 | | | | | | | | | | | | | | | | | | | | | | |
Net Income (Loss) | | | $ | 201 | | | $ | 468 | | | $ | (413 | ) | | $ | (21 | ) | | $ | 235 | | |
Loss from Discontinued Operations, (Including Loss on Disposal, net of tax—$28) | | | | — | | | | — | | | | (49 | ) | | | — | | | | (49 | ) | |
Cumulative Effect of a Change in Accounting Principle, (net of tax—$66) | | | | — | | | | — | | | | (121 | ) | | | — | | | | (121 | ) | |
Minority Interest in Earnings of Subsidiaries | | | | — | | | | — | | | | 1 | | | | — | | | | 1 | | |
Income from Continuing Operations, less Preferred Dividends | | | | 201 | | | | 468 | | | | (244 | ) | | | (21 | ) | | | 404 | | |
Preferred Dividends (net) | | | | (4 | ) | | | — | | | | (23 | ) | | | 23 | | | | (4 | ) | |
Income (Loss) from Continuing Operations excluding Minority Interest and Preferred Dividends | | | $ | 205 | | | $ | 468 | | | $ | (221 | ) | | $ | (44 | ) | | $ | 408 | | |
| | | | | | | | | | | | | | | | | | | | | | |
Income Taxes: | | | | | | | | | | | | | | | | | | | | | | |
Federal — Current | | | | 121 | | | | 184 | | | | (102 | ) | | | (29 | ) | | | 174 | | |
Deferred | | | | (44 | ) | | | 69 | | | | (24 | ) | | | 6 | | | | 7 | | |
ITC | | | | (2 | ) | | | — | | | | (2 | ) | | | — | | | | (4 | ) | |
Total Federal | | | | 75 | | | | 253 | | | | (128 | ) | | | (23 | ) | | | 177 | | |
State — Current | | | | 17 | | | | 41 | | | | (1 | ) | | | (7 | ) | | | 50 | | |
Deferred | | | | 23 | | | | 19 | | | | (27 | ) | | | — | | | | 15 | | |
Total State | | | | 40 | | | | 60 | | | | (28 | ) | | | (7 | ) | | | 65 | | |
Foreign — Current | | | | — | | | | — | | | | 1 | | | | — | | | | 1 | | |
Deferred | | | | — | | | | — | | | | 11 | | | | — | | | | 11 | | |
Total Foreign | | | | — | | | | — | | | | 12 | | | | — | | | | 12 | | |
Total | | | | 115 | | | | 313 | | | | (144 | ) | | | (30 | ) | | | 254 | | |
Pre-tax Income | | | $ | 320 | | | $ | 781 | | | $ | (365 | ) | | $ | (74 | ) | | $ | 662 | | |
Tax computed at the statutory rate | | | $ | 112 | | | $ | 273 | | | $ | (128 | ) | | $ | (26 | ) | | $ | 231 | | |
Increase (decrease) attributable to flow through of certain tax adjustments: | | | | | | | | | | | | | | | | | | | | | | |
Plant Related Items | | | | (15 | ) | | | — | | | | — | | | | — | | | | (15 | ) | |
Amortization of investment tax credits | | | | (2 | ) | | | — | | | | (1 | ) | | | — | | | | (3 | ) | |
Other | | | | (6 | ) | | | 1 | | | | (4 | ) | | | — | | | | (9 | ) | |
Tax Effects Attributable to Foreign Operations | | | | — | | | | — | | | | (2 | ) | | | — | | | | (2 | ) | |
State Income Tax (net of Federal Income Tax) | | | | 26 | | | | 39 | | | | (9 | ) | | | (4 | ) | | | 52 | | |
Subtotal | | | | 3 | | | | 40 | | | | (16 | ) | | | (4 | ) | | | 23 | | |
Total income tax provisions | | | $ | 115 | | | $ | 313 | | | $ | (144 | ) | | $ | (30 | ) | | $ | 254 | | |
Effective income tax rate | | | | 35.9 | % | | | 40.1 | % | | | 39.5 | % | | | 40.5 | % | | | 38.4 | % | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
180
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | PSE&G | | Power | | Energy
Holdings | | Other | | Consolidated
Total | |
| | (Millions) | |
2001 | | | | | | | | | | | | | | | | | | | | | | | | | |
Net Income (Loss) | | | $ | 230 | | | | $ | 394 | | | | $ | 154 | | | $ | (14 | ) | | | $ | 764 | | |
Loss from Discontinued Operations, (net of tax—$8) | | | | — | | | | | — | | | | | (12 | ) | | | — | | | | | (12 | ) | |
Cumulative Effect of a Change in Accounting Principle, (net of tax—$8) | | | | — | | | | | — | | | | | 10 | | | | — | | | | | 10 | | |
Income from Continuing Operations, less Preferred Dividends | | | | 230 | | | | | 394 | | | | | 156 | | | | (14 | ) | | | | 766 | | |
Preferred Dividends (net) | | | | (5 | ) | | | | — | | | | | (23 | ) | | | 23 | | | | | (5 | ) | |
Income (Loss) from Continuing Operations excluding Preferred Dividends | | | $ | 235 | | | | $ | 394 | | | | $ | 179 | | | $ | (37 | ) | | | $ | 771 | | |
Income Taxes: | | | | | | | | | | | | | | | | | | | | | | | | | |
Federal — Current | | | | 250 | | | | | 139 | | | | | (106 | ) | | | (32 | ) | | | | 251 | | |
Deferred | | | | (192 | ) | | | | 74 | | | | | 161 | | | | 13 | | | | | 56 | | |
ITC | | | | (2 | ) | | | | — | | | | | (1 | ) | | | — | | | | | (3 | ) | |
Total Federal | | | | 56 | | | | | 213 | | | | | 54 | | | | (19 | ) | | | | 304 | | |
State — Current | | | | 42 | | | | | 17 | | | | | 9 | | | | (4 | ) | | | | 64 | | |
Deferred | | | | (9 | ) | | | | 20 | | | | | (11 | ) | | | (1 | ) | | | | (1 | ) | |
Total State | | | | 33 | | | | | 37 | | | | | (2 | ) | | | (5 | ) | | | | 63 | | |
Foreign — Current | | | | — | | | | | — | | | | | 1 | | | | — | | | | | 1 | | |
Deferred | | | | — | | | | | — | | | | | 5 | | | | — | | | | | 5 | | |
Total Foreign | | | | — | | | | | — | | | | | 6 | | | | — | | | | | 6 | | |
Total | | | | 89 | | | | | 250 | | | | | 58 | | | | (24 | ) | | | | 373 | | |
Pre-tax Income | | | $ | 324 | | | | $ | 644 | | | | $ | 237 | | | $ | (61 | ) | | | $ | 1,144 | | |
Tax computed at the statutory rate | | | $ | 113 | | | | $ | 225 | | | | $ | 83 | | | | (21 | ) | | | $ | 400 | | |
Increase (decrease) attributable to flow through of certain tax adjustments: | | | | | | | | | | | | | | | | | | | | | | | | | |
Plant Related Items | | | | (41 | ) | | | | — | | | | | — | | | | — | | | | | (41 | ) | |
Amortization of investment and energy tax credits | | | | (2 | ) | | | | — | | | | | (1 | ) | | | — | | | | | (3 | ) | |
Other | | | | (2 | ) | | | | 1 | | | | | (2 | ) | | | — | | | | | (3 | ) | |
Tax Effects Attributable to Foreign Operations | | | | — | | | | | — | | | | | (19 | ) | | | — | | | | | (19 | ) | |
State Income Tax (net of Federal Income Tax) | | | | 21 | | | | | 24 | | | | | (3 | ) | | | (3 | ) | | | | 39 | | |
Subtotal | | | | (24 | ) | | | | 25 | | | | | (25 | ) | | | (3 | ) | | | | (27 | ) | |
Total income tax provisions | | | $ | 89 | | | | $ | 250 | | | | $ | 58 | | | $ | (24 | ) | | | $ | 373 | | |
Effective income tax rate | | | | 27.5 | % | | | | 38.8 | % | | | | 24.5 | % | | | 39.3 | % | | | | 32.6 | % | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
PSEG, PSE&G, Power and Energy Holdings
Each of PSEG, PSE&G, Power and Energy Holdings provide 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 PSE&G’s customers in the future. Accordingly, an offsetting regulatory asset was established. As of December 31, 2003, PSE&G had a deferred tax liability and an offsetting regulatory asset of $368 million representing the tax costs
181
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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%.
Energy Holdings’ effective tax rate differs from the statutory Federal income tax rate of 35% primarily due to the imposition of state taxes and the fact that Global accounts for many of its foreign investments using the equity method of accounting. The foreign income taxes are a component of each PSEG and Energy Holdings’ equity in earnings rather than included as a component of the income tax provision.
The following is an analysis of deferred income taxes:
| | PSE&G | | Power | | Energy
Holdings | | Other | | Consolidated | |
| | 2003 | | 2002 | | 2003 | | 2002 | | 2003 | | 2002 | | 2003 | | 2002 | | 2003 | | 2002 | |
| | | (Millions) | |
Deferred Income Taxes | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Assets: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Current (net) | | $ | 17 | | $ | 16 | | $ | — | | $ | — | | $ | — | | $ | — | | $ | — | | $ | — | | $ | 17 | | $ | 16 | |
Noncurrent: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Unrecovered Investment Tax Credits | | | 19 | | | 19 | | | — | | | — | | | — | | | — | | | — | | | — | | | 19 | | | 19 | |
Nuclear Decommissioning | | | — | | | — | | | — | | | 26 | | | — | | | — | | | — | | | — | | | — | | | 26 | |
SFAS 133 | | | — | | | — | | | 21 | | | 2 | | | 47 | | | 53 | | | 7 | | | 9 | | | 75 | | | 64 | |
Other Comprehensive Income | | | 2 | | | 122 | | | — | | | 58 | | | (1 | ) | | 3 | | | 2 | | | 24 | | | 3 | | | 207 | |
New Jersey Corporate Business Tax | | | 189 | | | 232 | | | 102 | | | 125 | | | (60 | ) | | (5 | ) | | (1 | ) | | — | | | 230 | | | 352 | |
OPEB | | | 110 | | | 99 | | | — | | | — | | | — | | | — | | | — | | | — | | | 110 | | | 99 | |
Cost of Removal | | | — | | | — | | | 51 | | | 51 | | | — | | | — | | | — | | | — | | | 51 | | | 51 | |
Investment Related Adjustment | | | 12 | | | — | | | — | | | — | | | 118 | | | 270 | | | — | | | — | | | 130 | | | 270 | |
Development Fees | | | — | | | — | | | — | | | — | | | 18 | | | 22 | | | — | | | — | | | 18 | | | 22 | |
Foreign Currency Translation | | | — | | | — | | | — | | | — | | | 35 | | | 39 | | | — | | | — | | | 35 | | | 39 | |
Contractual Liabilities and Environmental Costs | | | — | | | — | | | 35 | | | 35 | | | — | | | — | | | — | | | — | | | 35 | | | 35 | |
Market Transition Charge | | | 11 | | | 66 | | | — | | | — | | | — | | | — | | | — | | | — | | | 11 | | | 66 | |
Other | | | (1 | ) | | — | | | 18 | | | — | | | — | | | — | | | — | | | — | | | 17 | | | — | |
Total Noncurrent | | | 342 | | | 538 | | | 227 | | | 297 | | | 157 | | | 382 | | | 8 | | | 33 | | | 734 | | | 1,250 | |
Total Assets | | | 359 | | | 554 | | | 227 | | | 297 | | | 157 | | | 382 | | | 8 | | | 33 | | | 751 | | | 1,266 | |
Liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Noncurrent: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Plant Related Items | | | 1,288 | | | 1,138 | | | (181 | ) | | (276 | ) | | — | | | — | | | — | | | 5 | | | 1,107 | | | 867 | |
Nuclear Decommissioning | | | — | | | — | | | 18 | | | — | | | — | | | — | | | — | | | — | | | 18 | | | — | |
Securitization | | | 1,414 | | | 1,502 | | | — | | | — | | | — | | | — | | | — | | | — | | | 1,414 | | | 1,502 | |
Leasing Activities | | | — | | | — | | | — | | | — | | | 1,509 | | | 1,298 | | | — | | | — | | | 1,509 | | | 1,298 | |
Partnership Activities | | | — | | | — | | | — | | | — | | | 96 | | | 66 | | | — | | | — | | | 96 | | | 66 | |
Conservation Costs | | | 68 | | | 10 | | | — | | | — | | | — | | | — | | | — | | | — | | | 68 | | | 10 | |
Pension Costs | | | 71 | | | 84 | | | 22 | | | 25 | | | — | | | — | | | 21 | | | 15 | | | 114 | | | 124 | |
SFAS 143 | | | — | | | — | | | 337 | | | — | | | — | | | — | | | — | | | — | | | 337 | | | — | |
Taxes Recoverable Through Future Rates (net) | | | 156 | | | 145 | | | — | | | — | | | — | | | — | | | — | | | — | | | 156 | | | 145 | |
Income from Foreign Operation | | | — | | | — | | | — | | | — | | | 31 | | | 34 | | | — | | | — | | | 31 | | | 34 | |
Other | | | 7 | | | 39 | | | — | | | (5 | ) | | 1 | | | (1 | ) | | 5 | | | 4 | | | 13 | | | 37 | |
Total Noncurrent | | | 3,004 | | | 2,918 | | | 196 | | | (256 | ) | | 1,637 | | | 1,397 | | | 26 | | | 24 | | | 4,863 | | | 4,083 | |
Total Liabilities | | | 3,004 | | | 2,918 | | | 196 | | | (256 | ) | | 1,637 | | | 1,397 | | | 26 | | | 24 | | | 4,863 | | | 4,083 | |
Summary—Accumulated Deferred Income Taxes: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net Current Assets | | | 17 | | | 16 | | | — | | | — | | | — | | | — | | | — | | | — | | | 17 | | | 16 | |
Net Noncurrent Liability | | | 2,662 | | | 2,380 | | | (31 | ) | | (553 | ) | | 1,480 | | | 1,015 | | | 18 | | | (9 | ) | | 4,129 | | | 2,833 | |
Total | | $ | 2,645 | | $ | 2,364 | | $ | (31 | ) | $ | (553 | ) | $ | 1,480 | | $ | 1,015 | | $ | 18 | | $ | (9 | ) | $ | 4,112 | | $ | 2,817 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
182
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 21. Pension, Other Postretirement Benefit (OPEB) and Savings Plans
PSEG
PSEG sponsors several qualified and nonqualified pension plans and other postretirement benefit plans covering PSEG’s, and its participating affiliates current and former employees who meet certain eligibility criteria.
Plan Assets
The following table provides the percentage of fair value of total plan assets for each major category of plan assets held as of the measurement date, December 31.
| | As of December 31, | |
Investments | | 2003 | | 2002 | |
Equity Securities | | 63% | | 58% | |
Fixed Income Securities | | 29% | | 34% | |
Real Estate Asset | | 5% | | 6% | |
Other Investments | | 3% | | 2% | |
Total Percentage | | 100% | | 100% | |
PSEG utilizes an independent pension consultant to forecast returns, risk, and correlation of all asset classes in order to develop an optimal portfolio, which is designed to produce the maximum return opportunity per unit of risk. In 2002, PSEG’s completed its latest asset/liability study. The results from the study indicated that, in order to achieve the optimal risk/return portfolio, target allocations of 62% equity securities, 30% fixed income securities, 5% real estate investments, and 3% for other investments should be maintained. Derivative financial instruments are used by the plans investment managers primarily to rebalance the fixed income/equity allocation of the portfolio and hedge the currency risk component of the foreign investments.
The expected long-term rate of return on plan assets was 9.00% as of December 31, 2003. For 2004, the expected long-term rate of return on plan assets was reduced to 8.75%. This expected return was determined based on the study discussed above and considered the plans’ historical annualized rate of return since inception of the plan, which was an annualized return of 10.20%.
Plan Contributions
PSEG anticipates contributing approximately $90 million into its qualified pension plans for calendar year 2004.
Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the Medicare Act)
The passage of the Medicare Act introduces a prescription drug benefit under Medicare, as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. Certain accounting issues raised by the Medicare Act, such as the federal subsidy, are not explicitly addressed by current accounting standards. Therefore, PSEG elected to defer accounting per the implementation of the Medicare Act until official guidance is issued by the FASB. As such, the reported Accumulated Postretirement Benefit Obligation, and the net period postretirement benefit cost do not reflect the effects of the Medicare Act. The impact of this Act is expected to be an immaterial benefit. When specific authoritative guidance is issued it could require PSEG to change previously reported information.
Accumulated Benefit Obligations
The accumulated benefit obligations of all PSEG’s defined benefit pension plans as of December 31, 2003, and 2002 were $2.7 billion and $2.5 billion, respectively.
183
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table provides a reconciliation of the changes in the fair value of plan assets over each of the two years in the period ended December 31, 2003 and a reconciliation of the funded status at the end of both years.
Pension and Other Postretirement Benefit Plans
| | Pension Benefits | | Other Benefits | |
| |
| |
| |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| | (Millions) | |
Change in Benefit Obligation: | | | | | | | | | | | | | |
Benefit Obligation at Beginning of Year | | $ | 2,968 | | $ | 2,676 | | $ | 777 | | $ | 674 | |
Service Cost | | | 74 | | | 69 | | | 21 | | | 18 | |
Interest Cost | | | 195 | | | 188 | | | 51 | | | 47 | |
Actuarial Loss | | | 158 | | | 162 | | | 117 | | | 84 | |
Benefits Paid | | | (160 | ) | | (156 | ) | | (50 | ) | | (48 | ) |
Plan Amendments | | | — | | | 7 | | | — | | | — | |
Business Combinations | | | — | | | 22 | | | — | | | 2 | |
| |
|
| |
|
| |
|
| |
|
| |
Benefit Obligation at End of Year | | | 3,235 | | | 2,968 | | | 916 | | | 777 | |
| |
|
| |
|
| |
|
| |
|
| |
Change in Plan Assets: | | | | | | | | | | | | | |
Fair Value of Assets at Beginning of Year | | | 2,131 | | | 2,228 | | | 51 | | | 40 | |
Actual Return on Plan Assets | | | 514 | | | (192 | ) | | 13 | | | (3 | ) |
Employer Contributions | | | 211 | | | 240 | | | 63 | | | 61 | |
Benefits Paid | | | (160 | ) | | (156 | ) | | (50 | ) | | (48 | ) |
Business Combinations | | | — | | | 11 | | | — | | | 1 | |
| |
|
| |
|
| |
|
| |
|
| |
Fair Value of Assets at End of Year | | | 2,696 | | | 2,131 | | | 77 | | | 51 | |
| |
|
| |
|
| |
|
| |
|
| |
Reconciliation of Funded Status: | | | | | | | | | | | | | |
Funded Status | | | (539 | ) | | (837 | ) | | (839 | ) | | (726 | ) |
Unrecognized Net | | | | | | | | | | | | | |
Transition Obligation | | | — | | | 5 | | | 221 | | | 248 | |
Prior Service Cost | | | 94 | | | 104 | | | — | | | — | |
(Gain) Loss | | | 784 | | | 1,003 | | | 87 | | | (25 | ) |
| |
|
| |
|
| |
|
| |
|
| |
Net Amount Recognized | | $ | 339 | | $ | 275 | | $ | (531 | ) | $ | (503 | ) |
| |
|
| |
|
| |
|
| |
|
| |
Amounts Recognized in Statement of Financial Position: | | | | | | | | | | | | | |
Prepaid Benefit Cost | | $ | 379 | | $ | 3 | | $ | — | | $ | — | |
Accrued Cost | | | (67 | ) | | (343 | ) | | (531 | ) | | (503 | ) |
Intangible Asset | | | 14 | | | 114 | | | N/A | | | N/A | |
Accumulated Other Comprehensive Income (pre-tax) | | | 13 | | | 501 | | | N/A | | | N/A | |
| |
|
| |
|
| |
|
| |
|
| |
Net Amount Recognized | | $ | 339 | | $ | 275 | | $ | (531 | ) | $ | (503 | ) |
| |
|
| |
|
| |
|
| |
|
| |
Separate Disclosure for Pension Plans With an Accumulated Benefit Obligation in Excess of Plan Assets: | | | | | | | | | | | | | |
Projected Benefit Obligation at End of Year | | $ | 86 | | $ | 2,946 | | | | | | | |
Accumulated Benefit Obligation at End of Year | | $ | 67 | | $ | 2,451 | | | | | | | |
Fair Value of Assets at End of Year | | $ | — | | $ | 2,113 | | | | | | | |
184
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The pension benefits table above provides information relating to the funded status of all qualified and nonqualified pension plans and other postretirement benefit plans on an aggregate basis.
| | Pension Benefits | | Other Benefits | |
| |
| |
| |
| | 2003 | | 2002 | | 2001 | | 2003 | | 2002 | | 2001 | |
| | (Millions) | |
Components of Net Periodic Benefit Cost: | | | | | | | | | | | | | | | | | | | |
Service Cost | | $ | 74 | | $ | 69 | | $ | 63 | | $ | 21 | | $ | 19 | | $ | 16 | |
Interest Cost | | | 195 | | | 188 | | | 182 | | | 51 | | | 47 | | | 47 | |
Expected Return on Plan Assets | | | (193 | ) | | (206 | ) | | (211 | ) | | (5 | ) | | (4 | ) | | (3 | ) |
Amortization of Net | | | | | | | | | | | | | | | | | | | |
Transition Obligation | | | 5 | | | 8 | | | 8 | | | 27 | | | 27 | | | 27 | |
Prior Service Cost | | | 17 | | | 17 | | | 16 | | | — | | | — | | | — | |
(Gain)/Loss | | | 49 | | | 13 | | | — | | | (3 | ) | | (4 | ) | | (6 | ) |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Net Periodic Benefit Cost | | $ | 147 | | $ | 89 | | $ | 58 | | $ | 91 | | $ | 85 | | $ | 81 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Components of Total Benefit Expense: | | | | | | | | | | | | | | | | | | | |
Net Periodic Benefit Cost | | $ | 147 | | $ | 89 | | $ | 58 | | $ | 91 | | $ | 85 | | $ | 81 | |
Effect of Regulatory Asset | | | — | | �� | — | | | — | | | 19 | | | 19 | | | 19 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Total Benefit Expense Including Effect of Regulatory Asset | | $ | 147 | | $ | 89 | | $ | 58 | | $ | 110 | | $ | 104 | | $ | 100 | |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| |
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Cost for Years Ended December 31: | | | | | | | | | | | | | | | | | | | |
Discount Rate | | | 6.75 | % | | 7.25 | % | | 7.50 | % | | 6.75 | % | | 7.25 | % | | 7.50 | % |
Expected Return on Plan Assets | | | 9.00 | % | | 9.00 | % | | 9.00 | % | | 9.00 | % | | 9.00 | % | | 9.00 | % |
Rate of Compensation Increase | | | 4.69 | % | | 4.69 | % | | 4.69 | % | | 4.69 | % | | 4.69 | % | | 4.69 | % |
Weighted-Average Assumptions Used to Determine Benefit | | | | | | | | | | | | | | | | | | | |
Obligations as of December 31: | | | | | | | | | | | | | | | | | | | |
Discount Rate | | | 6.25 | % | | 6.75 | % | | 7.25 | % | | 6.25 | % | | 6.75 | % | | 7.25 | % |
Rate of Compensation Increase | | | 4.69 | % | | 4.69 | % | | 4.69 | % | | 4.69 | % | | 4.69 | % | | 4.69 | % |
Rate of Increase in Health Benefit Costs | | | | | | | | | | | | | | | | | | | |
Administrative Expense | | | | | | | | | | | | 5.00 | % | | 5.00 | % | | 5.00 | % |
Dental Costs | | | | | | | | | | | | 6.00 | % | | 6.00 | % | | 6.00 | % |
Pre-65 Medical Costs | | | | | | | | | | | | | | | | | | | |
Immediate Rate | | | | | | | | | | | | 9.00 | % | | 9.00 | % | | 9.50 | % |
Ultimate Rate | | | | | | | | | | | | 6.00 | % | | 6.00 | % | | 6.00 | % |
Year Ultimate Rate Reached | | | | | | | | | | | | 2010 | | | 2008 | | | 2008 | |
Post-65 Medical Costs | | | | | | | | | | | | | | | | | | | |
Immediate Rate | | | | | | | | | | | | 7.00 | % | | 7.00 | % | | 7.50 | % |
Ultimate Rate | | | | | | | | | | | | 6.00 | % | | 6.00 | % | | 6.00 | % |
Year Ultimate Rate Reached | | | | | | | | | | | | 2006 | | | 2004 | | | 2004 | |
Effect of a Change in the Assumed Rate of Increase in Health Benefit Costs: | | | | | | | | | | | | | | | | | | | |
Effect of a 1% Increase On | | | | | | | | | | | | | | | | | | | |
Total of Service Cost and Interest Cost | | | | | | | | | | | $ | 4 | | $ | 5 | | $ | 5 | |
Postretirement Benefit Obligation | | | | | | | | | | | $ | 51 | | $ | 46 | | $ | 45 | |
Effect of a 1% Decrease On | | | | | | | | | | | | | | | | | | | |
Total of Service Cost and Interest Cost | | | | | | | | | | | $ | (5 | ) | $ | (4 | ) | $ | (4 | ) |
Postretirement Benefit Obligation | | | | | | | | | | | $ | (59 | ) | $ | (39 | ) | $ | (39 | ) |
185
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Cash Flows
Estimated Future Benefit Payments (Reflecting Expected Future Service)
The following benefit payments, which reflect expected future service, are expected to be paid:
Year | | Pension
Benefits | | Other
Benefits | |
| | (Millions) | |
2004 | | | $ | 164 | | | | $ | 51 | | |
2005 | | | | 168 | | | | | 53 | | |
2006 | | | | 173 | | | | | 54 | | |
2007 | | | | 178 | | | | | 56 | | |
2008 | | | | 185 | | | | | 57 | | |
2009–2013 | | | | 1,100 | | | | | 337 | | |
Total | | | $ | 1,968 | | | | $ | 608 | | |
401K Plans
PSEG sponsors two 401(k) plans, which are Employee Retirement Income Security Act (ERISA) defined contribution plans. Eligible represented employees of PSE&G, Power and Services participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSE&G, Power, Energy Holdings and Services participate in the PSEG Thrift and Tax-Deferred Savings Plan (Thrift Plan). Eligible employees may contribute up to 50% of their compensation to these plans. Employee contributions up to 7% for Savings Plan participants and up to 8% for Thrift Plan participants are matched with employer contributions of cash equal to 50% of such employee contributions. For periods prior to March 1, 2002, employer contributions, related to participant contributions in excess of 5% and up to 7%, were made in shares of PSEG Common Stock for Savings Plan participants. For periods prior to March 1, 2002, Employer contributions, related to participant contributions in excess of 6% and up to 8%, were made in shares of PSEG Common Stock for Thrift Plan participants. The shares for these contributions were purchased in the open market. Since that time, all Employer contributions have been made in cash. The amount expensed for Employer matching contributions to the plans was approximately $25 million, $25 million, and $24 million in 2003, 2002, and 2001, respectively.
PSE&G, Power, Energy Holdings and Services eligible employees participate in non-contributory pension and OPEB plans sponsored by PSEG and administered by Services. In addition, represented and nonrepresented employees are eligible for participation in PSEG’s two defined contribution plans described above.
PSE&G
PSE&G’s pension costs amounted to $79 million, $46 million and $30 million for the years ended December 31, 2003, 2002 and 2001, respectively. For 2003, this amount represented approximately 54% of PSEG’s total consolidated pension costs. PSE&G’s Thrift Plan and Savings Plan matching costs amounted to approximately $13 million, $13 million and $12 million for the years ended December 31, 2003, 2002 and 2001, respectively. PSE&G’s OPEB costs amounted to $100 million, $95 million and $95 million for the years ended December 31, 2003, 2002 and 2001, respectively. For 2003, this amount represented approximately 90% of PSEG’s total consolidated OPEB costs.
Power
Power’s pension costs amounted to $46 million, $26 million and $16 million for the years ended December 31, 2003, 2002 and 2001, respectively. For 2003, this amount represented approximately 31% of PSEG’s total consolidated pension costs. Power’s Thrift Plan and Savings Plan matching costs amounted to approximately $9 million, $8 million and $8 million for the years ended December 31,
186
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
2003, 2002 and 2001, respectively. Power’s OPEB costs amounted to $8 million, $6 million and $4 million for the years ended December 31, 2003, 2002 and 2001, respectively. For 2003, this amount represented approximately 7% of PSEG’s total consolidated OPEB costs.
Energy Holdings
Energy Holdings’ pension costs amounted to $4 million, $2 million and $1 million for the years ended December 31, 2003, 2002 and 2001, respectively. For 2003, this amount represented approximately 3% of PSEG’s total consolidated pension costs. Energy Holdings’ Thrift Plan and Savings Plan matching costs amounted to approximately $1 million for each of the years ended December 31, 2003, 2002 and 2001. Energy Holdings OPEB costs amounted to less than $1 million for each of the years ended December 31, 2003, 2002 and 2001.
Note 22. Stock Options and Employee Stock Purchase Plan
PSEG
Stock Options
Under PSEG’s 1989 Long-Term Incentive Plan (1989 LTIP) and its 2001 Long-Term Incentive Plan (2001 LTIP), non-qualified options to acquire shares of Common Stock may be granted to officers and other key employees of PSEG, PSE&G, Power, Energy Holdings, Services and their respective subsidiaries selected by the Organization and Compensation Committee of PSEG’s Board of Directors, the plan’s administrative committee (Committee). In addition, certain key executives have received option grants under the 1989 LTIP in connection with their employment agreements. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the Committee, by delivering previously acquired shares of PSEG Common Stock. In instances where an optionee tenders shares acquired from a grant previously exercised that were held for a period of less than six months, an expense will be recorded for the difference between the fair market value at exercise date and the option price. Options are exercisable over a period of time designated by the Committee (but not prior to one year or longer than ten years from the date of grant) and are subject to such other terms and conditions as the Committee determines. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change in control. Options may not be transferred during the lifetime of a holder.
The 1989 LTIP currently provides for the issuance of up to 8,000,000 options to purchase shares of common stock. As of December 31, 2003, there were 4,232,717 options available for future grants under the 1989 LTIP.
The 2001 LTIP currently provides for the issuance of up to 15,000,000 options to purchase shares of common stock. As of December 31, 2003, there were 8,742,433 options available for future grants under the 2001 LTIP.
PSEG purchases shares on the open market to meet the exercise of stock options. The difference between the cost of the shares (generally purchased on the date of exercise) and the exercise price of the options has been reflected in Stockholders’ Equity except where otherwise discussed.
187
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Changes in common shares under option for the three fiscal years in the period ended December 31, 2003 are summarized as follows:
| | 2003 | | 2002 | | 2001 | |
| | Options | | Weighted
Average
Exercise
Price | | Options | | Weighted
Average
Exercise
Price | | Options | | Weighted
Average
Exercise
Price | |
Beginning of year | | | 9,192,631 | | | $ | 39.32 | | | 7,652,463 | | | $ | 41.22 | | | 5,186,099 | | | $ | 40.38 | | |
Granted | | | 706,300 | | | | 37.35 | | | 1,890,000 | | | | 31.62 | | | 2,833,000 | | | | 41.84 | | |
Exercised | | | (541,767 | ) | | | 32.76 | | | (157,332 | ) | | | 36.28 | | | (303,135 | ) | | | 32.83 | | |
Canceled | | | (622,233 | ) | | | 42.01 | | | (192,500 | ) | | | 41.94 | | | (63,501 | ) | | | 41.27 | | |
End of year | | | 8,734,931 | | | | 39.37 | | | 9,192,631 | | | | 39.32 | | | 7,652,463 | | | | 41.22 | | |
Exercisable at end of year | | | 5,822,196 | | | $ | 40.44 | | | 4,542,165 | | | $ | 40.24 | | | 2,767,830 | | | $ | 39.19 | | |
Weighted average fair value of options granted during the year | | | | | | $ | 5.73 | | | | | | $ | 4.37 | | | | | | $ | 7.22 | | |
The following table provides information about options outstanding as of December 31, 2003:
| | Options Outstanding | | Options Exercisable | |
Range of
Exercise Prices | | Outstanding at
December 31,
2003 | | Weighted
Average
Remaining
Contractual
Life | | Weighted
Average
Exercise
Price | | Exercisable at
December 31,
2003 | | Weighted
Average
Exercise
Price | |
$25.03-$30.02 | | 135,000 | | 4.0 years | | $ 29.56 | | | 135,000 | | $ 29.56 | |
$30.03-$35.03 | | 2,741,932 | | 8.2 years | | 32.26 | | | 1,307,708 | | 32.42 | |
$35.04-$40.03 | | 649,167 | | 5.3 years | | 39.11 | | | 599,167 | | 39.31 | |
$40.04-$45.04 | | 3,041,332 | | 7.9 years | | 41.52 | | | 1,916,154 | | 41.56 | |
$45.05-$50.05 | | 2,167,500 | | 7.1 years | | 46.06 | | | 1,864,167 | | 46.06 | |
$25.03-$50.05 | | 8,734,931 | | 7.6 years | | $ 39.37 | | | 5,822,196 | | $ 40.44 | |
| | | | | | | | | | | | | |
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model with the following weighted average assumptions used for grants in 2003, 2002 and 2001, respectively are: expected volatility of 29.68%, 30.24% and 28.22%, risk free interest rates of 2.86%, 2.82% and 4.40%, expected lives of 4.4, 4.0 years and 4.2 years. There was a dividend yield of 5.82% in 2003, 6.84% in 2002 and 5.18% in 2001.
Stock Compensation
Executive Officers
In June 1998, the Committee granted 150,000 shares of restricted common stock to a key executive. An additional 60,000 shares of restricted stock was granted to this executive in November 2001. These shares are subject to restrictions on transfer and subject to risk of forfeiture until earned by continued employment. The shares vest on a staggered schedule beginning on March 31, 2002 and become fully vested on March 31, 2007. As the shares vest, the earned compensation is recorded as compensation expense in the Consolidated Statements of Operations. The unearned compensation related to this restricted stock grant as of December 31, 2003 is approximately $2 million and is included in Stockholders’ Equity on the Consolidated Balance Sheets.
In addition, in July 2001, the Committee granted 100,000 shares of restricted common stock to another key executive. These shares are subject to restrictions on transfer and subject to risk of forfeiture until earned by continued employment. The shares vest at one-third per year and become fully vested on July 1, 2004. As the shares vest, the earned compensation is recorded as compensation expense in the Consolidated Statements of Operations. The unearned compensation related to this
188
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
restricted stock grant as of December 31, 2003 is approximately $1 million and is included in Stockholders’ Equity on the Consolidated Balance Sheets.
Outside Directors
During 2003, each director who was not an officer of PSEG or its subsidiaries and affiliates was paid an annual retainer of $40,000. Pursuant to the Compensation Plan for Outside Directors, a certain percentage, currently fifty percent, of the annual retainer is paid in PSEG Common Stock. In January 2003, PSEG amended the Compensation Plan for Outside Directors to provide for 100,000 shares of Common Stock to be used for awards to directors of PSEG who are not employees of PSEG or its subsidiaries.
PSEG also maintains a Stock Plan for Outside Directors pursuant to which directors of PSEG who are not employees of PSEG or its subsidiaries receive a restricted stock award, currently 800 shares per year, for each year of service as a director. The restrictions on the stock granted under the Stock Plan for Outside Directors provide that the shares are subject to forfeiture if the director leaves service at any time prior to the Annual Meeting of Stockholders following his or her 70th birthday. This restriction would be deemed to have been satisfied if the director’s service were terminated after a “change in control” as defined in the Plan or if the director were to die in office. PSEG also has the ability to waive this restriction for good cause shown. Restricted stock may not be sold or otherwise transferred prior to the lapse of the restrictions. Dividends on shares held subject to restrictions are paid directly to the director who has the right to vote the shares. The fair value of these shares is recorded as compensation expense in the Consolidated Statements of Operations.
Employee Stock Purchase Plan
PSEG maintains an employee stock purchase plan for all eligible employees of PSEG, PSE&G, Power, Energy Holdings and Services. Under the plan, shares of the common stock may be purchased at 95% of the fair market value through payroll deductions. Employees may purchase shares having a value not exceeding 10% of their base pay. During 2003, 2002 and 2001, employees purchased 102,532, 104,627 and 85,552 shares at an average price of $40.00, $36.41 and $44.02 per share, respectively. In June 2003, an additional 2,120,485 shares were registered for this plan. As of December 31, 2003, 2,065,521 shares were available for future issuance under this plan.
Note 23. Financial Information by Business Segment
Basis of Organization
PSEG, PSE&G, Power and Energy Holdings
The reportable segments were determined by management in accordance with SFAS No. 131, “Disclosures About Segments of an Enterprise and Related Information” (SFAS 131). These segments were determined based on how management measures the performance based on segment net income, as illustrated in the following table, and how it allocates resources to each business.
Power
Power earns revenues by selling energy, capacity and ancillary services on a wholesale basis under contract to power marketers and to load serving entities and by bidding the energy, capacity and ancillary services into the market. Power also enters into trading contracts for energy capacity, firm transmission rights, gas, emission allowances and other energy related contracts to optimize the value of its portfolio of generating assets and its electric and gas supply obligations.
189
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSE&G
PSE&G earns revenue from its tariffs under which it provides electric transmission and electric and gas distribution services to residential, commercial and industrial customers in New Jersey. The rates charged for electric transmission are regulated by FERC while the rates charged for electric and gas distribution are regulated by the BPU. Revenues are also earned from several other activities such as sundry sales, the appliance service business, wholesale transmission services and other miscellaneous services.
Energy Holdings
Global
Global earns revenues from its investment in and operation of projects in the generation and distribution of energy, both domestically and internationally. Global has ownership interests in four distribution companies and has developed or acquired interests in electric generation facilities which sell energy, capacity and ancillary services to numerous customers. The generation plants sell power under long-term agreements as well as on a merchant basis while the distribution companies are rate-regulated enterprises.
Resources
Resources earns revenues from its passive investments in leveraged leases, limited partnerships, leveraged buyout funds and marketable securities. Over 80% of Resources’ investments are in energy industry related leveraged leases. DSM Investments were transferred to Resources on December 31, 2002 and earn revenues primarily from monthly payments from utilities, representing shared electricity savings from the installation of energy efficient equipment. Resources operates both domestically and internationally, however, revenues from all international investments are denominated in U.S. dollars.
Other
Energy Holdings’ other activities include amounts applicable to Energy Holdings (parent company), the HVAC/operating companies of Energy Technologies, which were reclassified into discontinued operations in 2002 and sold in 2003, and EGDC. The net losses primarily relate to financing and certain administrative and general costs at the Energy Holdings parent corporation.
Other
PSEG’s other activities include amounts applicable to PSEG (parent corporation), and intercompany eliminations, primarily relating to intercompany transactions between Power and PSE&G. No gains or losses are recorded on any intercompany transactions, rather, all intercompany transactions are at cost or, in the case of the BGS and Basic Gas Supply Service (BGSS) contracts between Power and PSE&G, at rates prescribed by the BPU. For a further discussion of the intercompany transactions between Power and PSE&G, see Note 26. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs at the PSEG parent corporation.
190
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Information related to the segments of PSEG’s and its subsidiaries is detailed below:
| | Power | | PSE&G | | | Energy Holdings | | | | Consolidated
Total | |
| | | | | Resources | | | Global | | Other | | Other | | |
| | | | | | | | | | | | | | | | (Millions) | | | | | | | | | | | | | |
For the Year Ended December 31, 2003: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Operating Revenues | | $ | 5,605 | | | $ | 6,740 | | | | $ | 238 | | | | $ | 476 | | | $ | 11 | | | $ | (1,954 | ) | | $ | 11,116 | | |
Depreciation and Amortization | | | 102 | | | | 372 | | | | | 5 | | | | | 38 | | | | 1 | | | | 9 | | | | 527 | | |
Operating Income (Loss) | | | 843 | | | | 761 | | | | | 206 | | | | | 263 | | | | (5 | ) | | | 11 | | | | 2,079 | | |
Interest Income | | | 7 | | | | (7 | ) | | | | — | | | | | — | | | | — | | | | 1 | | | | 1 | | |
Net Interest Charges | | | 114 | | | | 390 | | | | | 96 | | | | | 119 | | | | 3 | | | | 114 | | | | 836 | | |
Income (Loss) Before Income Taxes | | | 800 | | | | 376 | | | | | 109 | | | | | 158 | | | | (6 | ) | | | (121 | ) | | | 1,316 | | |
Income Taxes | | | 326 | | | | 129 | | | | | 37 | | | | | 23 | | | | (1 | ) | | | (50 | ) | | | 464 | | |
Income from Equity Method Investments | | | — | | | | — | | | | | 1 | | | | | 113 | | | | — | | | | — | | | | 114 | | |
Income (Loss) From Continuing Operations | | | 474 | | | | 247 | | | | | 72 | | | | | 121 | | | | (4 | ) | | | (58 | ) | | | 852 | | |
Loss from Discontinued Operations, net of tax | | | — | | | | — | | | | | — | | | | | (23 | ) | | | (21 | ) | | | — | | | | (44 | ) | |
Extraordinary Item, net of tax | | | — | | | | (18 | ) | | | | — | | | | | — | | | | — | | | | — | | | | (18 | ) | |
Cumulative Effect of a Change in Accounting Principle, net of tax | | | 370 | | | | — | | | | | — | | | | | — | | | | — | | | | — | | | | 370 | | |
Net Income (Loss) | | | 844 | | | | 229 | | | | | 72 | | | | | 98 | | | | (25 | ) | | | (58 | ) | | | 1,160 | | |
Segment Earnings (Loss) | | | 844 | | | | 225 | | | | | 66 | | | | | 81 | | | | (25 | ) | | | (31 | ) | | | 1,160 | | |
Gross Additions to Long-Lived Assets | | $ | 655 | | | $ | 411 | | | | $ | 1 | | | | $ | 306 | | | $ | — | | | $ | (3 | ) | | $ | 1,370 | | |
As of December 31, 2003: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 7,728 | | | $ | 13,136 | | | | $ | 3,277 | | | | $ | 3,814 | | | $ | 366 | | | $ | (266 | ) | | $ | 28,055 | | |
Investments in Equity Method Subsidiaries | | $ | — | | | $ | — | | | | $ | 94 | | | | $ | 1,472 | | | $ | 4 | | | $ | — | | | $ | 1,570 | | |
For the Year Ended December 31, 2002: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Operating Revenues | | $ | 3,636 | | | $ | 5,919 | | | | $ | 248 | | | | $ | 352 | | | $ | 9 | | | $ | (1,948 | ) | | $ | 8,216 | | |
Depreciation and Amortization | | | 108 | | | | 409 | | | | | 5 | | | | | 22 | | | | 1 | | | | 20 | | | | 565 | | |
Operating Income (Loss) | | | 903 | | | | 713 | | | | | 213 | | | | | (300 | ) | | | (10 | ) | | | 4 | | | | 1,523 | | |
Interest Income | | | — | | | | 4 | | | | | — | | | | | — | | | | — | | | | — | | | | 4 | | |
Net Interest Charges | | | 122 | | | | 406 | | | | | 98 | | | | | 118 | | | | 1 | | | | 74 | | | | 819 | | |
Income (Loss) Before Income Taxes | | | 781 | | | | 320 | | | | | 122 | | | | | (476 | ) | | | (11 | ) | | | (77 | ) | | | 659 | | |
Income Taxes | | | 313 | | | | 115 | | | | | 38 | | | | | (178 | ) | | | (4 | ) | | | (30 | ) | | | 254 | | |
Income from Equity Method Investments | | | — | | | | — | | | | | (1 | ) | | | | 120 | | | | — | | | | — | | | | 119 | | |
Income (Loss) From Continuing Operations | | | 468 | | | | 205 | | | | | 84 | | | | | (297 | ) | | | (7 | ) | | | (48 | ) | | | 405 | | |
Loss from Discontinued Operation, net of tax | | | — | | | | — | | | | | — | | | | | (9 | ) | | | (40 | ) | | | — | | | | (49 | ) | |
Cumulative Effect of a Change in Accounting Principle, net of tax | | | — | | | | — | | | | | — | | | | | (88 | ) | | | (33 | ) | | | — | | | | (121 | ) | |
Net Income (Loss) | | | 468 | | | | 205 | | | | | 84 | | | | | (395 | ) | | | (79 | ) | | | (48 | ) | | | 235 | | |
Segment Earnings (Loss) | | | 468 | | | | 201 | | | | | 78 | | | | | (411 | ) | | | (80 | ) | | | (21 | ) | | | 235 | | |
Gross Additions to Long-Lived Assets | | $ | 1,046 | | | $ | 472 | | | | $ | 1 | | | | $ | 294 | | | $ | 9 | | | $ | (35 | ) | | $ | 1,787 | | |
As of December 31, 2002: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Assets | | $ | 7,217 | | | $ | 12,841 | | | | $ | 3,086 | | | | $ | 3,696 | | | $ | (27 | ) | | $ | (678 | ) | | $ | 26,135 | | |
Investments in Equity Method Subsidiaries | | $ | — | | | $ | — | | | | $ | 118 | | | | $ | 1,210 | | | $ | 4 | | | $ | — | | | $ | 1,332 | | |
For the Year Ended December 31, 2001: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total Operating Revenues | | $ | 2,464 | | | $ | 6,091 | | | | $ | 240 | | | | $ | 204 | | | $ | 10 | | | $ | (2,126 | ) | | $ | 6,883 | | |
Depreciation and Amortization | | | 95 | | | | 370 | | | | | 4 | | | | | 11 | | | | — | | | | 15 | | | | 495 | | |
Operating Income | | | 787 | | | | 691 | | | | | 211 | | | | | 232 | | | | (10 | ) | | | (3 | ) | | | 1,908 | | |
Interest Income | | | — | | | | 88 | | | | | — | | | | | — | | | | — | | | | (66 | ) | | | 22 | | |
Net Interest Charges | | | 143 | | | | 458 | | | | | 100 | | | | | 81 | | | | 2 | | | | (8 | ) | | | 776 | | |
Income Before Income Taxes | | | 644 | | | | 324 | | | | | 111 | | | | | 135 | | | | (9 | ) | | | (66 | ) | | | 1,139 | | |
Income Taxes | | | 250 | | | | 89 | | | | | 34 | | | | | 29 | | | | (5 | ) | | | (24 | ) | | | 373 | | |
Income from Equity Method Investments | | | — | | | | — | | | | | — | | | | | 178 | | | | — | | | | — | | | | 178 | | |
Income (Loss) From Continuing Operations | | | 394 | | | | 235 | | | | | 77 | | | | | 106 | | | | (4 | ) | | | (42 | ) | | | 766 | | |
Income (Loss) from Discontinued Operations, net of tax | | | — | | | | — | | | | | — | | | | | 11 | | | | (23 | ) | | | — | | | | (12 | ) | |
Cumulative Effect of a Change in Accounting Principle, net of tax | | | — | | | | — | | | | | — | | | | | 10 | | | | — | | | | — | | | | 10 | | |
Net Income (Loss) | | | 394 | | | | 235 | | | | | 77 | | | | | 127 | | | | (27 | ) | | | (42 | ) | | | 764 | | |
Segment Earnings (Loss) | | | 394 | | | | 230 | | | | | 71 | | | | | 110 | | | | (27 | ) | | | (14 | ) | | | 764 | | |
Gross Additions to Long-Lived Assets | | $ | 1,592 | | | $ | 395 | | | | $ | 1 | | | | $ | 240 | | | $ | — | | | $ | 387 | | | $ | 2,615 | | |
191
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Geographic information for PSEG is disclosed below. The foreign assets and operations noted below were made solely through Energy Holdings.
| | Revenues(A) | | Assets(B) | |
| |
| |
| |
| | December 31, | | December 31, |
| | 2003 | | 2002 | | 2001 | | 2003 | | 2002 | |
| | (Millions) | |
United States | $ | 10,565 | | $ | 7,736 | | $ | 6,516 | | $ | 23,457 | | $ | 22,068 | |
Foreign Countries | | 551 | | | 480 | | | 367 | | | 4,598 | | | 4,067 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
Total | $ | 11,116 | | $ | 8,216 | | $ | 6,883 | | $ | 28,055 | | $ | 26,135 | |
|
|
| |
|
| |
|
| |
|
| |
|
| |
Identifiable assets in foreign countries include: | | | | | |
Chile | | $ | 1,151 | | $ | 1,053 | |
Netherlands | | | 1,060 | | | 988 | |
Peru | | | 475 | | | 429 | |
Tunisia | | | 300 | | | 313 | |
China | | | 202 | | | 172 | |
Oman | | | 282 | | | 160 | |
India | | | 39 | | | 38 | |
Poland | | | 466 | | | 480 | |
Brazil | | | 164 | | | 108 | |
Other | | | 459 | | | 326 | |
| |
|
| |
|
| |
| | | | | | | |
Total | | $ | 4,598 | | $ | 4,067 | |
| |
|
| |
|
| |
__________
| (A) | Revenues are attributed to countries based on the locations of the investments. Global’s revenue includes its share of the net income from joint ventures recorded under the equity method of accounting. |
| (B) | Total assets are net of foreign currency translation adjustment of $(270) million (pre-tax) as of December 31, 2003 and $(427) million (pre-tax) as of December 31, 2002. |
As of December 31, 2003, Global and Resources had approximately $3.2 billion and $1.4 billion, respectively of international assets. As of December 31, 2003, foreign assets represented 16% and 62% of PSEG’s and Energy Holdings’ consolidated assets, respectively, and the revenues related to those foreign assets contributed 5% and 76% to PSEG’s and Energy Holdings’ consolidated revenues, respectively, for the year ended December 31, 2003.
192
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 24. Property, Plant and Equipment and Jointly Owned Facilities
Information related to Property, Plant and Equipment as of December 31, 2003 and 2002 is detailed below:
| | PSE&G | | | Power | | | Energy
Holdings | | | Other | | PSEG
Consolidated | |
| | (Millions) | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
2003 | | | | | | | | | | | | | | | | | | | | | | | | | |
Generation: | | | | | | | | | | | | | | | | | | | | | | | | | |
Fossil Production | | $ | — | | | | $ | 3,019 | | | | $ | 729 | | | | $ | — | | | | $ | 3,748 | | |
Nuclear Production | | | — | | | | | 332 | | | | | — | | | | | — | | | | | 332 | | |
Nuclear Fuel in Service | | | — | | | | | 532 | | | | | — | | | | | — | | | | | 532 | | |
Construction Work in Progress | | | — | | | | | 2,020 | | | | | 17 | | | | | — | | | | | 2,037 | | |
| |
|
| | | |
|
| | | |
|
| | | |
|
| | | |
|
| | |
Total Generation | | | — | | | | | 5,903 | | | | | 746 | | | | | — | | | | | 6,649 | | |
| |
|
| | | |
|
| | | |
|
| | | |
|
| | | |
|
| | |
Transmission and Distribution: | | | | | | | | | | | | | | | | | | | | | | | | | |
Electric Transmission | | | 1,273 | | | | | — | | | | | 427 | | | | | — | | | | | 1,700 | | |
Electric Distribution | | | 4,646 | | | | | — | | | | | — | | | | | — | | | | | 4,646 | | |
Gas Transmission | | | 74 | | | | | — | | | | | — | | | | | — | | | | | 74 | | |
Gas Distribution | | | 3,430 | | | | | — | | | | | — | | | | | — | | | | | 3,430 | | |
Construction Work in Progress | | | 2 | | | | | — | | | | | 13 | | | | | — | | | | | 15 | | |
Plant Held for Future Use | | | 20 | | | | | — | | | | | — | | | | | — | | | | | 20 | | |
Other | | | 92 | | | | | — | | | | | — | | | | | — | | | | | 92 | | |
| |
|
| | | |
|
| | | |
|
| | | |
|
| | | |
|
| | |
Total Transmission and Distribution | | | 9,537 | | | | | — | | | | | 440 | | | | | — | | | | | 9,977 | | |
| |
|
| | | |
|
| | | |
|
| | | |
|
| | | |
|
| | |
Other | | | 256 | | | | | 77 | | | | | 176 | | | | | 271 | | | | | 780 | | |
| |
|
| | | |
|
| | | |
|
| | | |
|
| | | |
|
| | |
Total | | $ | 9,793 | | | | $ | 5,980 | | | | $ | 1,362 | | | | $ | 271 | | | | $ | 17,406 | | |
| |
|
| | | |
|
| | | |
|
| | | |
|
| | | |
|
| | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
2002 | | | | | | | | | | | | | | | | | | | | | | | | | |
Generation: | | | | | | | | | | | | | | | | | | | | | | | | | |
Fossil Production | | $ | — | | | | $ | 2,467 | | | | $ | 358 | | | | $ | — | | | | $ | 2,825 | | |
Nuclear Production | | | — | | | | | 215 | | | | | — | | | | | — | | | | | 215 | | |
Nuclear Fuel in Service | | | — | | | | | 527 | | | | | — | | | | | — | | | | | 527 | | |
Construction Work in Progress | | | — | | | | | 2,057 | | | | | 478 | | | | | — | | | | | 2,535 | | |
| |
|
| | | |
|
| | | |
|
| | | |
|
| | | |
|
| | |
Total Generation | | | — | | | | | 5,266 | | | | | 836 | | | | | — | | | | | 6,102 | | |
| |
|
| | | |
|
| | | |
|
| | | |
|
| | | |
|
| | |
Transmission and Distribution: | | | | | | | | | | | | | | | | | | | | | | | | | |
Electric Transmission | | | 1,243 | | | | | — | | | | | — | | | | | — | | | | | 1,243 | | |
Electric Distribution | | | 4,446 | | | | | — | | | | | 320 | | | | | — | | | | | 4,766 | | |
Gas Transmission | | | 74 | | | | | — | | | | | — | | | | | — | | | | | 74 | | |
Gas Distribution | | | 3,271 | | | | | — | | | | | — | | | | | — | | | | | 3,271 | | |
Construction Work in Progress | | | 20 | | | | | — | | | | | 27 | | | | | — | | | | | 47 | | |
Plant Held for Future Use | | | 18 | | | | | — | | | | | — | | | | | — | | | | | 18 | | |
Other | | | 91 | | | | | — | | | | | — | | | | | — | | | | | 91 | | |
| |
|
| | | |
|
| | | |
|
| | | |
|
| | | |
|
| | |
Total Transmission and Distribution | | | 9,163 | | | | | — | | | | | 347 | | | | | — | | | | | 9,510 | | |
| |
|
| | | |
|
| | | |
|
| | | |
|
| | | |
|
| | |
Other | | | 418 | | | | | 76 | | | | | 169 | | | | | 99 | | | | | 762 | | |
| |
|
| | | |
|
| | | |
|
| | | |
|
| | | |
|
| | |
Total | | $ | 9,581 | | | | $ | 5,342 | | | | $ | 1,352 | | | | $ | 99 | | | | $ | 16,374 | | |
| |
|
| | | |
|
| | | |
|
| | | |
|
| | | |
|
| | |
PSE&G and Power
PSE&G and Power have ownership interests in and are responsible for providing their share of the necessary financing for the following jointly owned facilities. All amounts reflect the share
193
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
of PSE&G’s and Power’s jointly owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as operating expenses.
| | Ownership
Interest | | Plant | | Accumulated
Depreciation |
| | (Millions, where Applicable) |
December 31, 2003 | | | | | | | | | | |
Power: | | | | | | | | | | |
Coal Generating | | | | | | | | | | |
Conemaugh | | 22.50 | % | $ | 204 | | $ | 83 | | |
Keystone | | 22.84 | % | $ | 167 | | $ | 62 | | |
Nuclear Generating | | | | | | | | | | |
Peach Bottom | | 50.00 | % | $ | 257 | | $ | 115 | | |
Salem | | 57.41 | % | $ | 435 | | $ | 202 | | |
Nuclear Support Facilities | | Various | | $ | 41 | | $ | 16 | | |
Pumped Storage Facilities | | | | | | | | | | |
Yards Creek | | 50.00 | % | $ | 28 | | $ | 16 | | |
Merrill Creek Reservoir | | 13.91 | % | $ | 2 | | $ | — | | |
PSE&G: | | | | | | | | | | |
Transmission Facilities | | Various | | $ | 80 | | $ | 35 | | |
Linden SNG Plant | | 90.00 | % | $ | 5 | | $ | 5 | | |
December 31, 2002 | | | | | | | | | | |
Power: | | | | | | | | | | |
Coal Generating | | | | | | | | | | |
Conemaugh | | 22.50 | % | $ | 203 | | $ | 76 | | |
Keystone. | | 22.84 | % | $ | 155 | | $ | 56 | | |
Nuclear Generating | | | | | | | | | | |
Peach Bottom | | 50.00 | % | $ | 225 | | $ | 105 | | |
Salem | | 57.41 | % | $ | 324 | | $ | 177 | | |
Nuclear Support Facilities | | Various | | $ | 34 | | $ | 13 | | |
Pumped Storage Facilities | | | | | | | | | | |
Yards Creek | | 50.00 | % | $ | 28 | | $ | 16 | | |
Merrill Creek Reservoir | | 13.91 | % | $ | 2 | | $ | — | | |
PSE&G: | | | | | | | | | | |
Transmission Facilities | | Various | | $ | 80 | | $ | 33 | | |
Linden SNG Plant | | 90.00 | % | $ | 5 | | $ | 5 | | |
Power
Power holds undivided ownership interests in the jointly owned facilities above, excluding related nuclear fuel and inventories. Power is entitled to shares of the generating capability and output of each unit equal to its respective ownership interests. Power also pays its ownership share of additional construction costs, fuel inventory purchases and operating expenses. Power’s share of expenses for the jointly owned facilities is included in the appropriate expense category.
Power’s subsidiary, Nuclear, co-owns Salem and Peach Bottom with Exelon. Nuclear is the owner-operator of Salem and Exelon is the operator of Peach Bottom. A committee appointed by the co-owners reviews/approves major planning, financing and budgetary (capital and operating) decisions. Operating decisions within the above guidelines are made by the owner-operator.
Reliant Resources is a co-owner and the operator for Keystone Generating Station and Conemaugh Generating Station. A committee appointed by all co-owners makes all planning, financing and budgetary (capital and operating) decisions. Operating decisions within the above guidelines are made by Reliant Resources.
194
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Power is a co-owner in the Yards Creek Pumped Storage Generation Facility. First Energy is also a co-owner and the operator of this facility. First Energy submits separate capital and Operations and Maintenance budgets, subject to the approval of Power.
Power is a minority owner in the Merrill Creek Reservoir. Merrill Creek Reservoir is the owner-operator of this facility. The operator submits separate capital and Operations and Maintenance budgets, subject to the approval of the non-operating owners.
All owners receive revenues, Operations and Maintenance and capital allocations based on their ownership percentages. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures.
Note 25. Selected Quarterly Data (Unaudited)
As discussed in Note 2. Restatement of Financial Statements, the Consolidated Financial Statements of PSEG and Energy Holdings have been restated. The unaudited quarterly data presented below and the Notes reflect the restated amounts for the current and prior periods.
The information shown below, in the opinion of PSEG, PSE&G, Power and Energy Holdings, includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts.
| | Calendar Quarter Ended | |
| | March 31 | | June 30 | | September 30, | | December 31, | |
| | As
Previously
Reported | | As
Restated | | As
Previously
Reported | | As
Restated | | As
Previously
Reported | | As
Restated | | | |
| | 2003 | | 2003 | | 2003 | | 2003 | | 2003 | | 2003 | | 2003 | |
| | (Millions, where Applicable) | |
PSEG Consolidated: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating Revenues | | $ | 3,364 | | | $ | 3,288 | | | $ | 2,419 | | | $ | 2,401 | | | $ | 2,805 | | | $ | 2,763 | | | $ | 2,664 | | |
Operating Income | | | 695 | | | | 693 | | | | 420 | | | | 418 | | | | 534 | | | | 525 | | | | 443 | | |
Income from Continuing Operations | | | 321 | | | | 324 | | | | 150 | | | | 156 | | | | 213 | | | | 208 | | | | 164 | | |
Loss from Discontinued Operations, including Loss on Disposal, net of tax | | | (15 | ) | | | (13 | ) | | | (2 | ) | | | (5 | ) | | | (3 | ) | | | (1 | ) | | | (25 | ) | |
Extraordinary Item, net of tax benefit | | | — | | | | — | | | | (18 | ) | | | (18 | ) | | | — | | | | — | | | | — | | |
Cumulative Effect of a Change in Accounting Principle | | | 370 | | | | 370 | | | | — | | | | — | | | | — | | | | — | | | | — | | |
Net Income | | | 676 | | | | 681 | | | | 130 | | | | 133 | | | | 210 | | | | 207 | | | | 139 | | |
Earnings Per Share: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
(Basic) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Income from Continuing Operations | | | 1.42 | | | | 1.44 | | | | 0.67 | | | | 0.69 | | | | 0.94 | | | | 0.92 | | | | 0.70 | | |
Net Income | | | 3.00 | | | | 3.03 | | | | 0.58 | | | | 0.59 | | | | 0.93 | | | | 0.92 | | | | 0.59 | | |
(Diluted) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Income from Continuing Operations | | | 1.42 | | | | 1.43 | | | | 0.66 | | | | 0.69 | | | | 0.93 | | | | 0.91 | | | | 0.69 | | |
Net Income | | | 3.00 | | | | 3.01 | | | | 0.57 | | | | 0.59 | | | | 0.92 | | | | 0.91 | | | | 0.59 | | |
Weighted Average Common Shares Outstanding: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Basic | | | 225 | | | | 225 | | | | 226 | | | | 226 | | | | 226 | | | | 226 | | | | 235 | | |
Diluted | | | 226 | | | | 226 | | | | 227 | | | | 227 | | | | 228 | | | | 228 | | | | 236 | | |
195
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | Calendar Quarter Ended | |
| | March 31, | | June 30, | | September 30, | | December 31, | |
| | As
Previously
Reported | | As
Restated | | As
Previously
Reported | | As
Restated | | As
Previously
Reported | | As
Restated | | As
Previously
Reported | | As
Restated | |
| | 2002 | | 2002 | | 2002 | | 2002 | | 2002 | | 2002 | | 2002 | | 2002 | |
| | (Millions, where Applicable) | |
PSEG Consolidated: | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating Revenues | | $ | 1,883 | | $ | 1,860 | | $ | 1,415 | | $ | 1,416 | | $ | 2,314 | | $ | 2,280 | | $ | 2,679 | | $ | 2,660 | |
Operating Income (Loss) | | | 541 | | | 531 | | | (125 | ) | | (123 | ) | | 529 | | | 529 | | | 588 | | | 586 | |
Income (Loss) from Continuing Operations | | | 181 | | | 172 | | | (227 | ) | | (228 | ) | | 207 | | | 205 | | | 255 | | | 256 | |
Loss from Discontinued Operations, including Loss on Disposal, net of tax | | | (1 | ) | | — | | | (37 | ) | | (38 | ) | | (3 | ) | | (1 | ) | | (10 | ) | | (10 | ) |
Cumulative Effect of a Change in Accounting Principle | | | (120 | ) | | (121 | ) | | — | | | — | | | — | | | — | | | — | | | — | |
Net Income (Loss) | | | 60 | | | 51 | | | (264 | ) | | (266 | ) | | 204 | | | 204 | | | 245 | | | 246 | |
Earnings Per Share: | | | | | | | | | | | | | | | | | | | | | | | | | |
(Basic) | | | | | | | | | | | | | | | | | | | | | | | | | |
Income (Loss) from Continuing Operations | | | 0.88 | | | 0.83 | | | (1.10 | ) | | (1.11 | ) | | 1.00 | | | 0.99 | | | 1.18 | | | 1.19 | |
Net Income (Loss) | | | 0.29 | | | 0.25 | | | (1.28 | ) | | (1.29 | ) | | 0.99 | | | 0.99 | | | 1.14 | | | 1.14 | |
(Diluted) | | | | | | | | | | | | | | | | | | | | | | | | | |
Income (Loss) from Continuing Operations | | | 0.88 | | | 0.83 | | | (1.10 | ) | | (1.11 | ) | | 1.00 | | | 0.99 | | | 1.18 | | | 1.19 | |
Net Income (Loss) | | | 0.29 | | | 0.25 | | | (1.28 | ) | | (1.29 | ) | | 0.99 | | | 0.99 | | | 1.14 | | | 1.14 | |
Weighted Average Common Shares Outstanding: | | | | | | | | | | | | | | | | | | | | | | | | | |
Basic | | | 206 | | | 206 | | | 206 | | | 206 | | | 207 | | | 207 | | | 216 | | | 216 | |
Diluted | | | 206 | | | 206 | | | 207 | | | 207 | | | 207 | | | 207 | | | 216 | | | 216 | |
| | Calendar Quarter Ended | |
| | March 31, | | June 30, | | September 30, | | December 31, | |
| | 2003 | | 2002 | | 2003 | | 2002 | | 2003 | | 2002 | | 2003 | | 2002 | |
| | (Millions) | |
PSE&G: | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating Revenues | | $ | 2,148 | | $ | 1,659 | | $ | 1,342 | | $ | 1,230 | | $ | 1,530 | | $ | 1,405 | | $ | 1,720 | | $ | 1,625 | |
Operating Income | | | 245 | | | 213 | | | 108 | | | 110 | | | 202 | | | 184 | | | 206 | | | 206 | |
Income from Continuing Operations | | | 101 | | | 68 | | | 22 | | | 8 | | | 69 | | | 56 | | | 55 | | | 73 | |
Extraordinary Item, net of tax benefit | | | — | | | — | | | (18 | ) | | — | | | — | | | — | | | — | | | — | |
Net Income | | | 101 | | | 68 | | | 4 | | | 8 | | | 69 | | | 56 | | | 55 | | | 73 | |
Earnings Available to PSEG | | | 100 | | | 67 | | | 3 | | | 7 | | | 68 | | | 55 | | | 54 | | | 72 | |
| | Calendar Quarter Ended | |
| | March 31, | | June 30, | | September 30, | | December 31, | |
| | 2003 | | 2002 | | 2003 | | 2002 | | 2003 | | 2002 | | 2003 | | 2002 | |
| | | (Millions) | |
Power: | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating Revenues | | $ | 1,830 | | $ | 560 | | $ | 1,235 | | $ | 674 | | $ | 1,255 | | $ | 1,093 | | $ | 1,285 | | $ | 1,309 | |
Operating Income | | | 314 | | | 228 | | | 196 | | | 173 | | | 202 | | | 239 | | | 131 | | | 263 | |
Income from Continuing Operations | | | 177 | | | 120 | | | 109 | | | 83 | | | 110 | | | 121 | | | 78 | | | 144 | |
Cumulative Effect of a Change in Accounting Principle | | | 370 | | | — | | | — | | | — | | | — | | | — | | | — | | | — | |
Net Income | | | 547 | | | 120 | | | 109 | | | 83 | | | 110 | | | 121 | | | 78 | | | 144 | |
196
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | Calendar Quarter Ended | |
| | March 31, | | June 30, | | September 30, | | December 31, | |
| | As
Previously
Reported | | As
Restated | | As
Previously
Reported | | As
Restated | | As
Previously
Reported | | As
Restated | | | |
| | 2003 | | 2003 | | 2003 | | 2003 | | 2003 | | 2003 | | 2003 | |
| | (Millions) | |
Energy Holdings: | | | | | | | | | | | | | | | | | | | | | | |
Operating Revenues | | $ | 209 | | $ | 190 | | $ | 188 | | $ | 171 | | $ | 211 | | $ | 178 | | $ | 186 | |
Operating Income | | | 134 | | | 132 | | | 112 | | | 110 | | | 128 | | | 118 | | | 104 | |
Income Before Discontinued Operations and Cumulative Effect of a Change in Accounting Principle | | | 59 | | | 62 | | | 33 | | | 39 | | | 48 | | | 43 | | | 45 | |
Loss From Discontinued Operations, including Loss on Disposal, net of tax benefit | | | (15 | ) | | (14 | ) | | (2 | ) | | (5 | ) | | (3 | ) | | — | | | (25 | ) |
Net Income | | | 44 | | | 48 | | | 31 | | | 34 | | | 45 | | | 43 | | | 20 | |
Earnings Available to PSEG | | | 38 | | | 42 | | | 26 | | | 28 | | | 39 | | | 38 | | | 14 | |
| | Calendar Quarter Ended | |
| | March 31, | | June 30, | | September 30, | | December 31, | |
| | As
Previously
Reported | | As
Restated | | As
Previously
Reported | | As
Restated | | As
Previously
Reported | | As
Restated | | As
Previously
Reported | | As
Restated | |
| | 2002 | | 2002 | | 2002 | | 2002 | | 2002 | | 2002 | | 2002 | | 2002 | |
| | (Millions, where Applicable) | |
Energy Holdings: | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating Revenues | | $ | 136 | | $ | 128 | | $ | 133 | | $ | 133 | | $ | 187 | | $ | 163 | | $ | 205 | | $ | 185 | |
Operating Income (Loss) | | | 101 | | | 90 | | | (411 | ) | | (410 | ) | | 105 | | | 108 | | | 112 | | | 115 | |
Income (Loss) Before Discontinued Operations and Cumulative Effect of a Change in Accounting Principle | | | 6 | | | (4 | ) | | (310 | ) | | (310 | ) | | 43 | | | 40 | | | 52 | | | 54 | |
Income (Loss) From Discontinued Operations, including Loss on Disposal, net of tax benefit | | | (1 | ) | | 1 | | | (37 | ) | | (39 | ) | | (3 | ) | | — | | | (10 | ) | | (11 | ) |
Cumulative Effect of a Change in Accounting Principle | | | (120 | ) | | (121 | ) | | — | | | — | | | — | | | — | | | — | | | — | |
Net (Loss) Income | | | (115 | ) | | (124 | ) | | (347 | ) | | (349 | ) | | 40 | | | 40 | | | 42 | | | 43 | |
Income (Loss) Earnings Available to PSEG | | | (121 | ) | | (129 | ) | | (352 | ) | | (355 | ) | | 34 | | | 34 | | | 36 | | | 37 | |
Note 26. Related-Party Transactions
The majority of the following discussion relates to intercompany transactions, which are eliminated during the PSEG consolidation process in accordance with GAAP.
BGSS and BGS Contracts
PSE&G and Power
Effective May 1, 2002, PSE&G transferred its gas supply contracts and gas inventory requirements to Power. On the same date, PSE&G entered into a requirements contract with Power under which Power provides the gas supply services needed to meet PSE&G’s BGSS and other contractual requirements.
For the years ended December 31, 2003 and 2002, Power billed PSE&G approximately $1.8 billion and $703 million, respectively, for BGSS. As of December 31, 2003 and 2002, PSE&G’s payable to Power related to the BGSS contract was approximately $268 million and $241 million, respectively.
Power billed PSE&G for the energy and capacity provided to meet its BGS requirements through July 31, 2002. Power also billed PSE&G for the MTC through July 31, 2003. For the years ended December 31, 2003 and 2002, Power billed PSE&G approximately $111 million and $1.2 billion, respectively, for the MTC and BGS. As of December 31, 2003, PSE&G did not have a payable to Power
197
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
related to these costs. As of December 31, 2002, PSE&G’s payable to Power relating to these costs was approximately $2 million.
Power was a participant in the BGS auction held in February 2003. As a result of this participation, Power entered into contracts for a ten-month period beginning August 1, 2003, to supply hourly priced energy, capacity and ancillary services to PSE&G, which in turn distributes these services to certain large industrial and commercial customers. For the year ended December 31, 2003, Power charged PSE&G approximately $30 million under this agreement. As of December 31, 2003, PSE&G’s payable to Power was approximately $9 million.
For the year ended December 31, 2002 and 2001, Power paid PSE&G for energy and capacity at the market price of approximately $77 million and $158 million, respectively, which PSE&G purchased under various NUG contracts at costs above market prices.
Affiliate Loans
PSEG and Power
As of December 31, 2003, Power had a receivable from PSEG of approximately $77 million for short-term funding needs. Interest income relating to this was immaterial. As of December 31, 2002, Power had a payable to PSEG of approximately $239 million for short-term funding needs. Interest expense related to short-term borrowings from PSEG was $2 million and $4 million for the year ended December 31, 2003 and 2002, respectively.
PSEG and Energy Holdings
As of December 31, 2003 and December 31, 2002, Energy Holdings had a note receivable due from PSEG of $300 million and $62 million, respectively, reflecting the investment of its excess cash with PSEG. Interest Income related to these borrowings were immaterial.
Equipment Purchases and Sales
Power and Energy Holdings
Global purchased equipment from Power totaling $47 million in 2002. This amount was sold at book value, thus no gain or loss was recorded on this transaction.
Energy Holdings
Operation and Maintenance and Development Fees
Global provides operating, maintenance and other services to and receives management and guaranty fees from various joint ventures and partnerships in which it is an investor. Fees related to the development and construction of certain projects are deferred and recognized when earned. Income from these services of $6 million, $3 million and $3 million were included in Operating Revenues in the Consolidated Statements of Operations for the years ended December 31, 2003, 2002, and 2001, respectively.
Affiliate Payables due to PSEG from Energy Technologies
As of December 31, 2002, Energy Technologies had recorded affiliate payable due to PSEG of $12 million. The amount was recorded as a component of Current Liabilities of Discontinued Operations on the Consolidated Balance Sheets. Energy Technologies repaid this balance during the first quarter of 2003.
198
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Loans to Texas Independent Energy, L.P. (TIE)
Global and its partner, TECO Energy, Inc. (Teco), own and operate two electric generation facilities in Texas through TIE, a 50/50 joint venture. As of December 31, 2003, Global had outstanding approximately $69 million of loans to TIE that earn interest at an annual rate of 12% and that are scheduled to be repaid in quarterly installments through 2012. For the year ended December 31, 2003 and 2002, Global recorded approximately $11 million and $10 million, respectively, of interest income related to this loan.
In March 2003, Global funded $14 million of convertible preferred equity to the two TIE projects as part of its negotiations with project lenders to amend the projects’ credit agreements. The convertible preferred equity has a 15% coupon and is convertible at Global’s option into an approximate 13% equity interest in TIE if not repaid in full by June 2004. This 13% equity interest is derived from the dilution of all existing general partners including Global and would give Global a net increase in ownership of approximately 7%.
Debt Issuance at GWF Energy
In September 2003, GWF Energy LLC (GWF Energy) issued $226 million of 6.131% senior secured notes to third parties that mature on December 30, 2011. The note proceeds were used by GWF Energy to repay a $45 million bank loan that matured on September 30, 2003, and to make distributions to its members and for general corporate purposes. GWF Energy made cash distributions to Global of approximately $137 million.
Transfer of Asset Management Group (AMG) from Energy Technologies to Resources
As of December 31, 2002, Energy Technologies contributed its equity investment in the capital stock of AMG, which includes various DSM investments to Resources. The aggregate book value, which approximated fair value, of the stock contributed was $42 million.
Changes in Capitalization
PSE&G
On January 21, 2003, PSEG contributed $170 million of equity to PSE&G. PSE&G paid a common stock dividend of approximately $200 million and $305 million to PSEG in 2003 and 2002, respectively.
Power
PSEG contributed capital of approximately $150 million and $200 million to Power during 2003 and 2002, respectively.
Services
PSE&G, Power and Energy Holdings
Services provides and bills administrative services to PSE&G, Power and Energy Holdings as follows:
| | Services billed
for the
Years Ended
December 31, | | Payable to
Services as of
December 31, | |
| | 2003 | | 2002 | | 2003 | | 2002 | |
| | (Millions) | |
PSE&G | | $ | 201 | | $ | 193 | | $ | 21 | | $ | 15 | |
Power | | $ | 124 | | $ | 149 | | $ | 14 | | $ | 4 | |
Energy Holdings | | $ | 16 | | $ | 22 | | $ | 2 | | $ | 3 | |
199
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
These transactions were properly recognized on each company’s stand-alone financial statements and were eliminated when preparing PSEG’s Consolidated Financial Statements. PSEG, PSE&G, Power and Energy Holdings believe that the costs of services provided by Services approximates market value for such services.
On July 31, 2003, the BPU approved the sale by PSE&G to Services, of certain non-operating assets related to PSE&G’s transmission and distribution operations with a net book value of approximately $53 million, together with associated rights and liabilities. The sale was completed on September 30, 2003 at net book value.
Tax Sharing Agreement
PSEG, PSE&G, Power and Energy Holdings
PSEG files a consolidated Federal income tax return with its affiliated companies. A tax allocation agreement exists between PSEG and each of its affiliated companies. The general operation of these agreements is that the subsidiary company will compute its taxable income on a stand-alone basis. If the result is a net tax liability, such amount shall be paid to PSEG. If there are net operating losses and/or tax credits, the subsidiary shall receive payment for the tax savings from PSEG to the extent that PSEG is able to utilize those benefits. As of December 31, 2003, PSE&G, Power and Energy Holdings had a net receivable/(payable) from/to PSEG of approximately $(105) million, $(17) million and $173 million, respectively. As of December 31, 2002, PSE&G, Power and Energy Holdings has a net payable to PSEG of approximately $113 million, $1 million and $71 million, respectively.
Note 27. Guarantees of Debt
Power has $500 million of 6.88% Senior Notes maturing in 2006, $800 million of 7.75% Senior Notes maturing in 2011, $600 million of 6.95% Senior Notes maturing in 2012, $300 million of 5.50% Senior Notes maturing in 2015 and $500 million of 8.63% Senior Notes maturing in 2031. Power also has $66 million of 5.00% Pollution Control Notes maturing in 2012, $14 million of 5.50% Pollution Control Notes maturing in 2020, $19 million of 5.85% Pollution Control Notes maturing in 2027 and $25 million of 5.75% Pollution Control Notes maturing in 2031. Each series of these Senior Notes and Pollution Control Notes is fully and unconditionally and jointly and severally guaranteed by Fossil, Nuclear and ER&T. The following table presents condensed financial information for the guarantor subsidiaries as well as Power’s non-guarantor subsidiaries as of December 31, 2003 and 2002:
| | Power | | Guarantor
Subsidiaries | | Other
Subsidiaries | | Consolidating
Adjustments | | Total | |
| | | | | | (Millions) | | | | | |
For the Year Ended December 31, 2003: | | | | | | | | | | | |
Revenues | | $ | — | | $ | 6,429 | | $ | 134 | | $ | (958 | ) | $ | 5,605 | |
Operating Expenses | | | — | | | 5,627 | | | 93 | | | (958 | ) | | 4,762 | |
Operating Income | | | — | | | 802 | | | 41 | | | — | | | 843 | |
Equity Earnings in Subsidiaries | | | 928 | | | 21 | | | — | | | (949 | ) | | — | |
Other Income | | | 14 | | | 155 | | | 116 | | | (136 | ) | | 149 | |
Other Deductions | | | — | | | (78 | ) | | — | | | — | | | (78 | ) |
Interest Expense | | | (159 | ) | | (81 | ) | | (11 | ) | | 137 | | | (114 | ) |
Income Taxes | | | 61 | | | (327 | ) | | (60 | ) | | — | | | (326 | ) |
Cumulative Change in Accounting Principle | | | — | | | 366 | | | 4 | | | — | | | 370 | |
Net Income | | $ | 844 | | $ | 858 | | $ | 90 | | $ | (948 | ) | $ | 844 | |
200
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| | | Power | | | | Guarantor
Subsidiaries | | | | Other
Subsidiaries | | | | Consolidating
Adjustments | | | Total | |
| | | | | | | | | | | (Millions) | | | | | | | | |
As of December 31, 2003: | | | | | | | | | | | | | | | | | | | |
Current Assets | | $ | 3,376 | | | $ | 1,910 | | | $ | 122 | | | $ | (3,599 | ) | $ | 1,809 | |
Property, Plant and Equipment, net | | | 46 | | | | 2,723 | | | | 1,812 | | | | — | | | 4,581 | |
Investment in Subsidiaries | | | 3,330 | | | | 733 | | | | — | | | | (4,063 | ) | | — | |
Noncurrent Assets | | | 456 | | | | 1,115 | | | | 69 | | | | (302 | ) | | 1,338 | |
Total Assets | | $ | 7,208 | | | $ | 6,481 | | | $ | 2,003 | | | $ | (7,964 | ) | $ | 7,728 | |
| | | | | | | | | | | | | | | | | | | |
Current Liabilities | | $ | 1,742 | | | $ | 2,839 | | | $ | 168 | | | $ | (3,670 | ) | $ | 1,079 | |
Noncurrent Liabilities | | | 44 | | | | 373 | | | | 11 | | | | — | | | 428 | |
Note Payable—Affiliated Company | | | — | | | | — | | | | 300 | | | | (300 | ) | | — | |
Long-Term Debt | | | 2,816 | | | | — | | | | 800 | | | | — | | | 3,616 | |
Member’s Equity | | | 2,606 | | | | 3,269 | | | | 724 | | | | (3,994 | ) | | 2,605 | |
Total Liabilities and Member’s Equity | | $ | 7,208 | | | $ | 6,481 | | | $ | 2,003 | | | $ | (7,964 | ) | $ | 7,728 | |
For the Year Ended December 31, 2003: | | | | | | | | | | | | | | | | | | | |
Net Cash Provided By (Used In) Operating Activities | | $ | (1,647 | ) | | $ | (132 | ) | | $ | (88 | ) | | $ | 2,447 | | $ | 580 | |
Net Cash Provided By (Used In) Investing Activities | | $ | 1,349 | | | $ | 440 | | | $ | (253 | ) | | $ | (2,285 | ) | $ | (749 | ) |
Net Cash Provided By (Used In) Financing Activities | | $ | 54 | | | $ | (62 | ) | | $ | 379 | | | $ | (162 | ) | $ | 209 | |
For the Year Ended December 31, 2002: | | | | | | | | | | | | | | | | | | | |
Revenues | | $ | 2 | | | $ | 4,499 | | | $ | 42 | | | $ | (907 | ) | $ | 3,636 | |
Operating Expenses | | | — | | | | 3,599 | | | | 41 | | | | (907 | ) | | 2,733 | |
Operating Income | | | 2 | | | | 900 | | | | 1 | | | | — | | | 903 | |
Equity Earnings in Subsidiaries | | | 574 | | | | (3 | ) | | | — | | | | (571 | ) | | — | |
Other Income | | | — | | | | 9 | | | | — | | | | (8 | ) | | 1 | |
Other Deductions | | | — | | | | — | | | | — | | | | (1 | ) | | (1 | ) |
Interest Expense | | | (180 | ) | | | (69) | | | | 118 | | | | 9 | | | (122 | ) |
Income Taxes | | | 72 | | | | (343) | | | | (42 | ) | | | — | | | (313 | ) |
Net Income (Loss) | | $ | 468 | | | $ | 494 | | | $ | 77 | | | $ | (571 | ) | $ | 468 | |
As of December 31, 2002: | | | | | | | | | | | | | | | | | | | |
Current Assets | | $ | 1,329 | | | $ | 2,292 | | | $ | 141 | | | $ | (2,188 | ) | $ | 1,574 | |
Property, Plant and Equipment, net | | | 42 | | | | 2,423 | | | | 1,572 | | | | 3 | | | 4,040 | |
Investment in Subsidiaries | | | 3,028 | | | | 377 | | | | — | | | | (3,405 | ) | | — | |
Noncurrent Assets | | | 230 | | | | 1,349 | | | | 1,313 | | | | (1,289 | ) | | 1,603 | |
Total Assets | | $ | 4,629 | | | $ | 6,441 | | | $ | 3,026 | | | $ | (6,879 | ) | $ | 7,217 | |
Current Liabilities | | $ | 367 | | | $ | 2,604 | | | $ | 499 | | | $ | (2,158 | ) | $ | 1,312 | |
Noncurrent Liabilities | | | 209 | | | | 990 | | | | 29 | | | | (78 | ) | | 1,150 | |
Note Payable—Affiliated Company | | | 97 | | | | 1,150 | | | | — | | | | (1,247 | ) | | — | |
Long-Term Debt | | | 2,516 | | | | — | | | | 800 | | | | — | | | 3,316 | |
Member’s Equity | | | 1,440 | | | | 1,697 | | | | 1,698 | | | | (3,396 | ) | | 1,439 | |
Total Liabilities and Member’s Equity | | $ | 4,629 | | | $ | 6,441 | | | $ | 3,026 | | | $ | (6,879 | ) | $ | 7,217 | |
For the Year Ended December 31, 2002: | | | | | | | | | | | | | | | | | | | |
Net Cash Provided By (Used In) Operating Activities | | $ | (182 | ) | | $ | 738 | | | $ | 298 | | | $ | (437 | ) | $ | 417 | |
Net Cash Provided By (Used In) Investing Activities | | $ | (695 | ) | | $ | (1,051 | ) | | $ | (625 | ) | | $ | 1,072 | | $ | (1,299 | ) |
Net Cash Provided By (Used In) Financing Activities | | $ | 877 | | | $ | 332 | | | $ | 328 | | | $ | (638 | ) | $ | 899 | |
For the Year Ended December 31, 2001: | | | | | | | | | | | | | | | | | | | |
Revenues | | $ | 2 | | | $ | 3,309 | | | $ | 22 | | | $ | (869 | ) | $ | 2,464 | |
Operating Expenses | | | — | | | | 2,524 | | | | 22 | | | | (869 | ) | | 1,677 | |
Operating Income (Loss) | | | 2 | | | | 785 | | | | — | | | | — | | | 787 | |
Equity Earnings in Subsidiaries | | | 500 | | | | (9 | ) | | | — | | | | (491 | ) | | — | |
Other Income (Loss) | | | — | | | | 10 | | | | — | | | | (10 | ) | | — | |
Interest Expense | | | (180 | ) | | | (79 | ) | | | 108 | | | | 8 | | | (143 | ) |
Income Taxes | | | 72 | | | | (286 | ) | | | (38) | | | | 2 | | | (250 | ) |
Net Income (Loss) | | $ | 394 | | | $ | 421 | | | $ | 70 | | | $ | (491 | ) | $ | 394 | |
For the Year Ended December 31, 2001: | | | | | | | | | | | | | | | | | | | |
Net Cash Provided By (Used In) Operating Activities | | $ | 313 | | | $ | 1,456 | | | $ | (989 | ) | | $ | (205 | ) | $ | 575 | |
Net Cash Provided By (Used In) Investing Activities | | $ | 41 | | | $ | (2,394 | ) | | $ | (947 | ) | | $ | 1,687 | | $ | (1,613 | ) |
Net Cash Provided By (Used In) Financing Activities | | $ | 329 | | | $ | 928 | | | $ | 1,936 | | | $ | (2,166 | ) | $ | 1,027 | |
201
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
PSEG
None.
PSE&G
None.
Power
None.
Energy Holdings
None.
202
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
PSEG, PSE&G, Power and Energy Holdings
PSEG, PSE&G, Power and Energy Holdings have established and maintain disclosure controls and procedures which are designed to provide reasonable assurance that material information relating to each company, including their respective consolidated subsidiaries, is made known to the Chief Executive Officer and Chief Financial Officer of each company by others within those entities. PSEG, PSE&G, Power and Energy Holdings have established a Disclosure Committee, which is made up of several key management employees and reports directly to the Chief Financial Officer and Chief Executive Officer of each company, to monitor and evaluate these disclosure controls and procedures. The Chief Financial Officer and Chief Executive Officer of each company have evaluated the effectiveness of the disclosure controls and procedures and, based on this evaluation, it was concluded that the disclosure controls and procedures for the financial statements prepared as of and for the year ended December 31, 2003 were effective in providing reasonable assurance during the period covered in these annual reports.
Internal Controls
PSEG, PSE&G, Power and Energy Holdings
In preparation for the implementation of the detailed internal control documentation and testing required by the Sarbanes-Oxley Act, PSEG, PSE&G, Power and Energy Holdings have been performing a review of internal controls related to each of their accounting and reporting processes. As a result of this review, PSEG, PSE&G, Power and Energy Holdings have made several enhancements in internal controls, including the centralization of certain operations and related accounting functions and the formalization and documentation of internal control processes and procedures.
PSEG and Energy Holdings
As a result of a Management review by Energy Holdings of the accounting for its investments at year end 2003, it was determined that the foreign currency translation impacts for RGE, one of Energy Holdings’ investments, were incorrectly recorded. Management at Energy Holdings has reviewed the accounting for each of its investments and has determined that this issue was isolated to the accounting for RGE. As a result of this error, and as discussed in further detail in Note 2. Restatement of Financial Statements of the Notes to Consolidated Financial Statements, Energy Holdings and PSEG have restated their 2003 quarterly information and 2002 and 2001 financial statements. Separately, also as part of the year end 2003 review, it was determined that there were internal control deficiencies related to the recording and review of the sale of Energy Holdings’ indirect ownership interest in CPC, which resulted in an increase in the loss recognized on the sale. As a result of an internal review of these two matters, Energy Holdings and PSEG have determined that certain significant deficiencies in their respective internal control processes existed. Specifically, such internal control deficiencies related to the design and operational effectiveness of performing investment reconciliations of foreign subsidiaries, review procedures and resource constraints. Management at Energy Holdings and PSEG have reviewed the existing internal control processes, taken various corrective actions to address each of these deficiencies and reviewed these matters with the external auditors and the Audit Committee.
PSEG, PSE&G, Power and Energy Holdings
As a result of the corrective actions taken to address the control deficiencies in internal controls at Energy Holdings and PSEG cited above, as well as the general control enhancements at PSEG, PSE&G, Power and Energy Holdings, each discussed above, there were certain significant changes in internal controls made during the most recent fiscal quarter and during the first quarter of 2004.
203
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
Executive Officers
The Executive Officers of each of PSEG, PSE&G, Power and Energy Holdings, respectively, are set forth below, as indicated for each individual.
Name | | Age as of
December 31,
2003 | | Office | | Effective Date
First Elected to
Present Position |
| | | | | | | |
E. James Ferland(1)(2)(3)(4) | | 61 | | Chairman of the Board, President and Chief Executive Officer (PSEG) | | July 1986 to present |
| | | | Chairman of the Board and Chief Executive Officer (PSE&G) | | July 1986 to present |
| | | | Chairman of the Board and Chief Executive Officer (Energy Holdings) | | June 1989 to present |
| | | | Chairman of the Board and Chief Executive Officer (Power) | | June 1999 to present |
| | | | Chairman of the Board and Chief Executive Officer (Services) | | November 1999 to present |
| | | | | | |
Thomas M. O’Flynn(1)(3)(4) | | 43 | | Executive Vice President and Chief Financial Officer (PSEG) | | July 2001 to present |
| | | | Executive Vice President — Finance (Services) | | July 2001 to present |
| | | | Executive Vice President and Chief Financial Officer (Energy Holdings) | | August 2002 to present |
| | | | Executive Vice President and Chief Financial Officer (Power) | | February 2002 to present |
| | | | Managing Director — Global Power and Utility Investment Banking Division Group (Morgan Stanley) | | December 1997 to May 2001 |
| | | | | | |
Robert J. Dougherty, Jr.(1)(4) | | 52 | | President (Global) | | August 2003 to present |
| | | | President and Chief Operating Officer (Energy Holdings) | | January 1997 to present |
| | | | Vice President (PSEG) | | March 1995 to present |
| | | | | | |
Ralph Izzo(1)(2) | | 46 | | President and Chief Operating Officer (PSE&G) | | October 2003 to present |
| | | | Vice President — Utility Operations (PSE&G) | | June 2002 to October 2003 |
| | | | Vice President — Special Projects (Services) | | September 2001 to June 2002 |
| | | | Vice President — Appliance Service (PSE&G) | | April 2000 to September 2001 |
| | | | Vice President — Corporate Planning (PSEG) | | March 1998 to April 2000 |
| | | | | | |
R. Edwin Selover(1)(2) | | 58 | | Senior Vice President and General Counsel (PSEG) | | April 2002 to present |
| | | | Vice President and General Counsel (PSEG) | | April 1988 to April 2002 |
| | | | Senior Vice President and General Counsel (PSE&G) | | January 1988 to present |
| | | | Senior Vice President and General Counsel (Services) | | November 1999 to present |
| | | | | | |
Patricia A. Rado(1)(2)(3) | | 61 | | Vice President and Controller (PSEG) | | April 1993 to present |
| | | | Vice President and Controller (PSE&G) | | April 1993 to present |
204
| | | | Vice President and Controller (Power) | | June 1999 to present |
| | | | Vice President and Controller (Services) | | November 1999 to present |
| | | | | | |
Robert E. Busch(1)(2) | | 57 | | President & Chief Operating Officer (Services) | | April 2001 to present |
| | | | Senior Vice President-Finance and Chief Financial Officer (Services) | | November 1999 to April 2001 |
| | | | Senior Vice President and Chief Financial Officer (PSE&G) | | March 1998 to present |
| | | | | | |
Harold W. Borden Jr.(3) | | 59 | | Vice President and General Counsel (Power) | | June 1999 to present |
| | | | Vice President — Law (PSE&G) | | April 1995 to July 1999 |
| | | | | | |
Morton A. Plawner(3) | | 56 | | Treasurer (PSEG) | | January 1998 to present |
| | | | Vice President and Treasurer (PSE&G) | | January 1998 to present |
| | | | Vice President and Treasurer (Power) | | June 1999 to present |
| | | | | | |
Frank Cassidy(1)(3) | | 57 | | President and Chief Operating Officer (Power) | | July 1999 to present |
| | | | President (Energy Technologies)
| | November 1996 to June 1999
|
Steven R. Teitelman(3) | | 57 | | President (ER&T) | | June 1999 to present |
| | | | Vice President — Energy Resources and Trading (PSE&G) | | August 1997 to August 2002 |
| | | | | | |
Roy A. Anderson(3) | | 55 | | President and Chief Nuclear Officer (Nuclear) | | March 2003 to present |
| | | | Executive Vice President and Chief Nuclear Officer (Nuclear Management Company) | | May 2001 to March 2003 |
| | | | Senior Vice President, Chief Nuclear Officer, Senior Vice President — Energy Supply (Florida Power Corporation) | | January 1997 to January 2001 |
| | | | | | |
Michael J. Thomson(3) | | 45 | | President (Fossil) | | August 2003 to present |
| | | | President (Global) | | January 1997 to July 2003 |
| | | | | | |
Eileen A. Moran(4) | | 49 | | President (Resources) | | May 1990 to present |
| | | | President (EGDC) | | January 1997 to present |
| | | | | | |
Miriam E. Gilligan(4) | | 52 | | Vice President — Finance and Treasurer (Energy Holdings) | | December 2001 to present |
| | | | Vice President (Services) | | December 2001 to present |
| | | | Treasurer (Energy Holdings) | | 1997 to December 2001 |
| | | | | | |
Derek M. DiRisio(4) | | 39 | | Vice President and Controller (Energy Holdings) | | June 1998 to present |
| | | | Director — Accounting Services (PSEG) | | November 1997 to June 1998 |
(1)
Executive Officer of PSEG
(2)
Executive Officer of PSE&G
(3)
Executive Officer of Power
(4)
Executive Officer of Energy Holdings
Directors
PSEG
The information required by Item 10 of Form 10-K with respect to (i) present directors of PSEG who are nominees for election as directors at PSEG’s Annual Meeting of Stockholders to be held on April 20, 2004, and directors whose terms will continue beyond the meeting, and (ii) compliance with
205
Section 16(a) of the Securities Exchange Act of 1934, as amended, is set forth under the headings “Election of Directors” and Section 16(a) “Beneficial Ownership Reporting Compliance” in PSEG’s definitive Proxy Statement for such Annual Meeting of Stockholders, which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 10, 2004 and which information set forth under said heading is incorporated herein by this reference thereto.
PSE&G
CAROLINE DORSA has been a director of PSE&G since February 2003. Age 44. Director of PSEG. Has been Vice President and Treasurer of Merck & Co., Inc., Whitehouse Station, New Jersey (discovers, develops, manufactures and markets human and animal health products) since December 1996. Was Treasurer from January 1994 to November 1996 and Executive Director of the U.S. Human Health Marketing subsidiary of Merck & Co., Inc. from June 1992 to January 1994. Director of Readington Holdings, Inc.
E. JAMES FERLAND has been a director of PSE&G since July 1986. Age 61. For additional information, see Executive Officers table above.
ALBERT R. GAMPER, JR. has been a director of PSE&G since December 2000. Age 61. Director of PSEG. Has been Chairman of the Board and Chief Executive Officer of The CIT Group, Inc., Livingston, New Jersey (commercial finance company) since September 2003. Was Chairman of the Board, President and Chief Executive Officer from June 2002 to September 2003. Was President and Chief Executive Officer from February 2002 to June 2002. Was President and Chief Executive Officer of Tyco Capital Corporation from June 2001 to February 2002. Was Chairman of the Board, President and Chief Executive Officer of The CIT Group, Inc., from January 2000 to June 2001. Was President and Chief Executive Officer of The CIT Group, Inc. from December 1989 to December 1999.
CONRAD K. HARPER has been a director of PSE&G since May 1997. Age 63. Director of PSEG. Of counsel to the law firm of Simpson Thacher & Bartlett LLP, New York, New York since January 2003. Was a partner from October 1996 to December 2002 and from October 1974 to May 1993. Was Legal Adviser, US Department of State from May 1993 to June 1996. Director of New York Life Insurance Company.
Power
ROBERT E. BUSCH has been a director of Power since December 2000. For additional information, see Executive Officers table above.
FRANK CASSIDY has been a director of Power since July 1999. For additional information, see Executive Officers table above.
ROBERT J. DOUGHERTY, JR. has been a director of Power since July 1999. For additional information, see Executive Officers table above.
E. JAMES FERLAND has been a director of Power since July 1999. For additional information, see Executive Officers table above.
THOMAS M. O’FLYNN has been a director of Power since July 2001. For additional information, see Executive Officers table above.
R. EDWIN SELOVER has been a director of Power since July 1999. For additional information, see Executive Officers table above.
Energy Holdings
ROBERT E. BUSCH has been a director of Energy Holdings since December 2000. For additional information, see Executive Officers table above.
FRANK CASSIDY has been a director of Energy Holdings since January 2000. For additional information, see Executive Officers table above.
ROBERT J. DOUGHERTY, JR. has been a director of Energy Holdings since January 2000. For additional information, see Executive Officers table above.
206
E. JAMES FERLAND has been a director of Energy Holdings since June 1989. For additional information, see Executive Officers table above.
THOMAS M. O’FLYNN has been a Director of Energy Holdings since July 2001. For additional information, see Executive Officers table above.
R. EDWIN SELOVER has been a Director of Energy Holdings since January 2000. For additional information, see Executive Officers table above.
PSEG, PSE&G, Power and Energy Holdings
Code of Ethics
PSEG has adopted a code of ethics entitled Standards of Integrity (Standards) applicable to it and its subsidiaries, including PSE&G, Power and Energy Holdings. The Standards are an integral part of PSEG’s business conduct compliance program and embody the commitment of PSEG and its subsidiary companies to conduct operations in accordance with the highest legal and ethical standards. The Standards apply to all PSEG directors, employees (including PSEG’s, PSE&G’s, Power’s and Energy Holdings’ respective principal executive officer, principal financial officer, principal accounting officer or Controller and persons performing similar functions), contractors and consultants, worldwide. Each is responsible for understanding and complying with the Standards.
The Standards establish a set of common expectations for behavior that each employee must adhere to in dealings with investors, customers, fellow employees, competitors, vendors, government officials, the media and all others who may associate their words and actions with PSEG. They have been developed to provide reasonable assurance that, in conducting PSEG’s business, employees behave ethically and in accordance with the law and do not take advantage of investors, regulators or customers through manipulation, abuse of confidential information or misrepresentation of material facts.
Any amendment (other than technical, administrative or non-substantive) to or a waiver from the Standards that applies to PSEG’s, PSE&G’s, Power’s or Energy Holdings’ principal executive officer, principal financial officer, principal accounting officer or Controller, or persons performing similar functions and that relates to any element enumerated by the SEC, will be posted on PSEG’s website,www.pseg.com/investor/governance.
ITEM 11. EXECUTIVE COMPENSATION
PSEG
The information required by Item 11 of Form 10-K is set forth under the heading ‘Executive Compensation’ in PSEG’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 20, 2004 which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 10, 2004 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, 2003 is set forth below. Amounts shown were paid or awarded for all services rendered to PSEG and its subsidiaries and affiliates including PSE&G.
207
Summary Compensation Table
| | | | | | | | | | | Long Term Compensation | | | | |
| | | | | | | | | | |
| | | | |
| | | | | Annual Compensation | | Awards | | Payouts | | | | |
| | | | |
| |
| |
| | | | |
Name and Principal Position | | Year | | Salary $ | | Bonus/Annual
Incentive
Award ($)(1) | | Restricted
Stock ($) | | Options
(#)(2) | | LTIP
Payouts
($)(3) | | All Other
Compensation
($)(4) | |
| | | | | | | | | | | | | | | | |
E. James Ferland | | | 2003 | | | 1,006,227 | | | 1,440,000 | | | 0 | | | 0 | (5) | | 0 | | | 6,002 | |
Chairman of the Board and Chief Executive Officer | | | 2002 | | | 971,358 | | | 713,000 | | | 0 | | | 350,000 | | | 0 | | | 6,002 | |
| | | 2001 | | | 962,525 | | | 1,023,000 | | | 2,248,000 | (6) | | 350,000 | | | 400,800 | | | 51,152 | |
| | | | | | | | | | | | | | | | | | | | | | |
R. Edwin Selover | | | 2003 | | | 403,487 | | | 287,000 | | | 0 | | | 0 | (5) | | 0 | | | 8,004 | |
Senior Vice President and General Counsel | | | 2002 | | | 388,544 | | | 125,500 | | | 0 | | | 80,000 | | | 0 | | | 8,004 | |
| | | 2001 | | | 367,852 | | | 225,000 | | | 0 | | | 70,000 | | | 100,200 | | | 15,597 | |
| | | | | | | | | | | | | | | | | | | | | | |
Robert E. Busch | | | 2003 | | | 370,610 | | | 279,000 | | | 0 | | | 0 | (5) | | 0 | | | 8,003 | |
Senior Vice President and Chief Financial Officer | | | 2002 | | | 358,654 | | | 153,200 | | | 0 | | | 65,000 | | | 0 | | | 8,006 | |
| | | 2001 | | | 335,482 | | | 262,500 | | | 0 | | | 315,000 | | | 60,120 | | | 6,803 | |
| | | | | | | | | | | | | | | | | | | | | | |
Ralph Izzo(7) | | | 2003 | | | 304,051 | | | 282,800 | | | 0 | | | 250,000 | | | 0 | | | 8,003 | |
President and Chief Operating Officer | | | 2002 | | | 273,973 | | | 79,800 | | | 0 | | | 35,000 | | | 0 | | | 5,500 | |
| | | 2001 | | | 239,104 | | | 99,000 | | | 0 | | | 35,000 | | | 24,048 | | | 5,250 | |
| | | | | | | | | | | | | | | | | | | | | | |
Patricia A. Rado | | | 2003 | | | 227,148 | | | 102,400 | | | 0 | | | 0 | (5) | | 0 | | | 5,509 | |
Vice President and Controller | | | 2002 | | | 219,178 | | | 53,600 | | | 0 | | | 25,000 | | | 0 | | | 5,593 | |
| | | 2001 | | | 209,835 | | | 94,500 | | | 0 | | | 25,000 | | | 24,048 | | | 6,449 | |
(1)
Amounts awarded were earned under the Restated and Amended Management Incentive Compensation Plan and determined and paid in the following year based on individual performance and financial and operating performance of PSEG and PSE&G, including comparison to other companies.
(2)
All grants of options to purchase shares of PSEG Common Stock were non-qualified options made under the 2001Long-Term Incentive Plan (2001 LTIP). All options granted were non-tandem. Non-tandem grants are made without performance units and dividend equivalents.
(3)
Amount paid in proportion to options exercised, if any, based on value of previously granted performance units and dividend equivalents under the 1989 LTIP, each as measured during three-year period ending the year prior to the year in which payment is made. Under the 1989 LTIP, tandem grants were made with an equal number of performance units and dividend equivalents which may provide cash payments, dependent upon future financial performance of PSEG in comparison to other companies and dividend payments by PSEG, to assist recipients in exercising options granted. The tandem grant was made at the beginning of a three-year performance period and cash payment of the value of such performance units and dividend equivalents is made following such period in proportion to the options, if any, exercised at such time.
(4)
Includes employer contribution to the PSEG Thrift and Tax-Deferred Savings Plan:
| | Ferland
($) | | Selover
($) | | Busch
($) | | Izzo
($) | | Rado
($) | |
| |
| |
| |
| |
| |
| |
2003 | | | 6,002 | | | | 8,004 | | | | 8,003 | | | | 8,003 | | | | 5,509 | | |
2002 | | | 6,002 | | | | 8,004 | | | | 8,006 | | | | 8,001 | | | | 5,593 | | |
2001 | | | 5,102 | | | | 5,104 | | | | 6,803 | | | | 6,803 | | | | 6,450 | | |
In addition, 2001 amounts include $46,050 for Mr. Ferland; $10,493 for Mr. Selover; and $1,093 for Mrs. Rado, respectively, representing earnings credited on compensation deferred under PSE&G’s Deferred Compensation Plan in excess of 120% of the applicable Federal long-term interest rate as prescribed under Section 1274(d) of the Internal Revenue Code.
(5)
No regular annual grants were made under the 2001 LTIP because, as noted below in “Option Grants in Last Fiscal Year (2003),” PSEG stockholders are being asked to approve the 2004 LTIP and the PSEG Organization and Compensation Committee expects to make grants with respect to 2003 following such vote.
(6)
Value as of original grant date, based on the closing price of $40.80 on the New York Stock Exchange on November 20, 2001, with respect to an award to Mr. Ferland of 60,000 shares of restricted stock, with 30,000 shares vesting in 2006 and 30,000 shares vesting in 2007. Dividends on the entire grant are paid in cash from the date of award.
(7)
Mr. Izzo was elected to his present position effective October 18, 2003.
208
Option Grants in Last Fiscal Year (2003)
| | Option Grants in Last Fiscal Year | | | | |
| |
| | | | |
Name | | Number of
Securities
Underlying
Options
Granted(1) | | % of Total
Options
Granted to
Employees in
Fiscal Year | | Exercise or
Base Price
($/Sh) | | Expiration
Date | | Grant Date
Present Value
($)(2) | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
E. James Ferland | | | — | | | | — | | | | — | | | | — | | | | — | | |
R. Edwin Selover | | | — | | | | — | | | | — | | | | — | | | | — | | |
Robert E. Busch | | | — | | | | — | | | | — | | | | — | | | | — | | |
Ralph Izzo(3) | | | 250,000 | | | | 35.4 | | | | 40.77 | | | | 10/18/13 | | | | 1,577,500 | | |
Patricia A. Rado | | | — | | | | — | | | | — | | | | — | | | | — | | |
(1)
At its Annual Meeting to be held on April 20, 2004, PSEG is requesting stockholders to approve the 2004 Long-Term Incentive Compensation Plan (2004 LTIP), a new long-term incentive compensation plan for employees. Because of this requested approval, the Organization and Compensation Committee of the Board of Directors did not make any annual long-term incentive grants to any of the named executive officers or any other officers in December 2003, pending the outcome of the stockholder vote at the 2004 Annual Meeting. If stockholders approve the 2004 LTIP, the Organization and Compensation Committee intends to make long-term incentive grants of stock options, performance shares and/or restricted stock to officers, including the executive officers, under the 2004 LTIP in an amount designed to reflect the median of the competitive market for energy services companies. If stockholders approve the 2004 LTIP, it will replace the existing 2001 LTIP approved by stockholders in 2002, and the 1989 LTIP (Prior Plans). If stockholders do not approve the 2004 LTIP, the Organization and Compensation Committee intends to continue to make grants of stock options under the Prior Plans.
(2)
Determined using the Black-Scholes model, incorporating the following material assumptions and adjustments: (a) exercise price of $40.77, equal to the fair market value of the underlying PSEG Common Stock on the date of grant; (b) an option term of ten years on all grants; (c) interest rate of 4.29% that represent the interest rates on U.S. Treasury securities on the date of grant with a maturity date corresponding to that of the option terms; (d) volatility of 29.49% calculated using daily PSEG Common Stock prices for the one-year period prior to the grant date; (e) dividend yield of 5.30% and (f) reductions of approximately 11.38% to reflect the probability of forfeiture due to termination prior to vesting, and approximately 9.53% to reflect the probability of a shortened option term due to termination of employment prior to the option expiration dates. Actual values which may be realized, if any, upon any exercise of such options, will be based on the market price of PSEG Common Stock at the time of any such exercise and thus are dependent upon future performance of PSEG Common Stock. There is no assurance that any such value realized will be at or near the value estimated by the Black-Scholes model utilized.
(3)
Granted under the 2001 LTIP with exercisability commencing October 18, 2004, October 18, 2005 and October 18, 2006, respectively, with respect to one-third of the options at each such date.
209
Aggregated Option Exercises in Last Fiscal Year (2003) and
Fiscal Year End Option Values (12/31/03)
| | | | | | | | Number of Unexercised
Options at FY-End(#)(1) | | Value of Unexercised
In-the-Money Options
At FY-End($)(3) | |
| | | | | | | |
| |
| |
Name | | Shares
Acquired
on Exercise
(#)(1) | | Value
Realized
($)(2) | | Exercisable
(#) | | Unexercisable
(#) | | Exercisable
($)(3) | | Unexercisable
($)(3) | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
E. James Ferland | | | 0 | | | | 0 | | | | 1,115,000 | | | 350,000 | | | | 6,539,836 | | | 3,238,664 | | |
R. Edwin Selover | | | 0 | | | | 0 | | | | 183,334 | | | 76,666 | | | | 1,098,993 | | | 730,195 | | |
Robert E. Busch | | | 0 | | | | 0 | | | | 245,000 | | | 215,000 | | | | 733,074 | | | 601,464 | | |
Ralph Izzo | | | 0 | | | | 0 | | | | 83,000 | | | 285,000 | | | | 410,811 | | | 1,081,364 | | |
Patricia A. Rado | | | 0 | | | | 0 | | | | 63,001 | | | 24,999 | | | | 349,451 | | | 231,324 | | |
(1)
Reflects any options granted and/or exercised through year-end (12/31/03).
(2)
Represents difference between exercise price and market price of PSEG Common Stock on date of exercise.
(3)
Represents difference at fiscal year end (12/31/03) between market price of PSEG Common Stock ($43.80) and the respective exercise prices of the options. Such amounts may not necessarily be realized. Actual values which may be realized, if any, upon any exercise of such options will be based on the market price of PSEG Common Stock at the time of any such exercise and thus are dependent upon future performance of PSEG Common Stock.
Employment Contracts and Arrangements
PSEG has entered into an employment agreement dated as of June 16, 1998 and amended as of November 20, 2001 with Mr. Ferland covering his employment as Chief Executive Officer through March 31, 2007. The Agreement provides that Mr. Ferland will be re-nominated for election as a director during his employment under the Agreement. The Agreement also provides that Mr. Ferland’s base salary, target annual incentive bonus and long term incentive bonus will be determined based on compensation practices for CEO’s of similar companies and that his annual salary will not be reduced during the term of the Agreement. The Agreement also provided for an award to him of 150,000 shares of restricted PSEG Common Stock as of June 16, 1998 and 60,000 shares of restricted PSEG Common Stock as of November 20, 2001, with 60,000 shares vesting in 2002; 20,000 shares vesting in 2003; 30,000 shares vesting in 2004; 40,000 shares vesting in 2005; 30,000 shares vesting in 2006; and 30,000 shares vesting in 2007. Any non-vested shares are forfeited upon his retirement unless the Board of Directors, in its discretion, determines to waive the forfeiture. The Agreement provides for the granting of 22 years of pension credit for Mr. Ferland’s prior service, which was awarded at the time of his initial employment.
PSEG has entered into an employment agreement with Mr. Izzo dated as of October 18, 2003 and Mr. Busch dated as of April 24, 2001, covering the respective employment of each in the position listed in the Summary Compensation Table through October 17, 2008 for Mr. Izzo and April 24, 2006 for Mr. Busch. The agreements are essentially identical and provide that the base salary, target annual incentive bonus and long-term incentive bonus will be determined based on compensation practices of similar companies and that their annual salary will not be reduced during the term of the Agreement, and awarded to Mr. Izzo 250,000 options on PSEG Common Stock, 50,000 of which vest each October 18 and expire on October 18, 2013 and awarded to Mr. Busch 250,000 options on PSEG Common Stock, 50,000 of which vest each April 24 and expire on April 24, 2011 in each case provided that the individual has remained continuously employed by PSEG through such date. The agreement for Mr. Busch also provides for the grant of additional years of credited service for retirement purposes in light of allied work experience of fifteen years.
Each of the Agreements further provide that if the individual is terminated without “Cause” or resigns for “Good Reason” (as those terms are defined in each Agreement) during the term of the Agreement, the respective entire restricted stock award or the entire option award becomes vested, the
210
individual will be paid a benefit of two times base salary and target bonus, and his welfare benefits will be continued for two years unless he is sooner employed. In the event such a termination occurs after a “Change in Control” (also as defined in each Agreement), the payment to the individual becomes three times the sum of salary and target bonus, continuation of welfare benefits for three years for Messrs. Ferland and Busch and two years for Mr. Izzo unless sooner reemployed, payment of the net present value of providing three years additional service under PSEG’s retirement plans, and a gross-up for excise taxes on any termination payments due under the Internal Revenue Code. The respective Agreements provide that Mr. Ferland is prohibited for two years and Messrs. Izzo and Busch are prohibited for one year from competing with and each is prohibited for two years from recruiting employees from, PSEG or its subsidiaries or affiliates, after termination of employment. Violation of these provisions requires a forfeiture of the respective restricted stock and option grant and certain benefits.
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 PSEG. Hence, during 2003 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
During 2003, a director who was not an officer of PSEG or its subsidiaries and affiliates, including PSE&G, was paid an annual retainer of $40,000 and a fee of $1,500 for attendance at any Board or committee meeting, inspection trip, conference or other similar activity relating to PSEG or PSE&G. Pursuant to the Compensation Plan for Outside Directors, a certain percentage, currently fifty percent, of the annual retainer is paid in PSEG Common Stock. No additional retainer is paid for service as a director of PSE&G. Each PSEG Committee Chair received an additional annual retainer of $5,000 except for the Chair of the Audit Committee, who received $10,000. In addition, each member of the Audit Committee received an additional annual retainer of $5,000.
PSEG also maintains a Stock Plan for Outside Directors pursuant to which directors who are not employees of PSEG or its subsidiaries receive shares of restricted stock for each year of service as a director. For 2003, this amount was 800 shares. Such shares held by each non-employee director are included in the table below under Item 12. Security Ownership of Certain Beneficial Owners 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 after a ‘change in control’ as defined in the Plan or if the director were to die in office. PSEG also has the ability to waive these restrictions 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 for executive officers 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.
211
Pension Plan Table
Average Final
Compensation | | | Length of Service | |
|
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 | |
| 1,300,000 | | | | | 780,000 | | | 845,000 | | | 910,000 | | | 975,000 | |
| 1,400,000 | | | | | 840,000 | | | 910,000 | | | 980,000 | | | 1,050,000 | |
| 1,500,000 | | | | | 900,000 | | | 975,000 | | | 1,050,000 | | | 1,125,000 | |
Average final compensation, for purposes of retirement benefits of executive officers, is generally equivalent to the average of the aggregate of the salary and bonus amounts reported in the Summary Compensation Table above under ‘Annual Compensation’ for the five years preceding retirement, not to exceed 150% of the average annual salary for such five year period. Messrs. Ferland, Selover, Busch, Izzo and Mrs. Rado will have accrued approximately 48, 43, 34, 36, and 29 years of credited service, respectively, as of age 65.
Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
Energy Holdings
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
PSEG
The information required by Item 12 of Form 10-K with respect to directors, executive officers and certain beneficial owners is set forth under the heading “Security Ownership of Directors, Management and Certain Beneficial Owners” in PSEG’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 20, 2004 which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 10, 2004, and such information set forth under such heading is incorporated herein by this reference thereto.
The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2003:
Plan Category | | Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights(A) | | Weighted-average
exercise price of
outstanding options,
warrants and rights | | Number of securities
remaining available
for future issuance
under equity
compensation plans | |
| | | | | | | | |
Equity Compensation plans approved
by security holders | | | 6,093,398 | | | | $ | 39.33 | | | | 8,742,433 | | |
Equity compensation plans not
approved by security holders | | | 2,951,533 | | | | $ | 39.48 | | | | 2,167,196 | | |
| | |
| | | |
|
| | | |
| | |
Total | | | 9,044,931 | | | | $ | 39.37 | | | | 10,909,629 | | |
| | |
| | | |
|
| | | |
| | |
(A)
Includes 164,000 shares granted under restricted stock agreements of certain key employees.
212
For additional discussion of specific plans concerning equity-based compensation, see Note 22. Stock Options and Employee Stock Purchase Plan of the Notes, Item 11. Executive Compensation for PSE&G, above, and the information set forth under the heading “Executive Compensation” in PSEG’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held on April 20, 2004 and expected to be filed with the SEC on or about March 10, 2004, which 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, PSEG, 80 Park Plaza, P.O. Box 1171, Newark, New Jersey.
The following table sets forth beneficial ownership of PSEG Common Stock, including options, by the directors and executive officers named below as of February 20, 2004. None of these amounts exceed 1% of the PSEG Common Stock outstanding at such date, except for the amount for all directors and executive officers as a group, which constitutes approximately 1.26%. No director or executive officer owns any of PSE&G’s Preferred Stock of any class.
Name | | Amount and
Nature of
Beneficial Ownership | |
| | | | |
Robert E. Busch | | 461,920 | (1) | |
Caroline Dorsa | | 2,353 | (2) | |
E. James Ferland | | 1,761,921 | (3) | |
Albert R. Gamper, Jr. | | 4,783 | (4) | |
Conrad K. Harper | | 6,400 | (5) | |
Ralph Izzo | | 369,511 | (6) | |
Patricia A. Rado | | 90,879 | (7) | |
R. Edwin Selover | | 271,473 | (8) | |
All directors and executive officers as a group (8 persons) | | 2,969,240 | (9) | |
(1)
Includes the equivalent of 181 shares held under PSEG Thrift and Tax-Deferred Savings Plan. Includes options to purchase 460,000 shares, 245,000 of which are currently exercisable.
(2)
Includes 1,600 shares of restricted stock awarded pursuant to the Stock Plan for Outside Directors described above in Item 11 under Compensation of Directors and Certain Business Relationships.
(3)
Includes the equivalent of 14,874 shares held under PSEG Thrift and Tax-Deferred Savings Plan. Includes options to purchase 1,465,000 shares, 1,115,000 of which are currently exercisable. Includes 130,000 shares of restricted stock, which vest as described above in Item 11. under Employment Contracts and Arrangements. Includes 80,000 shares held in a trust.
(4)
Includes 2,000 shares of restricted stock awarded pursuant to the Stock Plan for Outside Directors described above.
(5)
Includes 3,800 shares of restricted stock awarded pursuant to the Stock Plan for Outside Directors described above.
(6)
Includes the equivalent of 310 shares held under the PSEG Thrift and Tax-Deferred Savings Plan. Includes options to purchase 368,000 shares, 83,000 of which are exercisable.
(7)
Includes options to purchase 88,000 shares, 63,001 of which are currently exercisable.
(8)
Includes the equivalent of 11 shares held under the PSEG Thrift and Tax-Deferred Savings Plan. Includes options to purchase 260,000 shares, 183,334 of which are currently exercisable.
(9)
Includes the equivalent of 15,376 shares held under the PSEG Thrift and Tax-Deferred Savings Plan. Includes options to purchase 2,553,000 shares, 1,689,335 of which are currently exercisable. Includes 137,400 shares of restricted stock. Includes 80,000 shares held in a trust.
213
Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
Energy Holdings
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
PSEG
The information required by Item 13 of Form 10-K is set forth under the heading “Executive Compensation” in PSEG’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 20, 2004, which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 10, 2004. Such information set forth under such heading is incorporated herein by this reference thereto.
PSE&G
None.
Power
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
Energy Holdings
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by Item 14 of Form 10-K is set forth under the heading “Fees Billed to PSEG by Deloitte & Touche LLP for 2003 and 2002” in PSEG’s definitive Proxy Statement for the Annual Meeting of Stockholders to be held April 20, 2004, which definitive Proxy Statement is expected to be filed with the U.S. Securities and Exchange Commission (SEC) on or about March 10, 2004. Such information set forth under such heading is incorporated herein by this reference thereto.
PART IV
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(A)
The following Financial Statements are filed as a part of this report:
a.
Public Service Enterprise Group Incorporated’s Consolidated Balance Sheets as of December 31, 2003 and 2002 and the related Consolidated Statements of Operations, Cash Flows and Common Stockholders’ Equity for the three years ended December 31, 2003 on pages 100 and 101, 99, 102 and 103, respectively.
b.
Public Service Electric and Gas Company’s Consolidated Balance Sheets as of December 31, 2003 and 2002 and the related Consolidated Statements of Operations, Cash Flows and Common Stockholder’s Equity for the three years ended December 31, 2003 on pages 106 and 107, 105, 108 and 109, respectively.
c.
PSEG Power LLC Consolidated Balance Sheets as of December 31, 2003 and 2002 and the related Consolidated Statements of Operations, Cash Flows and Capitalization and Member’s Equity for the three years ended December 31, 2003 on pages 111, 110, 112 and 113, respectively.
214
d.
PSEG Energy Holdings LLC Consolidated Balance Sheets as of December 31, 2003 and 2002 and the related Consolidated Statements of Operations, Cash Flows and Member’s/Common Stockholder’s Equity for the three years ended December 31, 2003 on pages 116 and 117, 115, 118 and 119, respectively.
(B)
The following documents are filed as a part of this report:
a.
PSEG Financial Statement Schedules:
Schedule II — Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2003 (page 230).
b.
PSE&G Financial Statement Schedules:
Schedule II — Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2003 (page 231).
c.
Power’s Financial Statement Schedules:
Schedule II — Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2003 (page 231).
d.
Energy Holdings’ Financial Statement Schedules:
Schedule II — Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2003 (page 232).
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 documents are filed as part of this report:
LIST OF EXHIBITS
a. PSEG:
3a | | Certificate of Incorporation Public Service Enterprise Group Incorporated1 |
| | |
3b | | By-Laws of Public Service Enterprise Group Incorporated2 |
| | |
3c | | Certificate of Amendment of Certificate of Incorporation of Public Service Enterprise Group Incorporated, effective April 23, 19873 |
| | |
3d | | Amended and Restated Trust Agreement for Enterprise Capital Trust I4 |
| | |
3e | | Amended and Restated Trust Agreement for Enterprise Capital Trust II5 |
| | |
3f | | Amended and Restated Trust Agreement for Enterprise Capital Trust III6 |
| | |
3g | | Amended and Restated Trust Agreement for PSEG Funding Trust I7 |
| | |
3h | | Amended and Restated Trust Agreement for PSEG Funding Trust II8 |
| | |
4a(1) | | Indenture between Public Service Enterprise Group Incorporated and First Union National Bank (now, Wachovia Bank, National Association), as Trustee, dated January 1, 1998 providing for Deferrable Interest Subordinated Debentures in Series (relating to Quarterly Preferred Securities)9 |
| | |
4a(2) | | First Supplemental Indenture to Indenture dated as of January 1, 1998 between Public Service Enterprise Group Incorporated and First Union National Bank (now, Wachovia Bank, National Association), as Trustee, dated June 1, 1998 providing for the issuance of Floating Rate Deferrable Interest Subordinated Debentures, Series B (relating to Trust Preferred Securities)10 |
| | |
4a(3) | | Second Supplemental Indenture to Indenture dated as of January 1, 1998 between Public Service Enterprise Group Incorporated and First Union National Bank (now, Wachovia Bank, National Association), as Trustee, dated July 1, 1998 providing for the issuance of Deferrable Interest Subordinated Debentures, Series C (relating to Trust Preferred Securities)11 |
| | |
4b | | Indenture dated as of November 1, 1998 between Public Service Enterprise Group Incorporated and First Union National Bank (now, Wachovia Bank, National Association) providing for the issuance of Senior Debt Securities12 |
| | |
4c | | First Supplemental Indenture to Indenture dated as of November 1, 1998 between Public Service Enterprise Group Incorporated and Wachovia Bank, National Association, as Trustee, dated September 10, 2002 providing for the issuance of Senior Deferrable Notes
(Senior Debt Securities)13 |
| | |
215
4d | | Indenture dated as of December 17, 2002 between Public Service Enterprise Group Incorporated and Wachovia Bank, National Association providing for the issuance of Debentures in Series including 8.75% Deferrable Interest Junior Subordinated Debentures, Series D14 |
| | |
9 | | Inapplicable |
| | |
10a(1) | | Deferred Compensation Plan for Directors15 |
| | |
10a(2) | | Deferred Compensation Plan for Certain Employees16 |
| | |
10a(3) | | Limited Supplemental Benefits Plan for Certain Employees17 |
| | |
10a(4) | | Mid Career Hire Supplemental Retirement Income Plan18 |
| | |
10a(5) | | Retirement Income Reinstatement Plan for Non-Represented Employees19 |
| | |
10a(6) | | 1989 Long-Term Incentive Plan, as amended20 |
| | |
10a(7) | | 2001 Long-Term Incentive Plan21 |
| | |
10a(8) | | Restated and Amended Management Incentive Compensation Plan22 |
| | |
10a(9) | | Employment Agreement with E. James Ferland dated June 16, 199823 |
| | |
10a(10) | | Amendment to Employment Agreement with E. James Ferland dated November 20, 200124 |
| | |
10a(11) | | Employment Agreement with Thomas M. O’Flynn dated April 18, 200125 |
| | |
10a(12) | | Amendment to Employment Agreement with Thomas M. O’Flynn dated December 21, 200126 |
| | |
10a(13) | | Letter Agreement with Patricia A. Rado dated March 24, 199327 |
| | |
10a(14) | | Employment Agreement with Ralph Izzo dated October 18, 200328 |
| | |
10a(15) | | Employment Agreement with Frank Cassidy dated October 17, 200029 |
| | |
10a(16) | | Employment Agreement with Robert J. Dougherty, Jr. dated October 17, 200030 |
| | |
10a(17) | | Stock Plan for Outside Directors, as amended31 |
| | |
10a(18) | | Employment Agreement with Robert E. Busch dated April 24, 200132 |
| | |
10a(19) | | Employee Stock Purchase Plan33 |
| | |
10a(20) | | Compensation Plan for Outside Directors34 |
| | |
10a(21) | | 2004 Long-Term Incentive Plan |
| | |
11 | | Inapplicable |
| | |
12 | | Computation of Ratios of Earnings to Fixed Charges |
| | |
13 | | Inapplicable |
| | |
14 | | Code of Ethics |
| | |
16 | | Inapplicable |
| | |
18 | | Inapplicable |
| | |
21 | | Subsidiaries of the Registrant |
| | |
22 | | Inapplicable |
| | |
23 | | Independent Auditors’ Consent |
| | |
24 | | Inapplicable |
| | |
31a | | Certification by E. James Ferland, pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act |
| | |
31b | | Certification by Thomas M. O’Flynn pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act |
| | |
32a | | Certification by E. James Ferland, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code |
| | |
216
32b | | Certification by Thomas M. O’Flynn, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code |
| | |
3a(1) | | Restated Certificate of Incorporation of PSE&G35 |
| | |
3a(2) | | Certificate of Amendment of 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 Act36 |
| | |
3a(3) | | Certificate of Amendment of 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 Preferred Stock37 |
| | |
3a(4) | | Certificate of Amendment of 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 Stock38 |
| | |
3a(5) | | Certificate of Amendment of 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 Stock39 |
| | |
3b(1) | | Copy of By-Laws of PSE&G40 |
| | |
3c | | Trust Agreement for PSE&G Capital Trust III41 |
| | |
3d | | Trust Agreement for PSE&G Capital Trust IV42 |
| | |
4a(1) | | Indenture between PSE&G and Fidelity Union Trust Company (now, Wachovia Bank, National Association), as Trustee, dated August 1, 1924, securing First and Refunding Mortgage Bond43 |
| | |
| | Indentures between PSE&G and First Fidelity Bank, National Association (now, Wachovia Bank, National Association), as Trustee, supplemental to Exhibit 4a(1), dated as follows: |
| | |
4a(2) | | April 1, 192744 |
| | |
4a(3) | | June 1, 193745 |
| | |
4a(4) | | July 1, 193746 |
| | |
4a(5) | | December 19, 193947 |
| | |
4a(6) | | March 1, 194248 |
| | |
4a(7) | | June 1, 194949 |
| | |
4a(8) | | May 1, 195050 |
| | |
4a(9) | | October 1, 195351 |
| | |
4a(10) | | May 1, 195452 |
| | |
4a(11) | | November 1, 195653 |
| | |
4a(12) | | September 1, 195754 |
| | |
4a(13) | | August 1, 195855 |
| | |
4a(14) | | June 1, 195956 |
| | |
4a(15) | | September 1, 196057 |
| | |
4a(16) | | August 1, 196258 |
| | |
4a(17) | | June 1, 196359 |
| | |
4a(18) | | September 1, 196460 |
| | |
4a(19) | | September 1, 196561 |
| | |
4a(20) | | June 1, 196762 |
| | |
4a(21) | | June 1, 196863 |
| | |
4a(22) | | April 1, 196964 |
217
4a(24) | | May 15, 197166 |
| | |
4a(25) | | November 15, 197167 |
| | |
4a(26) | | April 1, 197268 |
| | |
4a(27) | | March 1, 197469 |
| | |
4a(28) | | October 1, 197470 |
| | |
4a(29) | | April 1, 197671 |
| | |
4a(30) | | September 1, 197672 |
| | |
4a(31) | | October 1, 197673 |
| | |
4a(32) | | June 1, 197774 |
| | |
4a(33) | | September 1, 197775 |
| | |
4a(34) | | November 1, 197876 |
| | |
4a(35) | | July 1, 197977 |
| | |
4a(36) | | September 1, 1979 (No. 1)78 |
| | |
4a(37) | | September 1, 1979 (No. 2)79 |
| | |
4a(38) | | November 1, 197980 |
| | |
4a(39) | | June 1, 198081 |
| | |
4a(40) | | August 1, 198182 |
| | |
4a(41) | | April 1, 198283 |
| | |
4a(42) | | September 1, 198284 |
| | |
4a(43) | | December 1, 198285 |
| | |
4a(44) | | June 1, 198386 |
| | |
4a(45) | | August 1, 198387 |
| | |
4a(46) | | July 1, 198488 |
| | |
4a(47) | | September 1, 198489 |
| | |
4a(48) | | November 1, 1984 (No. 1)90 |
| | |
4a(49) | | November 1, 1984 (No. 2)91 |
| | |
4a(50) | | July 1, 198592 |
| | |
4a(51) | | January 1, 198693 |
| | |
4a(52) | | March 1, 198694 |
| | |
4a(53) | | April 1, 1986 (No. 1)95 |
| | |
4a(54) | | April 1, 1986 (No. 2)96 |
| | |
4a(55) | | March 1, 198797 |
| | |
4a(56) | | July 1, 1987 (No. 1)98 |
| | |
4a(57) | | July 1, 1987 (No. 2)99 |
| | |
4a(58) | | May 1, 1988100 |
| | |
4a(59) | | September 1, 1988101 |
| | |
4a(60) | | July 1, 1989102 |
| | |
4a(61) | | July 1, 1990 (No. 1)103 |
| | |
4a(62) | | July 1, 1990 (No. 2)104 |
| | |
4a(63) | | June 1, 1991 (No. 1)105 |
| | |
4a(64) | | June 1, 1991 (No. 2)106 |
| | |
4a(65) | | November 1, 1991 (No. 1)107 |
| | |
4a(66) | | November 1, 1991 (No. 2)108 |
| | |
4a(67) | | November 1, 1991 (No. 3)109 |
| | |
218
4a(68) | | February 1, 1992 (No. 1)110 |
| | |
4a(69) | | February 1, 1992 (No. 2)111 |
| | |
4a(70) | | June 1, 1992 (No. 1)112 |
| | |
4a(71) | | June 1, 1992 (No. 2)113 |
| | |
4a(72) | | June 1, 1992 (No. 3)114 |
| | |
4a(73) | | January 1, 1993 (No. 1)115 |
| | |
4a(74) | | January 1, 1993 (No. 2)116 |
| | |
4a(75) | | March 1, 1993117 |
| | |
4a(76) | | May 1, 1993118 |
| | |
4a(77) | | May 1, 1993 (No. 2)119 |
| | |
4a(78) | | May 1, 1993 (No. 3)120 |
| | |
4a(79) | | July 1, 1993121 |
| | |
4a(80) | | August 1, 1993122 |
| | |
4a(81) | | September 1, 1993123 |
| | |
4a(82) | | September 1, 1993 (No. 2)124 |
| | |
4a(84) | | February 1, 1994125 |
| | |
4a(85) | | March 1, 1994 (No. 1)126 |
| | |
4a(86) | | March 1, 1994 (No. 2)127 |
| | |
4a(87) | | May 1, 1994128 |
| | |
4a(88) | | June 1, 1994129 |
| | |
4a(89) | | August 1, 1994130 |
| | |
4a(90) | | October 1, 1994 (No. 1)131 |
| | |
4a(91) | | October 1, 1994 (No. 2)132 |
| | |
4a(92) | | January 1, 1996 (No. 1)133 |
| | |
4a(93) | | January 1, 1996 (No. 2)134 |
| | |
4a(94) | | December 1, 1996135 |
| | |
4a(95) | | June 1, 1997136 |
| | |
4a(96) | | May 1, 1998137 |
| | |
4a(97) | | September 1, 2002138 |
| | |
4a(98) | | August 1, 2003 |
| | |
4a(99) | | December 1, 2003 (No. 1) |
| | |
4a(100) | | December 1, 2003 (No. 2) |
| | |
4a(101) | | December 1, 2003 (No. 3) |
| | |
4a(102) | | December 1, 2003 (No. 4) |
| | |
4b | | Indenture of Trust between PSE&G and Chase Manhattan Bank (National Association) (now, JP Morgan Chase Bank, NA), as Trustee, providing for Secured Medium-Term Notes dated July 1, 1993139 |
| | |
4c | | Indenture dated as of December 1, 2000 between Public Service and Gas Company and First Union National Bank (now, Wachovia Bank, National Association), as Trustee, providing for Senior Debt Securities.140 |
| | |
10a(1) | | Deferred Compensation Plan for Directors15 |
| | |
10a(2) | | Deferred Compensation Plan for Certain Employees16 |
| | |
10a(3) | | Limited Supplemental Benefits Plan for Certain Employees17 |
| | |
10a(4) | | Mid Career Hire Supplemental Retirement Income Plan18 |
| | |
10a(5) | | Retirement Income Reinstatement Plan for Non-Represented Employees19 |
| | |
219
10a(6) | | 1989 Long-Term Incentive Plan, as amended20 |
| | |
10a(7) | | 2001 Long-Term Incentive Plan21 |
| | |
10a(8) | | Restated and Amended Management Incentive Compensation Plan22 |
| | |
10a(9) | | Employment Agreement with E. James Ferland, dated June 16, 199823 |
| | |
10a(10) | | Amendment to Employment Agreement with E. James Ferland dated November 20, 200124 |
| | |
10a(11) | | Letter Agreement with Patricia A. Rado dated March 24, 199327 |
| | |
10a(12) | | Employment Agreement with Ralph Izzo dated October 18, 200328 |
| | |
10a(13) | | Employment Agreement with Robert E. Busch dated April 24, 200132 |
| | |
10a(14) | | Employee Stock Purchase Plan33 |
| | |
10a(15) | | Stock Plan for Outside Directors, as amended31 |
| | |
10a(16) | | Compensation Plan for Outside Directors34 |
| | |
10a(17) | | 2004 Long-Term Incentive Plan |
| | |
11 | | Inapplicable |
| | |
12a | | Computation of Ratios of Earnings to Fixed Charges |
| | |
12b | | Computation of Ratios of Earnings to Fixed Charges Plus Preferred Stock Dividend Requirements |
| | |
13 | | Inapplicable |
| | |
14 | | Code of Ethics |
| | |
16 | | Inapplicable |
| | |
18 | | Inapplicable |
| | |
19 | | Inapplicable |
| | |
21a | | Inapplicable |
| | |
23a | | Independent Auditors’ Consent |
| | |
24 | | Inapplicable |
| | |
31c | | Certification by E. James Ferland, pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act |
| | |
31d | | Certification by Robert E. Busch pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act |
| | |
32c | | Certification by E. James Ferland, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code |
| | |
32d | | Certification by Robert E. Busch, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code |
| | |
| C. Power: | | |
| | |
3a | | Certificate of Formation of PSEG Power LLC141 |
| | |
3b | | PSEG Power LLC Limited Liability Company Agreement142 |
| | |
3c | | Trust Agreement for PSEG Power Capital Trust I143 |
| | |
3d | | Trust Agreement for PSEG Power Capital Trust II144 |
| | |
3e | | Trust Agreement for PSEG Power Capital Trust III145 |
| | |
3f | | Trust Agreement for PSEG Power Capital Trust IV146 |
| | |
3g | | Trust Agreement for PSEG Power Capital Trust V147 |
| | |
4a | | Indenture dated April 16, 2001 between and among PSEG Power, PESG Fossil, PSEG Nuclear, PSEG Energy Resources & Trade and The Bank of New York and form of Subsidiary Guaranty included therein.148 |
| | |
4b | | First Supplemental Indenture, supplemental to Exhibit 4a, dated as of March 13, 2002.149 |
| | |
10a(1) | | Deferred Compensation Plan for Certain Employees16 |
| | |
10a(2) | | Limited Supplemental Benefits Plan for Certain Employees17 |
| | |
10a(3) | | Mid Career Hire Supplemental Retirement Income Plan18 |
| | |
220
10a(4) | | Retirement Income Reinstatement Plan for Non-Represented Employees19 |
| | |
10a(5) | | 1989 Long-Term Incentive Plan, as amended20 |
| | |
10a(6) | | 2001 Long-Term Incentive Plan21 |
| | |
10a(7) | | Restated and Amended Management Incentive Compensation Plan22 |
| | |
10a(8) | | Employment Agreement with E. James Ferland, dated June 16, 199823 |
| | |
10a(9) | | Amendment to Employment Agreement with E. James Ferland dated November 20, 200124 |
| | |
10a(10) | | Employment Agreement with Thomas M. O’Flynn dated April 18, 200125 |
| | |
10a(11) | | Amendment to Employment Agreement with Thomas M. O’Flynn dated December 21, 200126 |
| | |
10a(12) | | Letter Agreement with Patricia A. Rado dated March 24, 199327 |
| | |
10a(13) | | Employment Agreement with Frank Cassidy dated October 17, 200029 |
| | |
10a(14) | | Employee Stock Purchase Plan33 |
| | |
10a(15) | | 2004 Long-Term Incentive Plan |
| | |
11 | | Inapplicable |
| | |
12c | | Computation of Ratio of Earnings to Fixed Charges |
| | |
13 | | Inapplicable |
| | |
14 | | Code of Ethics |
| | |
16 | | Inapplicable |
| | |
18 | | Inapplicable |
| | |
19 | | Inapplicable |
| | |
23 | | Independent Auditors’ Consent |
| | |
24 | | Inapplicable |
| | |
31e | | Certification by E. James Ferland, pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act |
| | |
31f | | Certification by Thomas M. O’Flynn pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act |
| | |
32e | | Certification by E. James Ferland, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code |
| | |
32f | | Certification by Thomas M. O’Flynn, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code |
| | |
| d. Energy Holdings: |
| | |
3a | | Certificate of Formation of PSEG Energy Holdings L.L.C.150 |
| | |
3b | | Certificate of Amendment to Certificate of Formation of PSEG Energy Holdings L.L.C.151 |
| | |
3c | | Limited Liability Company Agreement of PSEG Energy Holdings L.L.C.152 |
| | |
4a | | Indenture dated October 8, 1999 between Energy Holdings and First Union National Bank (now Wachovia Bank, National Association).153 |
| | |
4b | | First Supplemental Indenture to Exhibit 4a between Energy Holdings and Wachovia Bank, National Association dated September 30, 2002.154 |
| | |
10a(1) | | Deferred Compensation Plan for Certain Employees16 |
| | |
10a(2) | | Limited Supplemental Benefits Plan for Certain Employees17 |
| | |
10a(3) | | Mid Career Hire Supplemental Retirement Income Plan18 |
| | |
10a(4) | | Retirement Income Reinstatement Plan for Non-Represented Employees19 |
| | |
10a(5) | | 1989 Long-Term Incentive Plan, as amended20 |
| | |
10a(6) | | 2001 Long-Term Incentive Plan21 |
| | |
10a(7) | | Restated and Amended Management Incentive Compensation Plan22 |
| | |
10a(8) | | Employment Agreement with E. James Ferland, dated June 16, 199823 |
| | |
10a(9) | | Amendment to Employment Agreement with E. James Ferland dated November 20, 200124 |
| | |
10a(10) | | Employment Agreement with Thomas M. O’Flynn dated April 18, 200125 |
| | |
10a(11) | | Amendment to Employment Agreement with Thomas M. O’Flynn dated December 21, 200126 |
| | |
10a(12) | | Employment Agreement with Robert J. Dougherty, Jr. dated October 17, 200030 |
| | |
10a(13) | | Employee Stock Purchase Plan33 |
| | |
10a(14) | | 2004 Long-Term Incentive Plan |
| | |
221
11 | | Inapplicable |
| | |
12d | | Computation of Ratios of Earnings to Fixed Charges |
| | |
13 | | Inapplicable |
| | |
14 | | Code of Ethics |
| | |
16 | | Inapplicable |
| | |
19 | | Inapplicable |
| | |
24 | | Inapplicable |
| | |
31g | | Certification by E. James Ferland, pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act |
| | |
31h | | Certification by Thomas M. O’Flynn pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act |
| | |
32g | | Certification by E. James Ferland, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code |
| | |
32h | | Certification by Thomas M. O’Flynn, pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code |
(1) | | Filed as Exhibit 3(a) to Registration Statement on Form S-4, No. 33-2935 and incorporated herein by this reference. |
| | |
(2) | | Filed as Exhibit 4.3 to Registration Statement on Form S-3, No. 333-86372 filed on April 16, 2002 and incorporated herein by this reference. |
| | |
(3) | | Filed as Exhibit 3(c) with Annual Report on Form 10-K for the year ended December 31, 1987, File No. 001-09120 on April 11, 1988 and incorporated herein by this reference. |
| | |
(4) | | Filed as Exhibit 3d with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120 on February 26, 2003 and incorporated herein by this reference. |
| | |
(5) | | Filed as Exhibit 3 with Quarterly Report on Form 10-Q for the Quarter ended June 30, 1998, File No. 001-09120 on August 14, 1998 and incorporated herein by this reference. |
| | |
(6) | | Filed as Exhibit 3(f) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120 on February 26, 2003 and incorporated herein by this reference. |
| | |
(7) | | Filed as Exhibit 4.3 with Current Report on Form 8-K, File No. 001-09120 on September 9, 2002 and incorporated herein by this reference. |
| | |
(8) | | Filed as Exhibit 3(h) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120 on February 26, 2003 and incorporated herein by this reference. |
| | |
(9) | | Filed as Exhibit 4(f) with Quarterly Report on Form 10-Q for the Quarter ended March 31, 1998, File No. 001-09120 on May 13, 1998 and incorporated herein by this reference. |
| | |
(10) | | Filed as Exhibit 4(a) with Current Report on Form 8-K, File No. 001-09120 on August 14, 1998 and incorporated herein by this reference. |
| | |
(11) | | Filed as Exhibit 4(b) with Current Report on Form 8-K, File No. 001-09120 on August 14, 1998 and incorporated herein by this reference. |
| | |
(12) | | Filed as Exhibit 4(f) with Annual Report on Form 10-K for the year ended December 31, 1998, File No. 001-09120 on February 22, 1999 and incorporated herein by this reference. |
| | |
(13) | | Filed as Exhibit 4(c) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120 on February 26, 2003 and incorporated herein by this reference. |
| | |
(14) | | Filed as Exhibit 4(d) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120 on February 26, 2003 and incorporated herein by this reference. |
| | |
(15) | | Filed as Exhibit 10a(1) with Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-09120, on February 25, 2000 and incorporated herein by this reference. |
| | |
(16) | | Filed as Exhibit 10a(2) with Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-09120, on February 25, 2000 and incorporated herein by this reference. |
| | |
(footnotes continued on next page)
222
(footnotes continued from previous page)
(17) | | Filed as Exhibit 10a(3) with Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-09120, on February 25, 2000 and incorporated herein by this reference. |
| | |
(18) | | Filed as Exhibit 10a(4) with Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-09120, on February 25, 2000 and incorporated herein by this reference. |
| | |
(19) | | Filed as Exhibit 10a(5) with Annual Report on Form 10-K for the year ended December 31, 1999, File No. 001-09120, on February 25, 2000 and incorporated herein by this reference. |
| | |
(20) | | Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the Quarter ended September 30, 2002, File No. 001-09120, on November 2, 2002 and incorporated herein by this reference. |
| | |
(21) | | Filed as Exhibit 10a(7) with Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-09120, on March 6, 2001 and incorporated herein by this reference. |
| | |
(22) | | Filed as Exhibit 10a(8) with Annual Report on Form 10-K for the year ended December 31, 2000, File No. 001-09120, on March 6, 2001 and incorporated herein by this reference. |
| | |
(23) | | Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the Quarter ended June 30, 1998, File No. 001-09120, on August 14, 1998 and incorporated herein by this reference. |
| | |
(24) | | Filed as Exhibit 10a(10) with Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-09120, on March 1, 2002 and incorporated herein by this reference. |
| | |
(25) | | Filed as Exhibit 10a(24) with Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001, File No. 001-09120, on August 9, 2001 and incorporated herein by this reference. |
| | |
(26) | | Filed as Exhibit 10a(12) with Annual Report on Form 10-K for the year ended December 31, 2001, File No. 001-09120, on March 1, 2002 and incorporated herein by this reference. |
| | |
(27) | | Filed as Exhibit 10a(14) with Annual Report on Form 10-K for the year ended December 31, 1993, File No. 001-09120, on February 26, 1994 and incorporated herein by this reference. |
| | |
(28) | | File as Exhibit 10 with Quarterly Report on Form 10-Q for the Quarter ended September 30, 2003, File No. 001-09120, on October 30, 2003 and incorporated herein by this reference. |
| | |
(29) | | Filed as Exhibit 10a(19) with Quarterly Report on Form 10-Q for the Quarter ended September 30, 2000, File No. 001-09120, on November 13, 2000 and incorporated herein by this reference. |
| | |
(30) | | Filed as Exhibit 10a(20) with Quarterly Report on Form 10-Q for the Quarter ended September 30, 2000, File No. 001-09120, on November 13, 2000 and incorporated herein by this reference. |
| | |
(31) | | Filed as Exhibit 10a(17) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference. |
| | |
(32) | | Filed as Exhibit 10a(23) with Quarterly Report on Form 10-Q for the Quarter ended June 30, 2001, File No. 001-09120, on August 9, 2001 and incorporated herein by this reference. |
| | |
(33) | | Filed with Registration Statement on Form S-8, File No. 333-106330 filed on June 20, 2003 and incorporated herein by this reference. |
| | |
(34) | | Filed as Exhibit 10a(20) with Annual Report on Form 10-K for the year ended December 31, 2002, File No. 001-09120, on February 26, 2003 and incorporated herein by this reference. |
| | |
(35) | | Filed as Exhibit 3(a) with Quarterly Report on Form 10-Q for the Quarter ended June 30, 1986, File No. 001-00973, on August 28, 1986 and incorporated herein by this reference. |
| | |
(36) | | Filed as Exhibit 3a(2) with Annual Report on Form 10-K for the year ended December 31, 1987, File No. 001-00973, on March 28, 1988 and incorporated herein by this reference. |
| | |
(37) | | Filed as Exhibit 3a(3) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference. |
| | |
(footnotes continued on next page)
223
(footnotes continued from previous page)
(38) | | Filed as Exhibit 3a(4) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference. |
| | |
(39) | | Filed as Exhibit 3a(5) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference. |
| | |
(40) | | Filed as Exhibit 3b(1) with Quarterly Report on Form 10-Q for the Quarter ended June 30, 2000, No. 001-00973 filed on August 8, 2000 and incorporated herein by this reference. |
| | |
(41) | | Filed as Exhibit 3.6 to Registration Statement on Form S-3, No. 333-02763 filed on April 24, 1996 and incorporated herein by this reference. |
| | |
(42) | | Filed as Exhibit 3-2 to Registration Statement on Form S-3, File No. 333-76020 filed on December 27, 2001 and incorporated herein by this reference. |
| | |
(43) | | Filed as Exhibit 4b(1) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(44) | | Filed as Exhibit 4b(2) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| |
(45) | | Filed as Exhibit 4b(3) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(46) | | Filed as Exhibit 4b(4) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(47) | | Filed as Exhibit 4b(5) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(48) | | Filed as Exhibit 4b(6) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(49) | | Filed as Exhibit 4b(7) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(50) | | Filed as Exhibit 4b(8) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(51) | | Filed as Exhibit 4b(9) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(52) | | Filed as Exhibit 4b(10) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(53) | | Filed as Exhibit 4b(11) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(54) | | Filed as Exhibit 4b(12) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(55) | | Filed as Exhibit 4b(13) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(56) | | Filed as Exhibit 4b(14) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(57) | | Filed as Exhibit 4b(15) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(58) | | Filed as Exhibit 4b(16) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(59) | | Filed as Exhibit 4b(17) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(footnotes continued on next page)
224
(footnotes continued from previous page)
(60) | | Filed as Exhibit 4b(18) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(61) | | Filed as Exhibit 4b(19) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(62) | | Filed as Exhibit 4b(20) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(63) | | Filed as Exhibit 4b(21) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(64) | | Filed as Exhibit 4b(22) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(65) | | Filed as Exhibit 4b(23) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(66) | | Filed as Exhibit 4b(24) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| |
(67) | | Filed as Exhibit 4b(25) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(68) | | Filed as Exhibit 4b(26) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(69) | | Filed as Exhibit 4b(27) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(70) | | Filed as Exhibit 4b(28) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(71) | | Filed as Exhibit 4b(29) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(72) | | Filed as Exhibit 4b(30) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(73) | | Filed as Exhibit 4b(31) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(74) | | Filed as Exhibit 4b(32) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(75) | | Filed as Exhibit 4b(33) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(76) | | Filed as Exhibit 4b(34) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(77) | | Filed as Exhibit 4b(35) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(78) | | Filed as Exhibit 4b(36) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(79) | | Filed as Exhibit 4b(37) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(80) | | Filed as Exhibit 4b(38) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(81) | | Filed as Exhibit 4b(39) with Annual Report on Form 10-K for the Year ended December 31, 1980, File No. 001-00973 on February 18, 1981 and incorporated herein by this reference. |
| | |
(footnotes continued on next page)
225
(footnotes continued from previous page)
(82) | | Filed as Exhibit 2 on Form 8-A, File No. 001-00973 on August 19, 1981 and incorporated herein by this reference. |
| | |
(83) | | Filed as Exhibit 4e with Current Report on Form 8-K, File No. 001-00973 on April 29, 1982 and incorporated herein by this reference. |
| | |
(84) | | Filed as Exhibit 2 on Form 8-A, File No. 001-00973 on September 17, 1982 and incorporated herein by this reference. |
| | |
(85) | | Filed as Exhibit 2 on Form 8-A, File No. 001-00973 on December 21, 1982 and incorporated herein by this reference. |
| | |
(86) | | Filed as Exhibit 4(ii) with Quarterly Report on Form 10-Q for the Quarter ended June 30, 1983, File No. 001-00973, on July 26, 1983 and incorporated herein by this reference. |
| | |
(87) | | Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on August 19, 1983 and incorporated herein by this reference. |
| | |
(88) | | Filed as Exhibit 4(ii) with Quarterly Report on Form 10-Q for the Quarter ended June 30, 1984, File No. 001-00973, on August 14, 1984 and incorporated herein by this reference. |
| |
(89) | | Filed as Exhibit 4(ii) with November 12, 1984 and incorporated herein by this reference. |
| | |
(90) | | Filed as Exhibit 4(i) with Current Report on Form 8-K, File No. 001-00973 on January 4, 1985 and incorporated herein by this reference. |
| | |
(91) | | Filed as Exhibit 4(ii) with Current Report on Form 8-K, File No. 001-00973 on January 4, 1985 and incorporated herein by this reference. |
| | |
(92) | | Filed as Exhibit 2 on Form 8-A, File No. 001-00973 on August 2, 1985 and incorporated herein by this reference. |
| | |
(93) | | Filed as Exhibit 4a(51) with Annual Report on Form 10-K for the Year ended December 31, 1985, File No. 001-00973 on February 11, 1986 and incorporated herein by this reference. |
| | |
(94) | | Filed as Exhibit 2 on Form 8-A, File No. 001-00973 on March 28, 1986 and incorporated herein by this reference. |
| | |
(95) | | Filed as Exhibit 2(a) on Form 8-A, File No. 001-00973 on May 1, 1986 and incorporated herein by this reference. |
| | |
(96) | | Filed as Exhibit 2(b) on Form 8-A, File No. 001-00973 on May 1, 1986 and incorporated herein by this reference. |
| | |
(97) | | Filed as Exhibit 4a(55) to Registration Statement on Form S-3, No. 33-13209 filed on April 9, 1987 and incorporated herein by this reference. |
| | |
(98) | | Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on August 17, 1987 and incorporated herein by this reference. |
| | |
(99) | | Filed as Exhibit 4 with Quarterly Report on Form 10-Q for the Quarter ended September 30, 1987, File No. 001-00973, on November 13, 1987 and incorporated herein by this reference. |
| | |
(100) | | Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on May 17, 1988 and incorporated herein by this reference. |
| | |
(101) | | Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on September 27, 1988 and incorporated herein by this reference. |
| | |
(102) | | Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on July 25, 1989 and incorporated herein by this reference. |
| | |
(103) | | Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on July 25, 1990 and incorporated herein by this reference. |
| | |
(footnotes continued on next page)
226
(footnotes continued from previous page)
(104) | | Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973 on July 25, 1990 and incorporated herein by this reference. |
| | |
(105) | | Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on July 1, 1991 and incorporated herein by this reference. |
| | |
(106) | | Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973 on July 1, 1991 and incorporated herein by this reference. |
| | |
(107) | | Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on December 2, 1991 and incorporated herein by this reference. |
| | |
(108) | | Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973 on December 2, 1991 and incorporated herein by this reference. |
| | |
(109) | | Filed as Exhibit 4(iii) on Form 8-A, File No. 001-00973 on December 2, 1991 and incorporated herein by this reference. |
| | |
(110) | | Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on February 27, 1992 and incorporated herein by this reference. |
| |
(111) | | Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973 on February 27, 1992 and incorporated herein by this reference. |
| | |
(112) | | Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on June 17, 1992 and incorporated herein by this reference. |
| | |
(113) | | Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973 on June 17, 1992 and incorporated herein by this reference. |
| | |
(114) | | Filed as Exhibit 4(iii) on Form 8-A, File No. 001-00973 on June 17, 1992 and incorporated herein by this reference. |
| | |
(115) | | Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on February 2, 1993 and incorporated herein by this reference. |
| | |
(116) | | Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973 on February 2, 1993 and incorporated herein by this reference. |
| | |
(117) | | Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on March 17, 1993 and incorporated herein by this reference. |
| | |
(118) | | Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on May 25, 1993 and incorporated herein by this reference. |
| | |
(119) | | Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973 on May 25, 1993 and incorporated herein by this reference. |
| | |
(120) | | Filed as Exhibit 4(iii) on Form 8-A, File No. 001-00973 on May 25, 1993 and incorporated herein by this reference. |
| | |
(121) | | Filed as Exhibit 4(i) with Current Report on Form 8-K, File No. 001-00973 on December 1, 1993 and incorporated herein by this reference. |
| | |
(122) | | Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on August 3, 1993 and incorporated herein by this reference. |
| | |
(123) | | Filed as Exhibit 4 with Current Report on Form 8-K, File No. 001-00973 on December 1, 1993 and incorporated herein by this reference. |
| | |
(124) | | Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on December 1, 1993 and incorporated herein by this reference. |
| | |
(125) | | Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on February 3, 1994 and incorporated herein by this reference. |
| | |
(footnotes continued on next page)
227
(footnotes continued from previous page)
(126) | | Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on March 15, 1994 and incorporated herein by this reference. |
| | |
(127) | | Filed as Exhibit 4(ii) on Form 8-A, File No. 001-00973 on March 15, 1994 and incorporated herein by this reference. |
| | |
(128) | | Filed as Exhibit 4a(87) with Quarterly Report on Form 10-Q for the Quarter ended September 30, 1994, File No. 001-00973, on November 8, 1994 and incorporated herein by this reference. |
| | |
(129) | | Filed as Exhibit 4a(88) with Quarterly Report on Form 10-Q for the Quarter ended September 30, 1994, File No. 001-00973, on November 8, 1994 and incorporated herein by this reference. |
| | |
(130) | | Filed as Exhibit 4a(89) with Quarterly Report on Form 10-Q for the Quarter ended September 30, 1994, File No. 001-00973, on November 8, 1994 and incorporated herein by this reference. |
| |
(131) | | Filed as Exhibit 4a(90) with Quarterly Report on Form 10-Q for the Quarter ended September 30, 1994, File No. 001-00973, on November 8, 1994 and incorporated herein by this reference. |
| | |
(132) | | Filed as Exhibit 4a(91) with Quarterly Report on Form 10-Q for the Quarter ended September 30, 1994, File No. 001-00973, on November 8, 1994 and incorporated herein by this reference. |
| | |
(133) | | Filed as Exhibit 4a(2) on Form 8-A, File No. 001-00973 on January 26, 1996 and incorporated herein by this reference. |
| | |
(134) | | Filed as Exhibit 4a(3) on Form 8-A, File No. 001-00973 on January 26, 1996 and incorporated herein by this reference. |
| | |
(135) | | Filed as Exhibit 4a(94) with Annual Report on Form 10-K for the Year ended December 31, 1996, File No. 001-00973 on February 27, 1997 and incorporated herein by this reference. |
| | |
(136) | | Filed as Exhibit 4a(2) on Form 8-A, File No. 001-00973 on June 17, 1997 and incorporated herein by this reference. |
| | |
(137) | | Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on May 15, 1998 and incorporated herein by this reference. |
| | |
(138) | | Filed as Exhibit 4a(97) with Annual Report on Form 10-K for the Year ended December 31, 2002, File No. 001-00973 on February 25, 2003 and incorporated herein by this reference. |
| | |
(139) | | Filed as Exhibit 4 with Current Report on Form 8-K, File No. 001-00973 on December 1, 1993 and incorporated herein by this reference. |
| | |
(140) | | Filed as Exhibit 4.6 to Registration Statement on Form S-3, No. 333-76020 filed on December 27, 2001 and incorporated herein by this reference. |
| | |
(141) | | Filed as Exhibit 3.1 to Registration Statement on Form S-4, No. 333-69228 filed on October 5, 2001 and incorporated herein by this reference. |
| | |
(142) | | Filed as Exhibit 3.2 to Registration Statement on Form S-4, No. 333-69228 filed on October 5, 2001 and incorporated herein by this reference. |
| | |
(143) | | Filed as Exhibit 3.6 to Registration Statement on Form S-3, No. 333-105704 filed on May 30, 2003 and incorporated herein by this reference. |
| | |
(144) | | Filed as Exhibit 3.7 to Registration Statement on Form S-3, No. 333-105704 filed on May 30, 2003 and incorporated herein by this reference. |
| | |
(145) | | Filed as Exhibit 3.8 to Registration Statement on Form S-3, No. 333-105704 filed on May 30, 2003 and incorporated herein by this reference. |
| | |
(footnotes continued on next page)
228
(footnotes continued from previous page)
(146) | | Filed as Exhibit 3.9 to Registration Statement on Form S-3, No. 333-105704 filed on May 30, 2003 and incorporated herein by this reference. |
| | |
(147) | | Filed as Exhibit 3.10 to Registration Statement on Form S-3, No. filed 333-105704 on May 30, 2003 and incorporated herein by this reference. |
| | |
(148) | | Filed as Exhibit 4.1 to Registration Statement on Form S-4, No. 333-69228 filed on October 5, 2001 and incorporated herein by this reference. |
| | |
(149) | | Filed as Exhibit 4.7 with Quarterly Report on Form 10-Q for the Quarter ended March 31, 2002, File No. 001-49614, on May 15, 2002 and incorporated herein by this reference. |
| | |
(150) | | Filed as Exhibit 3 with Current Report on Form 8-K, File No. 000-32503 on October 4, 2002 and incorporated herein by this reference. |
| | |
(151) | | Filed as Exhibit 3.1 with Current Report on Form 8-K, File No. 000-32503 on October 4, 2002 and incorporated herein by this reference. |
| |
(152) | | Filed as Exhibit 3.2 with Current Report on Form 8-K, File No. 000-32503 on October 4, 2002 and incorporated herein by this reference. |
| | |
(153) | | Filed as Exhibit 4.1 to Registration Statement on Form S-4, No. 333-95697 filed on January 28, 2000 and incorporated herein by this reference. |
| | |
(154) | | Filed as Exhibit 4 with Current Report on Form 8-K, File No. 000-32503 on October 4, 2002 and incorporated herein by this reference. |
(D)
The following reports on Form 8-K were filed during the last quarter of 2003 and the 2004 period covered by this report under Item 5:
a.
PSEG:
Items Reported | | Date of Report |
Items 5 and 9 | | October 22, 2003 |
Items 5 and 12 | | February 2, 2004 |
b.
PSE&G:
Items Reported | | Date of Report |
Items 5 and 9 | | October 22, 2003 |
Items 5 and 12 | | February 2, 2004 |
c.
Power:
Items Reported | | Date of Report |
Items 5 and 9 | | October 22, 2003 |
Items 5 and 12 | | February 2, 2004 |
d.
Energy Holdings:
Items Reported | | Date of Report |
Items 5 and 9 | | October 22, 2003 |
Items 5 and 12 | | February 2, 2004 |
229
SCHEDULE II
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
Schedule II—Valuation and Qualifying Accounts
Years Ended December 31, 2003—December 31, 2001
Column A | | Column B | | Column C | | Column D | | Column E | |
| | | | Additions | | | | | |
| | | |
| | | | | |
Description | | Balance at
Beginning
of Period | | Charged to
cost and
expenses | | Charged to
other
accounts -
describe | | Deductions -
describe | | Balance at
End of
Period | |
| | | | | | | | | | | | |
2003: | | | | | | | | | | | |
Allowance for Doubtful
Accounts | | | $ | 47 | | | | $ | 52 | | | | $ | — | | | | $ | 59 | (A)(E) | | | $ | 40 | | |
Materials and Supplies
Valuation Reserve | | | | 5 | | | | | 11 | (I) | | | | — | | | | | 1 | (B) | | | | 15 | | |
Other Reserves | | | | 12 | | | | | — | | | | | 2 | (G) | | | | — | | | | | 14 | | |
Other Valuation
Allowances | | | | 28 | | | | | 8 | | | | | — | | | | | 12 | (E)(F) | | | | 24 | | |
2002: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Allowance for Doubtful
Accounts | | | $ | 40 | | | | $ | 58 | | | | $ | — | | | | $ | 51 | (A)(H) | | | $ | 47 | | |
Materials and Supplies
Valuation Reserve | | | | 2 | | | | | 2 | | | | | 1 | (C) | | | | — | | | | | 5 | | |
Other Reserves | | | | 2 | | | | | 10 | (D) | | | | — | | | | | — | | | | | 12 | | |
Other Valuation
Allowances | | | | 29 | | | | | 2 | | | | | — | | | | | 3 | (E)(F) | | | | 28 | | |
2001: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Allowance for Doubtful
Accounts | | | $ | 41 | | | | $ | 45 | | | | $ | — | | | | $ | 46 | (A) | | | $ | 40 | | |
Materials and Supplies
Valuation Reserve | | | | 11 | | | | | — | | | | | — | | | | | 9 | (B) | | | | 2 | | |
Other Reserves | | | | 4 | | | | | — | | | | | — | | | | | 2 | (D) | | | | 2 | | |
Other Valuation
Allowances | | | | 41 | | | | | — | | | | | — | | | | | 12 | (E) | | | | 29 | | |
(A)
Accounts Receivable/Investments written off.
(B)
Reduced reserve to appropriate level and to remove obsolete inventory.
(C)
Acquired two Connecticut electric generating stations.
(D)
Includes various liquidity, credit and bad debt reserves.
(E)
Valuation allowances consolidated in connection with the acquisition of SAESA.
(F)
Recorded in connection with the sales of certain properties held by EGDC.
(G)
Includes fuel reserve related to Connecticut acquisition.
(H)
Reclassified to Discontinued Operations.
(I)
Increased reserve due to obsolescence, excess and damaged items.
230
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
Schedule II—Valuation and Qualifying Accounts
Years Ended December 31, 2003—December 31, 2001
Column A | | Column B | | Column C | | Column D | | Column E | |
| | | | Additions | | | | | |
| | | |
| | | | | |
Description | | Balance at
Beginning
of Period | | Charged to
cost and
expenses | | Charged to
other
accounts -
describe | | Deductions -
describe | | Balance at
End of
Period | |
| | | | | | | | | | | | |
| | (Millions) | |
2003: | | | | | | | | | | | |
Allowance for Doubtful Accounts | | | $ | 32 | | | | $ | 46 | | | | $ | — | | | | $ | 44 | (A) | | | $ | 34 | | |
2002: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Allowance for Doubtful Accounts | | | $ | 38 | | | | $ | 43 | | | | $ | — | | | | $ | 49 | (A) | | | $ | 32 | | |
2001: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Allowance for Doubtful Accounts | | | $ | 39 | | | | $ | 45 | | | | $ | — | | | | $ | 46 | (A) | | | $ | 38 | | |
(A)
Accounts Receivable/Investments written off.
PSEG POWER LLC
Schedule II — Valuation and Qualifying Accounts
Years Ended December 31, 2003 — December 31, 2001
Column A | | Column B | | Column C | | Column D | | Column E | |
| | | | Additions | | | | | |
| | | |
| | | | | |
Description | | Balance at
Beginning
of Period | | Charged to
cost and
expenses | | Charged to
other
accounts -
describe | | Deductions -
describe | | Balance at
End of
Period | |
| | | | | | | | | | | | |
| | (Millions) | |
2003: | | | | | | | | | | | |
Materials and Supplies Valuation Reserve | | | $ | 5 | | | | $ | 11 | (E) | | | $ | — | | | | $ | 1 | (A) | | | $ | 15 | | |
Other Reserves | | | | 12 | | | | | — | | | | $ | 2 | (D) | | | | — | | | | | 14 | | |
2002: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Materials and Supplies Valuation Reserve | | | $ | 2 | | | | $ | 2 | | | | $ | 1 | (B) | | | $ | — | | | | $ | 5 | | |
Other Reserves | | | | 2 | | | | | 10 | (C) | | | | — | | | | | — | | | | | 12 | | |
2001: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Materials and Supplies Valuation Reserve | | | $ | 11 | | | | $ | — | | | | $ | — | | | | $ | 9 | (A) | | | $ | 2 | | |
Other Reserves | | | | 4 | | | | | — | | | | | — | | | | | 2 | (C) | | | | 2 | | |
(A)
Reduced reserve to appropriate level and removed obsolete inventory.
(B)
Acquired two Connecticut electric generation stations.
(C)
Includes various liquidity, credit and bad debt reserves.
(D)
Includes fuel reserve related to Connecticut acquisition.
(E)
Increased reserve due to obsolescence, excess and damaged items.
231
PSEG ENERGY HOLDINGS LLC
Schedule II—Valuation and Qualifying Accounts
Years Ended December 31, 2003—December 31, 2001
Column A | | Column B | | Column C | | Column D | | Column E | |
| | | | Additions | | | | | |
| | | |
| | | | | |
Description | | Balance at
Beginning
of Period | | Charged to
cost and
expenses | | Charged to
other
accounts-
describe | | Deductions-
describe | | Balance at
End of
Period | |
| | | (millions) | |
|---|
2003: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Allowance for Doubtful Accounts | | | $ | 15 | | | | $ | 6 | | | | $ | — | | | | $ | 15 | (A) | | | $ | 6 | | |
Other Valuation Allowances | | | | 28 | | | | | 8 | | | | | — | | | | | 12 | (A)(B) | | | | 24 | | |
2002: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Allowance for Doubtful Accounts | | | $ | 2 | | | | $ | 15 | (C) | | | $ | — | | | | $ | 2 | (D) | | | $ | 15 | | |
Other Valuation Allowances | | | | 29 | | | | | 2 | | | | | — | | | | | 3 | (A)(B) | | | | 28 | | |
2001: | | | | | | | | | | | | | | | | | | | | | | | | | | |
Allowance for Doubtful Accounts | | | $ | 2 | | | | $ | — | | | | $ | — | | | | $ | — | | | | $ | 2 | | |
Other Valuation Allowances | | | | 41 | | | | | — | | | | | — | | | | | 12 | (A) | | | | 29 | | |
(A)
Valuation allowances consolidated in connection with the acquisition of SAESA.
(B)
Recorded in connection with the sales of certain properties held by EGDC, $1 million and $2 million in 2003 and 2002, respectively.
(C)
Reserve established for Accounts Receivable in Argentina.
(D)
Reclassified to Discontinued Operations.
232
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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED |
| | |
| By | /s/ E. JAMES FERLAND |
| |
|
| | E. James Ferland
Chairman of the Board, President and
Chief Executive Officer |
Date: February 25, 2004
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. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
Signature | | Title | | Date |
| | | | | |
| | | | |
/s/ E. JAMES FERLAND | | Chairman of the Board, | | February 25, 2004 |
| | President and Chief Executive Officer and Director (Principal Executive Officer) | | |
E. James Ferland | | | |
| | | | |
/s/ THOMAS M. O’FLYNN | | Executive Vice President and Chief | | February 25, 2004 |
| | Financial Officer (Principal Financial Officer) | | |
Thomas M. O’Flynn | | | |
| | | | |
/s/ PATRICIA A. RADO | | Vice President and Controller | | February 25, 2004 |
| | (Principal Accounting Officer) | | |
Patricia A. Rado | | | | |
| | | | |
/s/ CAROLINE DORSA | | Director | | February 25, 2004 |
| | | | |
Caroline Dorsa | | | | |
| | | | |
/s/ ERNEST H. DREW | | Director | | February 25, 2004 |
| | | | |
Ernest H. Drew | | | | |
| | | | |
/s/ ALBERT R. GAMPER, JR. | | Director | | February 25, 2004 |
| | | | |
Albert R. Gamper, Jr. | | | | |
| | | | |
/s/ CONRAD K. HARPER | | Director | | February 25, 2004 |
| | | | |
Conrad K. Harper | | | | |
| | | | |
/s/ WILLIAM V. HICKEY | | Director | | February 25, 2004 |
| | | | |
William V. Hickey | | | | |
| | | | |
/s/ SHIRLEY ANN JACKSON | | Director | | February 25, 2004 |
| | | | |
Shirley Ann Jackson | | | | |
| | | | |
/s/ THOMAS A. RENYI | | Director | | February 25, 2004 |
| | | | |
Thomas A. Renyi | | | | |
| | | | |
/s/ RICHARD J. SWIFT | | Director | | February 25, 2004 |
| | | | |
Richard J. Swift | | | | |
233
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. The signature of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| PUBLIC SERVICE ELECTRICAND GAS COMPANY |
| | |
| By | /s/ RALPH IZZO |
| |
|
| | Ralph Izzo
President and
Chief Operating Officer |
Date: February 25, 2004
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. The signatures of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
Signature | | Title | | Date |
| | | | | |
| | | | |
/s/ E. JAMES FERLAND | | Chairman of the Board and Chief | | February 25, 2004 |
| | Executive Officer and Director | | |
E. James Ferland | | (Principal Executive Officer) | | |
| | | | |
/s/ ROBERT E. BUSCH | | Senior Vice President—Finance and | | February 25, 2004 |
| | Chief Financial Officer | | |
Robert E. Busch | | (Principal Financial Officer) | | |
| | | | |
/s/ PATRICIA A. RADO | | Vice President and Controller | | February 25, 2004 |
| | (Principal Accounting Officer) | | |
Patricia A. Rado | | | | |
| | | | |
/s/ CAROLINE DORSA | | Director | | February 25, 2004 |
| | | | |
Caroline Dorsa | | | | |
| | | | |
/s/ ALBERT R. GAMPER, JR. | | Director | | February 25, 2004 |
| | | | |
Albert R. Gamper, Jr. | | | | |
| | | | |
/s/ CONRAD K. HARPER | | Director | | February 25, 2004 |
| | | | |
Conrad K. Harper | | | | |
234
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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| PSEG POWER LLC |
| | |
| By | /s/ FRANK CASSIDY |
| |
|
| | Frank Cassidy
President and
Chief Operating Officer |
Date: February 25, 2004
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. The signatures of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
Signature | | Title | | Date |
| | | | | |
| | | | |
/s/ E. JAMES FERLAND | | Chairman of the Board and | | February 25, 2004 |
| | Chief Executive Officer and Director | | |
E. James Ferland | | (Principal Executive Officer) | | |
| | | | |
/s/ THOMAS M. O’FLYNN | | Executive Vice President and Chief | | February 25, 2004 |
| | Financial Officer and Director | | |
Thomas M. O’Flynn | | (Principal Financial Officer) | | |
| | | | |
/s/ PATRICIA A. RADO | | Vice President and Controller | | February 25, 2004 |
| | (Principal Accounting Officer) | | |
Patricia A. Rado | | | | |
| | | | |
/s/ ROBERT E. BUSCH | | Director | | February 25, 2004 |
| | | | |
Robert E. Busch | | | | |
| | | | |
/s/ FRANK CASSIDY | | Director | | February 25, 2004 |
| | | | |
Frank Cassidy | | | | |
| | | | |
/s/ ROBERT J. DOUGHERTY, JR. | | Director | | February 25, 2004 |
| | | | |
Robert J. Dougherty, Jr. | | | | |
| | | | |
/s/ R. EDWIN SELOVER | | Director | | February 25, 2004 |
| | | | |
R. Edwin Selover | | | | |
235
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. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
| PSEG ENERGY HOLDINGS LLC |
| | |
| By | /s/ ROBERT J. DOUGHERTY, JR. |
| |
|
| | Robert J. Dougherty, Jr.
President and
Chief Operating Officer |
Date: February 25, 2004
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. The signatures of the undersigned shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
Signature | | Title | | Date |
| | | | | |
| | | | |
/s/ E. JAMES FERLAND | | Chairman of the Board and | | February 25, 2004 |
| | Chief Executive Officer and Director | | |
E. James Ferland | | (Principal Executive Officer) | | |
| | | | |
/s/ THOMAS M. O’FLYNN | | Executive Vice President and | | February 25, 2004 |
| | Chief Financial Officer and Director | | |
Thomas M. O’Flynn | | (Principal Financial Officer) | | |
| | | | |
/s/ DEREK M. DIRISIO | | Vice President and Controller | | February 25, 2004 |
| | (Principal Accounting Officer) | | |
Derek M. DiRisio | | | | |
| | | | |
/s/ ROBERT E. BUSCH | | Director | | February 25, 2004 |
| | | | |
Robert E. Busch | | | | |
| | | | |
/s/ FRANK CASSIDY | | Director | | February 25, 2004 |
| | | | |
Frank Cassidy | | | | |
| | | | |
/s/ ROBERT J. DOUGHERTY, JR. | | Director | | February 25, 2004 |
| | | | |
Robert J. Dougherty, Jr. | | | | |
| | | | |
/s/ R. EDWIN SELOVER | | Director | | February 25, 2004 |
| | | | |
R. Edwin Selover | | | | |
236
The following documents are filed as a part of this report:
a.
PSEG:
Exhibit 10a(21): 2004 Long-Term Incentive Plan
Exhibit 12: Computation of Ratios of Earnings to Fixed Charges
Exhibit 14: Code of Ethics
Exhibit 21: Subsidiaries of the Registrant
Exhibit 23: Independent Auditors’ Consent
Exhibit 31a: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934
Exhibit 31b: Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934
Exhibit 32a: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
Exhibit 32b: Certification by Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
b.
PSE&G:
Exhibit 4a(98): Supplemental Indenture dated August 1, 2003 to Mortgage Indenture
Exhibit 4a(99): Supplemental Indenture dated December 1, 2003 (No. 1) to Mortgage Indenture
Exhibit 4a(100): Supplemental Indenture dated December 1, 2003 (No. 2) to Mortgage Indenture
Exhibit 4a(101): Supplemental Indenture dated December 1, 2003 (No. 3) to Mortgage Indenture
Exhibit 4a(102): Supplemental Indenture dated December 1, 2003 (No. 4) to Mortgage Indenture
Exhibit 10a(17): 2004 Long-Term Incentive Plan
Exhibit 12a: Computation of Ratios of Earnings to Fixed Charges
Exhibit 12b: Computation of Ratios of Earnings to Fixed Charges Plus Preferred Stock Dividend Requirements
Exhibit 14: Code of Ethics
Exhibit 21a: Subsidiaries of Registrant
Exhibit 23a: Independent Auditors’ Consent
Exhibit 31c: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934
Exhibit 31d: Certification by Robert E. Busch Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934
Exhibit 32c: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
Exhibit 32d: Certification by Robert E. Busch Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
237
c.
Power:
Exhibit 10a(15): 2004 Long-Term Incentive Plan
Exhibit 12c: Computation of Ratios of Earnings to Fixed Charges
Exhibit 14: Code of Ethics
Exhibit 23b: Independent Auditors’ Consent
Exhibit 31e: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934
Exhibit 31f: Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934
Exhibit 32e: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
Exhibit 32f: Certification by Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
d.
Energy Holdings:
Exhibit 10a(14): 2004 Long-Term Incentive Plan
Exhibit 12d: Computation of Ratios of Earnings to Fixed Charges
Exhibit 14: Code of Ethics
Exhibit 31g: Certification by E. James Ferland Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934
Exhibit 31h: Certification by Thomas M. O’Flynn Pursuant to Rules 13a-14 and 15d-14 of the 1934 Securities Exchange Act of 1934
Exhibit 32g: Certification by E. James Ferland Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
Exhibit 32h: Certification by Thomas M. O’Flynn Pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code
238
