ITEM 1. BUSINESS
We were incorporated under the laws of the State of New Jersey in 1985 and our principal executive offices are located at 80 Park Plaza, Newark, New Jersey 07102. We conduct our business through three direct wholly owned subsidiaries, Power, PSE&G and Energy Holdings, each of which also has its principal executive offices at 80 Park Plaza, Newark, New Jersey 07102. PSEG Services Corporation (Services), our other wholly owned subsidiary, provides us and these operating subsidiaries with certain management, administrative and general services at cost.
We are an energy company with a diversified business mix. Our operations are located primarily in the Northeastern and Mid- Atlantic United States. Our business approach focuses on operational excellence, financial strength and disciplined investment. As a holding company, our profitability depends on our subsidiaries’ operating results. Below are descriptions of our direct operating subsidiaries.
Power
PSE&G
Energy Holdings
A Delaware limited liability company formed in 1999 that integrates its generating asset operations with its wholesale energy sales, fuel supply and energy trading functions.
Earns revenues from selling under contract or on the spot market a range of diverse products such as electricity, natural gas, capacity, emissions credits and a series of energy-related products used to optimize the operation of the energy grid.
A New Jersey corporation, incorporated in 1924, which is a franchised public utility in New Jersey. It is also the provider of last resort for gas and electric commodity service for end users in its service territory.
Earns revenues from its regulated rate tariffs under which it provides electric transmission and electric and gas distribution to residential, commercial and industrial customers in its service territory. It also offers appliance services and repairs to customers throughout its service territory.
Has also implemented demand response and energy efficiency programs and invested in solar generation within New Jersey.
A New Jersey limited liability
company (successor to a
corporation which was formed
in 1989) that invests and
operates through its two primary
subsidiaries.
Earns revenues primarily from its portfolio of lease investments and its solar generation projects.
The following is a more detailed description of our business, including a discussion of our:
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Business Operations and Strategy
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Competitive Environment
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Employee Relations
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Regulatory Issues
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Environmental Matters
BUSINESS OPERATIONS AND STRATEGY
Power
Through Power, we seek to produce low-cost energy by efficiently operating our nuclear, coal, gas and oil-fired generation facilities, while balancing generation production, fuel requirements and supply obligations through energy portfolio management. We use commodity contracts and financial instruments, combined with our owned generation, to cover our commitments for Basic Generation Service (BGS) in New Jersey and other bilateral supply contract agreements.
Products and Services
As a merchant generator, our profit is derived from selling a range of products and services under contract to power marketers and to others, such as investor-owned and municipal utilities, and to aggregators who resell energy to retail consumers, or in the spot market. These products and services include:
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Energy-the electrical output produced by generation plants that is ultimately delivered to customers for use in lighting, heating, air conditioning and operation of other electrical equipment. Energy is our principal product and is priced on a usage basis, typically in cents per kilowatt hour (kWh) or dollars per megawatt hour (MWh).
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Capacity-a product distinct from energy, is a market commitment that a given generation unit will be available to an Independent System Operator (ISO) for dispatch if it is needed to meet system demand. Capacity is typically priced in dollars per megawatt (MW) for a given sale period.
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Ancillary Services-related activities supplied by generation unit owners to the wholesale market, required by the ISO to ensure the safe and reliable operation of the bulk power system. Owners of generation units may bid units into the ancillary services market in return for compensatory payments. Costs to pay generators for ancillary services are recovered through charges imposed on market participants.
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Emissions Allowances and Congestion Credits-Emissions allowances (or credits) represent the right to emit a specific amount of certain pollutants. Allowance trading is used to control air pollution by providing economic incentives for achieving reductions in the emissions of pollutants. Congestion credits (or Financial Transmission Rights) are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly congestion price differences across a transmission path.
Power also sells wholesale natural gas, primarily through a full requirements Basic Gas Supply Service (BGSS) contract with PSE&G to meet the gas supply requirements of PSE&G's customers. This long-term contract was for an initial period which extended through March 31, 2012 and continues on a year-to-year basis thereafter, unless terminated by either party with a one year notice.
Approximately 46% of PSE&G’s peak daily gas requirements is provided from Power’s firm transportation capacity, which is available every day of the year. Power satisfies the remainder of PSE&G’s requirements from storage contracts, liquefied natural gas, seasonal purchases, contract peaking supply, propane and refinery gas. Based upon availability, Power also sells gas to others.
How Power Operates
We own approximately 13,226 MW of generation capacity located in the Northeast and Mid-Atlantic regions of the United States in some of the country’s largest and most developed electricity markets.
The map below shows the locations of our Northeast and Mid-Atlantic generation facilities
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Generation Capacity
Power has approved the expenditure of approximately $192 million for a steam path retrofit and related upgrades at its co-owned Peach Bottom Units 2 and 3. Unit 3 upgrades were completed in October 2011. Unit 2 upgrades were completed in October 2012. The balance of work to ensure efficient operation is expected to be completed by 2014. Total expenditures through December 31, 2012 were $154 million.
Power has also approved the expenditure of $419 million for an extended power uprate of the Peach Bottom nuclear units. The uprate is expected to result in an increase in Power’s share of nominal capacity by approximately 130 MW. The uprate is expected to be in service in 2015 for Unit 2 and 2016 for Unit 3. Total expenditures through December 31, 2012 were $73 million.
In 2011, we sold 2,000 MW of generation facilities we owned and operated in Texas. See Item 8. Financial Statements and Supplementary Data-Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies and Note 4. Discontinued Operations and Dispositions, for additional information.
For additional information on each of our generation facilities, see Item 2. Properties.
Our installed capacity utilizes a diverse mix of fuels: 45% gas, 28% nuclear, 18% coal, 8% oil and 1% pumped storage. This fuel diversity helps to mitigate risks associated with fuel price volatility and market demand cycles. Our total generating output in 2012 was approximately 53,000 gigawatt hours (GWh). The generation mix by fuel type has changed slightly in recent years due to the relatively favorable price of natural gas as compared to coal, making it more economical to run certain of our gas units than our coal units. The following table indicates the proportionate share of generating output by fuel type.
(A) Less than one percent.
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Generation Dispatch
Our generation units are typically characterized as serving one or more of three general energy market segments: base load; load following; and peaking, based on their operating capability and performance. On a capacity basis, our portfolio of generation assets consists of 33% base load, 43% load following and 24% peaking. This diversity helps to reduce the risk associated with market demand cycles and allows us to participate in the market at each segment of the dispatch curve.
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Base Load Units run the most and typically operate whenever they are available. These units generally derive revenues from energy and capacity sales. Variable operating costs are low due to the combination of highly efficient operations and the use of relatively lower-cost fuels. Performance is generally measured by the unit’s “capacity factor,” or the ratio of the actual output to the theoretical maximum output. In 2012, our base load capacity factors were as follows:
No assurances can be given that these capacity factors will be achieved in the future.
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Load Following Units typically operate between 20% and 80% of the time. The operating costs are higher per unit of output due to lower efficiency and/or the use of higher-cost fuels such as oil, natural gas and, in some cases, coal. They operate less frequently than base load units and derive revenues from energy, capacity and ancillary services.
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Peaking Units run the least amount of time and utilize higher-priced fuels. These units typically operate less than 20% of the time. Costs per unit of output tend to be much higher than for base load units. The majority of
revenues are from capacity and ancillary service sales. The characteristics of these units enable them to capture energy revenues during periods of high energy prices.
In the energy markets in which we operate, owners of power plants specify to the ISO prices at which they are prepared to generate and sell energy based on the marginal cost of generating energy from each individual unit. The ISOs will dispatch in merit order, calling on the lowest variable cost units first and dispatching progressively higher-cost units until the point that the entire system demand for power (known as the system “load”) is satisfied. Base load units are dispatched first, with load following units next, followed by peaking units.
During periods when one or more parts of the transmission grid are operating at full capability, thereby resulting in a constraint on the transmission system, it may not be possible to dispatch units in merit order without violating transmission reliability standards. Under such circumstances, the ISO will dispatch higher-cost generation out of merit order within the congested area and power suppliers will be paid an increased Locational Marginal Price (LMP) in congested areas, reflecting the bid prices of those higher-cost generation units.
The following chart depicts the merit order of dispatch of our units in PJM Interconnection L.L.C. (PJM), where most of our generation units are located, based on illustrative historical dispatch cost. It should be noted that market price fluctuations have resulted in changes from historical norms, with lower gas prices allowing some gas generation to displace some coal generation.
The size of each facility's fuel circle in the above chart illustrates the relative MW capacity of the generating capacity of that facility. For additional information on each of our generation facilities, see Item 2. Properties.
The bid price of the last unit dispatched by an ISO establishes the energy market-clearing price. After considering the market-clearing price and the effect of transmission congestion and other factors, the ISO calculates the LMP for every location in the system. The ISO pays all units that are dispatched their respective LMP for each MWh of energy produced, regardless of their specific bid prices. Since bids generally approximate the marginal cost of production, units with lower marginal costs typically generate higher operating profits than units with comparatively higher marginal costs.
This method of determining supply and pricing creates an environment in the markets such that natural gas prices often have a major impact on the price that generators will receive for their output, especially in periods of relatively strong demand. Therefore, significant changes in the price of natural gas will often translate into significant changes in the wholesale price of electricity. This can be seen in the following graphs which present historical annual spot prices and forward calendar prices as averaged over each year.
Historical data and forward prices would imply that the price of natural gas will continue to have a strong influence on the price of electricity in the primary markets in which we operate.
The prices reflected in the tables above do not necessarily illustrate our contract prices, but they are representative of market prices at relatively liquid hubs, with nearer-term forward pricing generally resulting from more liquid markets than pricing for later years. In addition, the prices do not reflect locational differences resulting from congestion or other factors, which can be considerable. While these prices provide some perspective on past and future prices, the forward prices are highly volatile and there can be no assurance that such prices will remain in effect or that we will be able to contract output at these forward prices.
Fuel Supply
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Nuclear Fuel Supply-To run our nuclear units we have long-term contracts for nuclear fuel. These contracts provide for:
•purchase of uranium (concentrates and uranium hexafluoride),
•conversion of uranium concentrates to uranium hexafluoride,
•enrichment of uranium hexafluoride, and
•fabrication of nuclear fuel assemblies.
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Coal Supply-Coal is the primary fuel for our Keystone, Conemaugh and Bridgeport stations. Coal is also used by Hudson and Mercer which operate on both coal and natural gas. We have coal contracts with numerous suppliers. Coal is delivered to our units through a combination of rail, truck, barge or ocean shipments.
In order to minimize emissions levels, our Bridgeport 3 unit uses a specific type of coal obtained from Indonesia. If the supply from Indonesia or equivalent coal from other sources was not available for this facility, its long-term operations would be adversely impacted since additional material capital expenditures would be required to modify our Bridgeport 3 station to enable it to operate using a broader mix of coal sources.
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Gas Supply-Natural gas is the primary fuel for the bulk of our load following and peaking fleet. We purchase gas directly from natural gas producers and marketers. These supplies are transported to New Jersey by four interstate pipelines with whom we have contracted. In addition, we have firm gas transportation contracts to serve our Bethlehem Energy Center (BEC) in New York.
We have 1.3 billion cubic feet-per-day of firm transportation capacity under contract to meet our obligations under the BGSS contract. On an as available basis, this firm transportation capacity may also be used to serve the gas supply needs of our generation fleet. We supplement that supply with a total storage capacity of 76 billion cubic feet.
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Oil-Oil is used as the primary fuel for one load following steam unit and nine combustion turbine peaking units and can be used as an alternate fuel by several load following and peaking units that have dual-fuel capability. Oil for operations is drawn from on-site storage and is generally purchased on the spot market and delivered by truck, barge or pipeline.
We expect to be able to meet the fuel supply demands of our customers and our own operations. However, the ability to maintain an adequate fuel supply could be affected by several factors not within our control, including changes in prices and demand, curtailments by suppliers, severe weather and other factors. For additional information, see Item 7. Management's Discussion and Analysis (MD&A)-Overview of 2012 and Future Outlook and Item 8. Financial Statements and Supplementary Data -Note 13. Commitments and Contingent Liabilities.
Markets and Market Pricing
Power’s generation assets are located in three centralized, competitive electricity markets operated by ISO organizations all of which are subject to the regulatory oversight of the Federal Energy Regulatory Commission (FERC):
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PJM Regional Transmission Organization-PJM conducts the largest centrally dispatched energy market in North America. It serves over 60 million people, nearly 20% of the total United States population, and has a peak demand of over 163,848 MW. The PJM Interconnection coordinates the movement of electricity through all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia. The majority of our generating stations operate in PJM.
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New York-The NYISO is the market coordinator for New York State and is responsible for managing the New York Power Pool and for administering its energy marketplace. This service area has a population of about 19 million and a peak demand of over 33,939 MW. Our BEC station operates in New York.
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New England-ISO-NE coordinates the movement of electricity in a region covering Maine, New Hampshire, Vermont, Massachusetts, Connecticut and Rhode Island. This service area has a population of about 14 million and a peak demand of over 28,130 MW. Our Bridgeport and New Haven stations operate in Connecticut.
The price of electricity varies by location in each of these markets. Depending upon our production and our obligations, these price differentials can serve to increase or decrease our profitability.
Commodity prices, such as electricity, gas, coal, oil and emissions, as well as the availability of our diverse fleet of generation units to produce these products, also have a considerable effect on our profitability. These commodity prices have been, and continue to be, subject to significant market volatility. Over the long-term, the higher the forward prices are, the more attractive an environment exists for us to contract for the sale of our anticipated output. However, higher prices also increase the cost of replacement power; thereby placing us at greater risk should our generating units fail to function effectively or otherwise become unavailable.
Over the past few years, a decline in wholesale natural gas prices has resulted in lower electricity prices. One of the reasons for the decline in natural gas prices is greater supply from shale production. This trend has reduced margin on forward sales as we re-contract our expected generation output.
In addition to energy sales, we also earn revenue from capacity payments for our generating assets. These payments are compensation for committing a portion of our capacity to the ISO for dispatch at its discretion. Capacity payments reflect the
value to the ISO of assurance that there is sufficient generating capacity available at all times to meet system reliability and energy requirements. Currently, there is sufficient capacity in the markets in which we operate. However, in certain areas of these markets there are transmission system constraints, raising concerns about reliability and creating a more acute need for capacity.
In PJM and ISO-NE, where we operate most of our generation, the market design for capacity payments provides for a structured, forward-looking, transparent capacity pricing mechanism. This is through the Reliability Pricing Model (RPM) in PJM and the Forward Capacity Market (FCM) in ISO-NE. These mechanisms provide greater transparency regarding the value of capacity, resulting in an improved pricing signal to prospective investors in new generating facilities so as to encourage expansion of capacity to meet future market demands.
The prices to be received by generating units in PJM for capacity have been set through RPM base residual auctions and depend upon the zone in which the generating unit is located. The majority of our PJM generating units are located in zones where the following prices have been set:
For each delivery year, the prices differ in the various areas of PJM, depending on the constraints in each area of the transmission system. Keystone and Conemaugh receive lower prices than the majority of our PJM generating units since there are fewer constraints in that region and our generating units in northern New Jersey usually receive higher pricing.
The price that must be paid by an entity serving load in the various zones is also set through these auctions. These prices can be higher or lower than the prices noted in the table above due to import and export capability to and from lower-priced areas.
Like PJM and ISO-NE, the NYISO provides capacity payments to its generating units, but unlike the other two markets, the New York market does not provide a forward price signal beyond a six month auction period.
On a prospective basis, many factors may affect the capacity pricing, including but not limited to:
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changes in load and demand,
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changes in the available amounts of demand response resources,
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changes in available generating capacity (including retirements, additions, derates, forced outages, etc.),
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increases in transmission capability between zones,
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changes to the pricing mechanism, including potentially increasing the number of zones to create more pricing sensitivity to changes in supply and demand, as well as other potential changes that PJM and the other ISOs may propose over time, and
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changes driven by legislative and/or regulatory action, that permit states to subsidize local electric power generation.
For additional information on the RPM and FCM markets, as well as on state subsidization through various mechanisms, see Regulatory Issues-Federal Regulation.
Hedging Strategy
In an attempt to mitigate volatility in our results, we seek to contract in advance for a significant portion of our anticipated electric output, capacity and fuel needs. We seek to sell a portion of our anticipated lower-cost generation over a multi-year forward horizon, normally over a period of two to three years. We believe this hedging strategy increases stability of earnings.
Among the ways in which we hedge our output are: (1) sales at PJM West and (2) BGS contracts. Sales at PJM West reflect block energy sales at the liquid PJM Western Hub and other transactions that seek to secure price certainty for our generation related products. In addition, the BGS-Fixed Price contract, a full requirements contract that includes energy and capacity, ancillary and other services, is awarded for three-year periods through an auction process managed by the New Jersey Board of Public Utilities (BPU). The volume of BGS contracts and the electric utilities that our generation operations serve will vary from year to year. Pricing for the BGS contracts, including a capacity component, for recent and future periods by purchasing utility is as follows:
We have obtained price certainty for all of our PJM and New England capacity through May 2016 through the RPM and FCM pricing mechanisms.
Although we enter into these hedges in an effort to provide price certainty for a large portion of our anticipated generation, there is variability in both our actual output as well as in our hedges. Our actual output will vary based upon total market demand, the relative cost position of our units compared to all units in the market and the operational flexibility of our units. Our hedge volume can also vary, depending on the type of hedge into which we have entered. The BGS auction, for example, results in a contract that provides for the supplier to serve a percentage of the default load of a New Jersey electric distribution company (EDC), that is, the load that remains after some customers have chosen to be served directly by third party suppliers. The amount of power supplied through the BGS auction varies based on the level of the EDC's default load, which is affected by the number of customers who choose a third party supplier, as well as by other factors such as weather and the economy.
Historically, the number of customers that have switched to third party suppliers was relatively constant, but in recent years, as market prices declined from past years' historic highs, there was additional incentive for more of the smaller commercial and industrial electric customers to switch. In a falling price environment, this has a negative impact on our margins, as the anticipated BGS pricing is replaced by lower spot market pricing. While this impact has been reduced as average BGS rates have declined to a level more closely resembling current market prices, customers may still see an incentive to switch to third party suppliers. We are unable to determine the degree to which this switching, or “migration,” will continue, but the impact on our results could be material.
As of February 6, 2013, we had contracted for the following percentages of our anticipated base load generation output for the next three years with modest amounts beyond 2015.
Our strategy is to maintain certain levels of uranium in inventory and to make periodic purchases to support such levels. Our nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements for the three years. We also have various long-term fuel purchase commitments for coal to support our fossil generation stations. These purchase obligations are consistent with our strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts.
We take a more opportunistic approach in hedging our anticipated natural gas-fired generation. The generation from these units is less predictable, as a significant portion of these units will only dispatch when aggregate market demand has exceeded the supply provided by lower-cost units.
In a changing market environment, this hedging strategy may cause our realized prices to differ materially from current market prices. In a rising price environment, this strategy normally results in lower margins than would have been the case if little or no hedging activity had been conducted. Alternatively, in a falling price environment, this hedging strategy will tend to create margins higher than those implied by the then current market.
PSE&G
Our public utility, PSE&G, distributes electric energy and gas to customers within a designated service territory running diagonally across New Jersey where approximately 6.2 million people, or about 70% of New Jersey's population resides.
Products and Services
Our utility operations primarily earn margins through the transmission and distribution of electricity and the distribution of gas.
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Transmission-the movement of electricity at high voltage from generating plants to substations and transformers, where it is then reduced to a lower voltage for distribution to homes, businesses and industrial customers. Our revenues for these services are based upon tariffs approved by the FERC.
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Distribution-the delivery of electricity and gas to the retail customer’s home, business or industrial facility. Our revenues for these services are based upon tariffs approved by the BPU.
We also earn margins through competitive services, such as appliance repair. The commodity portion of our utility business’ electric and gas sales is managed by BGS and BGSS suppliers. Pricing for those services are set by the BPU as a pass-through, resulting in no margin for our utility operations.
In addition to our current utility products and services, we have implemented several programs to increase the level of solar generation including:
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a program to help finance the installation of solar power systems throughout our electric service area, and
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a program to develop, own and operate solar power systems.
We have also implemented a set of energy efficiency and demand response programs to encourage conservation and energy efficiency by providing energy and cost saving measures directly to businesses and families. For additional information concerning these programs and the components of our tariffs, see Regulatory Issues.
How PSE&G Operates
We provide network transmission and point-to-point transmission services, which are coordinated with PJM, and provide distribution service to 2.2 million electric customers and 1.8 million gas customers in a service area that covers approximately 2,600 square miles running diagonally across New Jersey. We serve the most heavily populated, commercialized and industrialized territory in New Jersey, including its six largest cities and approximately three hundred suburban and rural communities.
Transmission
We use formula rates for our transmission investments. Formula-type rates provide a method of rate recovery where the transmission owner annually determines its revenue requirements through a fixed formula which considers Operations and Maintenance expenditures, Rate Base and capital investments and applies an approved return on equity (ROE) in developing the weighted average cost of capital. Our approved rates provide for a base ROE of 11.68% on existing and new transmission investment, while certain investments are entitled to earn an additional incentive rate. For more information on current transmission construction activities, see Regulatory Issues, Federal Regulation-Transmission Regulation.
Distribution
The primary business of our utility is the distribution of gas and electricity to end users in our service territory. Our load requirements were split among residential, commercial and industrial customers, as described below for 2012. We believe that we have all the franchise rights (including consents) necessary for our electric and gas distribution operations in the territory we serve.
While our customer base has remained steady, gas and electric load have declined as illustrated:
The decline in both electric and gas sales were impacted by the unfavorable winter weather experienced in 2012 and customer conservation as a result of the economy. The first six months of 2012 were the warmest first half of a year on record in the United States. Electric sales were also impacted by a decline in the Industrial sector.
Solar Generation
We have undertaken major initiatives in order to spur investment in solar power in New Jersey. For additional details, please refer to our discussion under Energy Policy.
Supply
Although commodity revenues make up almost 48% of our revenues, we make no margin on the supply of energy since the actual costs are passed through to our customers.
All electric and gas customers in New Jersey have the ability to choose their own electric energy and/or gas supplier. Pursuant to the BPU requirements, we serve as the supplier of last resort for electric and gas customers within our service territory that are not served by another supplier. As a practical matter, this means we are obligated to provide supply to a vast majority of residential customers and a smaller portion of commercial and industrial customers.
We procure the supply to meet our BGS obligations through auctions authorized by the BPU for New Jersey’s total BGS requirement. These auctions take place annually in February. Results of these auctions determine which energy suppliers are authorized to supply BGS to New Jersey’s EDCs. Once validated by the BPU, electricity prices for BGS service are set.
PSE&G procures the supply requirements of our default service BGSS gas customers through a full requirements contract with Power. The BPU has approved a mechanism designed to recover all gas commodity costs related to BGSS for residential customers. BGSS filings are made annually by June 1 of each year, with an effective date of October 1. Any difference between rates charged under the BGSS contract and rates charged to our residential customers is deferred and collected or refunded through adjustments in future rates. Commercial and industrial customers that do not have third party suppliers are also supplied under the BGSS arrangement. These customers are charged a market-based price largely determined by prices for commodity futures contracts.
Markets and Market Pricing
Historically, there has been significant volatility in commodity prices. Such volatility can have a considerable impact on us since a rising commodity price environment results in higher delivered electric and gas rates for customers. This could result in decreased demand for electricity and gas, increased regulatory pressures and greater working capital requirements as the collection of higher commodity costs from our customers may be deferred under our regulated rate structure. A declining commodity price on the other hand, would be expected to have the opposite effect. For additional information, including the impact of natural gas commodity prices on electricity prices such as BGS, see Item 7. MD&A-Overview of 2012 and Future Outlook.
Energy Holdings
Energy Holdings primarily owns and manages a portfolio of lease investments and solar generation projects and is exploring opportunities for additional investment in renewable generation.
Over the past several years, we have terminated all of our international leveraged leases in order to reduce the cash tax exposure related to these leases. We have also reduced our risk by opportunistically monetizing all of our previous international investments. In February, 2012, the California Public Utilities Commission approved the shutdown of GWF Power and we anticipate recovering the remaining book value of our investment. For additional information on these generation facilities, see Item 2. Properties.
Products and Services
The majority of our remaining $840 million of domestic lease investments are primarily energy-related leveraged leases. As of December 31, 2012, 67% of our total leveraged lease investments were rated as below investment grade by Standard & Poor's.
Our leveraged leasing portfolio is designed to provide a fixed rate of return. Leveraged lease investments 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 secured by the property subject to the lease. Such long-term financing is non-recourse to the lessor and, with respect to our lease investments, is not presented on our Consolidated Balance Sheets.
The lessor acquires economic and tax ownership of the asset and then leases it to the lessee for a period of time no greater than 80% of its remaining useful life. As the owner, the lessor is entitled to depreciate the asset under applicable federal and state tax guidelines. The lessor receives income from lease payments made by the lessee during the term of the lease and from tax benefits associated with interest and depreciation deductions with respect to the leased property. Our ability to realize these tax
benefits is dependent on operating gains generated by our other operating subsidiaries and allocated pursuant to the consolidated tax sharing agreement between us and our operating subsidiaries.
Lease rental payments are unconditional obligations of the lessee and are set at levels at least sufficient to service the non-recourse lease debt. The lessor is also entitled to any residual value associated with the leased asset at the end of the lease term. An evaluation of the after-tax cash flows to the lessor determines the return on the investment. Under accounting principles generally accepted in the United States (GAAP), the leveraged lease investment is recorded net of non-recourse debt and income is recognized as a constant return on the net unrecovered investment.
For additional information on leases, including the credit, tax and accounting risks, see Item 1A.
ITEM 1A. RISK FACTORS
The following factors should be considered when reviewing our business. These factors could have a material adverse impact on our financial position, results of operations or net cash flows and could cause results to differ materially from those expressed elsewhere in this document.
The factors discussed in Item 7. MD&A may also have a material adverse effect on our results of operations and cash flows and affect the market prices for our publicly-traded securities. While we believe that we have identified and discussed the key risk factors affecting our business, there may be additional risks and uncertainties that are not presently known or that are not currently believed to be significant.
We are subject to comprehensive and evolving regulation by federal, state and local regulatory agencies that affects, or may affect, our businesses.
We are subject to regulation by federal, state and local authorities. Changes in regulation can cause significant delays in or materially affect business planning and transactions and can materially increase our costs. Regulation affects almost every aspect of our businesses, such as our ability to:
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Obtain fair and timely rate relief-Our utility’s retail rates are regulated by the BPU and its wholesale transmission rates are regulated by the FERC. The retail rates for electric and gas distribution services are established in a base rate case and remain in effect until a new base rate case is filed and concluded. In addition, our utility has received approval for several clause recovery mechanisms, some of which provide for recovery of and on the authorized investments. These clause mechanisms require periodic updates to be reviewed and approved by the BPU. Our utility's transmission rates are recovered through a FERC approved formula rate. The revenue requirements are reset each year through this formula. Transmission ROEs have recently become the target of certain state utility commissions, municipal utilities, consumer advocates and consumer groups seeking to lower customer rates in New England and New York. These agencies and groups have filed complaints at the FERC asking the FERC to reduce the base ROE of various transmission owners. They point to changes in the capital markets as justification for lowering the ROE of these companies. While we are not the subject of any of these complaints, the matter could set a precedent for FERC-regulated transmission owners, such as PSE&G. Inability to obtain fair or timely recovery of all our costs, including a return of or on our investments in rates, could have a material impact on our business.
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Obtain required regulatory approvals-The majority of our businesses operate under MBR authority granted by the FERC, which has determined that our subsidiaries do not have unmitigated market power and that MBR rules have
been satisfied. Failure to maintain MBR eligibility, or the effects of any severe mitigation measures that may be required if market power was evaluated differently in the future, could have a material adverse effect on us.
We may also require various other regulatory approvals to, among other things, buy or sell assets, engage in transactions between our public utility and our other subsidiaries, and, in some cases, enter into financing arrangements, issue securities and allow our subsidiaries to pay dividends. Failure to obtain these approvals on a timely basis could materially adversely affect our results of operations and cash flows.
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Comply with regulatory requirements-There are Federal standards, including mandatory NERC and cybersecurity standards, in place to ensure the reliability of the U. S. electric transmission and generation system and to prevent major system black-outs. We have been, and will continue to be, periodically audited by the NERC for compliance.
Further, the FERC requires compliance with all of its rules and orders, including rules concerning Standards of Conduct, market behavior and anti-manipulation rules, reporting, interlocking directorate rules and cross-subsidization. Our companies with MBR authority are currently being audited by the FERC for compliance with FERC's rules regarding MBR authority, the filing of Electric Quarterly Reports (EQRs) and the receipt of payments in organized markets by our generating units that are required to run for reliability reasons when it is not economical for them to do so.
We will soon be subject to the reporting and record-keeping requirements of the Dodd-Frank Act, as implemented by the CFTC, and may in the future be subject to CFTC requirements regarding position limits for trading of certain commodities. As part of the Dodd-Frank Act compliance, we will need to be vigilant in monitoring and reporting our swap transactions.
The BPU conducts periodic combined management/competitive service audits of New Jersey utilities related to affiliate standard requirements, competitive services, cross-subsidization, cost allocation and other issues. The BPU is near completion of a management audit and an affiliate transactions audit of PSE&G.
We are exposed to commodity price volatility as a result of our participation in the wholesale energy markets.
The material risks associated with the wholesale energy markets known or currently anticipated that could adversely affect our operations include:
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Price fluctuations and collateral requirements-We expect to meet our supply obligations through a combination of generation and energy purchases. We also enter into derivative and other positions related to our generation assets and supply obligations. As a result, we are subject to the risk of price fluctuations that could affect our future results and impact our liquidity needs. These include:
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variability in costs, such as changes in the expected price of energy and capacity that we sell into the market,
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increases in the price of energy purchased to meet supply obligations or the amount of excess energy sold into the market,
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the cost of fuel to generate electricity, and
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the cost of emission credits and congestion credits that we use to transmit electricity.
In the markets where we operate, natural gas prices typically have a major impact on the price that generators will receive for their output, especially in periods of relatively strong demand. Therefore, significant changes in the price of natural gas will usually translate into significant changes in the wholesale price of electricity.
Over the past few years, wholesale prices for natural gas have declined from the peak levels experienced in 2008. One of the reasons for this decline is increased shale gas production as extraction technology has improved. Lower gas prices have resulted in lower electricity prices, which has reduced our margins as nuclear and coal generation costs have not declined similarly. Over that time, generation by our coal units was also adversely affected by the relatively lower price of natural gas as compared to coal, making it sometimes more economical to run certain of our gas units than our coal units.
Natural gas prices may remain at low levels for an extended period and continue to decline if further advances in technology result in greater volumes of shale gas production.
Many factors may affect capacity pricing in PJM, including but not limited to:
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changes in load and demand,
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changes in the available amounts of demand response resources,
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changes in available generating capacity (including retirements, additions, derates, forced outage rates, etc.),
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increases in transmission capability between zones, and
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changes to the pricing mechanism, including increasing the potential number of zones to create more pricing sensitivity to changes in supply and demand, as well as other potential changes that PJM may propose over time, including issues currently pending at the FERC.
Potential changes to the rules governing energy markets in which the output of our plants is sold also poses risk to our business.
Also, as market prices for energy and fuel fluctuate, our forward energy sale and forward fuel purchase contracts could require us to post substantial additional collateral, thus requiring us to obtain additional sources of liquidity during periods when our ability to do so may be limited. If Power were to lose its investment grade credit rating, it would be required under certain agreements to provide a significant amount of additional collateral in the form of letters of credit or cash, which would have a material adverse effect on our liquidity and cash flows. If Power had lost its investment grade credit rating as of December 31, 2012, it may have had to provide approximately $654 million in additional collateral. We may also be subject to additional collateral requirements which could be required under new rules being developed by the CFTC which are expected to be implemented in 2013.
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Our cost of coal and nuclear fuel may substantially increase-Our coal and nuclear units have a diversified portfolio of contracts and inventory that will provide a substantial portion of our fuel needs over the next several years. However, it will be necessary to enter into additional arrangements to acquire coal and nuclear fuel in the future. Market prices for coal and nuclear fuel have recently been volatile. Although our fuel contract portfolio provides a degree of hedging against these market risks, future increases in our fuel costs cannot be predicted with certainty and could materially and adversely affect liquidity, financial condition and results of operations.
While our generation runs on diverse fuels, allowing for flexibility, the mix of fuels ultimately used can impact earnings.
•
Third party credit risk-We sell generation output and buy fuel through the execution of bilateral contracts. These contracts are subject to credit risk, which relates to the ability of our counterparties to meet their contractual obligations to us. Any failure to perform by these counterparties could have a material adverse impact on our results of operations, cash flows and financial position. In the spot markets, we are exposed to the risks of whatever default mechanisms exist in those markets, some of which attempt to spread the risk across all participants, which may not be an effective way of lessening the severity of the risk and the amounts at stake. The impact of economic conditions may also increase such risk.
We are subject to numerous Federal and state environmental laws and regulations that may significantly limit or affect our businesses, adversely impact our business plans or expose us to significant environmental fines and liabilities.
We are subject to extensive environmental regulation by Federal, state and local authorities regarding air quality, water quality, site remediation, land use, waste disposal, aesthetics, impact on global climate, natural resources damages and other matters. These laws and regulations affect the manner in which we conduct our operations and make capital expenditures. Future changes may result in significant increases in compliance costs.
Delay in obtaining, or failure to obtain and maintain, any environmental permits or approvals, or delay in or failure to satisfy any applicable environmental regulatory requirements, could:
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prevent construction of new facilities,
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prevent continued operation of existing facilities,
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prevent the sale of energy from these facilities, or
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result in significant additional costs, each of which could materially affect our business, results of operations and cash flows.
In obtaining required approvals and maintaining compliance with laws and regulations, we focus on several key environmental issues, including:
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Concerns over global climate change could result in laws and regulations to limit CO2 emissions or other GHG produced by our fossil generation facilities-Federal and state legislation and regulation designed to address global climate change through the reduction of GHG emissions could materially impact our fossil generation facilities. Legislation enacted in the states where our generation facilities are located establishes aggressive goals for the reduction of CO2 emissions over a 40-year period. There could be significant costs incurred to continue operation of our fossil generation facilities, including the potential need to purchase CO2 emission allowances. Such expenditures could materially affect the continued economic viability of one or more such facilities. Multiple states are developing
or have developed state-specific or regional initiatives to obtain CO2 emissions reductions in the electric power industry. The RGGI is such a program in the northeast.
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CO2 Litigation-In addition to legislative and regulatory initiatives, the outcome of certain legal proceedings regarding alleged impacts of global climate change not involving us could be material to the future liability of energy companies.
In June 2012, the United States Court of Appeals for the D.C. Circuit upheld the EPA finding that GHGs could reasonably be expected to endanger public health and welfare. However, the Court dismissed the action brought by individuals, local governments and interest groups alleging that various industries, including various energy companies, emitted GHGs, causing global climate change resulting in a variety of damages. Plaintiffs are expected to appeal to the United States Supreme Court.
In November 2012, the Ninth Circuit Court of Appeals refused to reconsider its decision not to rehear an Alaskan village's public nuisance lawsuit alleging that GHGs emissions from ExxonMobil Corporation and many other energy companies had made the village uninhabitable. The appellate court denied the petition for rehearing which accused these companies of causing GHGs emissions that contributed to global warming and alleged injury to the village. If relevant federal or state common law were to develop that imposed liability upon those that emit GHGs for alleged impacts of GHGs emissions, such potential liability to us could be material.
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Potential closed-cycle cooling requirements-Our Salem nuclear generating facility has a permit from the NJDEP allowing for its continued operation with its existing cooling water system. That permit expired in July 2006. Our application to renew the permit, filed in February 2006, estimated the costs associated with cooling towers for Salem to be approximately $1 billion, of which our share was approximately $575 million. These amounts have not been updated since our 2006 filing.
If the NJDEP and the Connecticut Department of Environmental Protection were to require installation of closed-cycle cooling or its equivalent at our Salem, Mercer, Hudson, Bridgeport, Sewaren or New Haven generating stations, the related increased costs and impacts would be material to our financial position, results of operations and net cash flows and would require further economic review to determine whether to continue operations or decommission the stations.
The EPA issued a proposed rule in 2011 regarding regulation of cooling water intake structures. If adopted as proposed, the impact of this rulemaking could significantly impact states’ permitting decisions on whether to require closed cycle cooling and could materially increase our cost of compliance. For additional information, see Item 8. Financial Statements and Supplementary Data-Note 13. Commitments and Contingent Liabilities.
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Remediation of environmental contamination at current or formerly owned facilities-We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we generated. Remediation activities associated with our former Manufactured Gas Plant (MGP) operations are one source of such costs. Also, we are currently involved in a number of proceedings relating to sites where other hazardous substances may have been discharged and may be subject to additional proceedings in the future, the related costs of which could have a material adverse effect on our financial condition, results of operations and cash flows. Recent amendments to New Jersey law now place affirmative obligations on us to investigate and, if necessary, remediate contaminated property upon which we were in any way responsible for a discharge of hazardous substances. While those amendments do not change our liability, they do impact the speed by which we will need to investigate contaminated properties, which could adversely impact cash flow.
The State of New Jersey has filed multiple lawsuits against parties, including us, who were alleged to be responsible for injuries to natural resources in New Jersey, including a site being remediated under our MGP program. We cannot predict what further actions, if any, or the costs or the timing thereof, that may be required with respect to these or other natural resource damages claims. For additional information, see Item 8. Financial Statements and Supplementary Data-Note 13. Commitments and Contingent Liabilities.
•
More stringent air pollution control requirements in New Jersey-Most of our generating facilities are located in New Jersey where restrictions are generally considered to be more stringent in comparison to other states. Therefore, there may be instances where the facilities located in New Jersey are subject to more restrictive and, therefore, more costly pollution control requirements and liability for damage to natural resources, than competing facilities in other states. Most of New Jersey has been classified as “nonattainment” with NAAQS for one or more air pollutants. This requires New Jersey to develop programs to reduce air emissions. Such programs can impose additional costs on us by requiring that we offset any emissions increases from new electric generators we may want to build and by setting more stringent emission limits on our facilities that run during the hottest days of the year.
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Coal Ash Management-Coal ash is a CCR produced as a byproduct of generation at our coal-fired facilities. We currently have a program to beneficially reuse coal ash as presently allowed by federal and state regulations. In June 2010, the EPA formally published a proposed rule offering three main options for the management of CCRs under the Resource Conservation and Recovery Act. One of these options regulates CCRs as a hazardous waste and the other two options are variations of a non-hazardous designation. All options communicate the EPA’s intent of ceasing wet ash transfer and instituting engineering controls on ash ponds and landfills to limit impact on human health and the environment. The outcome of the EPA rulemaking cannot be predicted. Proposed regulations which more stringently regulate coal ash, including regulating coal ash as hazardous waste, could materially increase costs at our coal-fired generation facilities. The EPA has not established a date for release of a final rule.
Our ownership and operation of nuclear power plants involve regulatory, financial, environmental, health and safety risks.
Approximately half of our total generation output each year is provided by our nuclear fleet, which comprises approximately one-fourth of our total owned generation capacity. For this reason, we are exposed to risks related to the continued successful operation of our nuclear facilities and issues that may adversely affect the nuclear generation industry. These include:
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Storage and Disposal of Spent Nuclear Fuel-We currently use on-site storage for spent nuclear fuel. Disposal of nuclear materials, including the availability or unavailability of a permanent repository for spent nuclear fuel, could impact future operations of these stations. In addition, the availability of an off-site repository for spent nuclear fuel may affect our ability to fully decommission our nuclear units in the future.
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Regulatory and Legal Risk-The NRC may modify, suspend or revoke licenses, or shut down a nuclear facility and impose substantial civil penalties for failure to comply with the Atomic Energy Act, related regulations or the terms and conditions of the licenses for nuclear generating facilities. As with all of our generation facilities, as discussed above, our nuclear facilities are also subject to comprehensive, evolving environmental regulation. Our nuclear generating facilities are currently operating under NRC licenses that expire in 2033 through 2046.
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Operational Risk-Operations at any of our nuclear generating units could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. Since our nuclear fleet provides the majority of our generation output, any significant outage could result in reduced earnings as we would need to purchase or generate higher-priced energy to meet our contractual obligations.
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Nuclear Incident or Accident Risk-Accidents and other unforeseen problems have occurred at nuclear stations, both in the United States and elsewhere. The consequences of an accident can be severe and may include loss of life, significant property damage and/or a change in the regulatory climate. We have nuclear units at two sites. It is possible that an accident or other incident at a nuclear generating unit could adversely affect our ability to continue to operate unaffected units located at the same site, which would further affect our financial condition, operating results and cash flows. An accident or incident at a nuclear unit not owned by us could also affect our ability to continue to operate our units. Any resulting financial impact from a nuclear accident may exceed our resources, including insurance coverages.
We may be adversely affected by changes in energy regulatory policies, including energy and capacity market design rules and developments affecting transmission.
The energy industry continues to be regulated and the rules to which our businesses are subject are always at risk of being changed. Our business has been impacted by established rules that create locational capacity markets in each of PJM, ISO-NE and NYISO. Under these rules, generators located in constrained areas are paid more for their capacity so there is an incentive to locate in those areas where generation capacity is most needed. Because much of our generation is located in constrained areas in PJM and ISO-NE, the existence of these rules has had a positive impact on our revenues. PJM’s locational capacity market design rules and New England forward capacity market rules have been challenged in court and continue to evolve. Any changes to these rules may have an adverse impact on our financial condition, results of operations and cash flows.
In addition, legislative developments in the State of New Jersey have the potential to adversely impact RPM prices. In January 2011, New Jersey enacted a law establishing a LCAPP which provides for the construction of subsidized base load or mid-merit electric power generation. The LCAPP may have the effect of artificially depressing prices in the competitive wholesale market on both a short-term and long-term basis. PJM’s Independent Market Monitor has released a report estimating that the impact of bidding 2,000 MW of capacity in New Jersey as a price taker could be a reduction in capacity market revenues to PJM suppliers of more than $2 billion in the first year.
We could also be impacted by a number of other events, including regulatory or legislative actions favoring non-competitive markets and energy efficiency and demand response initiatives. Further, some of the market-based mechanisms in which we participate, including BGS auctions, are at times the subject of review or discussion by some of the participants in the New Jersey and Federal regulatory and political arenas. We can provide no assurance that these mechanisms will continue to exist in their current form, nor otherwise be modified.
To the extent that additions to the transmission system relieve or reduce congestion in eastern PJM where most of our plants are located, Power's revenues could be adversely affected. Moreover, the FERC has issued a rule, currently being challenged in court, that requires changes to transmission planning processes which may result in more transmission being built to facilitate renewable generation. This rule has also opened up the construction of certain types of transmission to competition through elimination of the ROFR.
Changes in the current policies for building new transmission lines could result in additional competition to build transmission lines in our service territory in the future and would allow us to seek opportunities to build in other service territories.
We face significant competition in the merchant energy markets.
Our wholesale power and marketing businesses are subject to significant competition that may adversely affect our ability to make investments or sales on favorable terms and achieve our annual objectives. Increased competition could contribute to a reduction in prices offered for power and could result in lower earnings. Decreased competition could negatively impact results through a decline in market liquidity. Some of our competitors include:
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merchant generators,
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domestic and multi-national utility rate-based generators,
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energy marketers,
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utilities,
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banks, funds and other financial entities,
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fuel supply companies, and
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affiliates of other industrial companies.
Regulatory, environmental, industry and other operational developments will have a significant impact on our ability to compete in energy markets, potentially resulting in erosion of our market share and impairment in the value of our power plants. Our ability to compete will also be impacted by:
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DSM and other efficiency efforts-DSM and other efficiency efforts aimed at changing the quantity and patterns of consumers’ usage could result in a reduction in load requirements.
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Changes in technology and/or customer conservation-It is possible that advances in technology will reduce the cost of alternative methods of producing electricity, such as fuel cells, micro turbines, windmills and PV (solar) cells, to a level that is competitive with that of most central station electric production. It is also possible that electric customers may significantly decrease their electric consumption due to demand-side energy conservation programs. Changes in technology could also alter the channels through which retail electric customers buy electricity, which could adversely affect our financial results.
Our inability to balance energy obligations with available supply could negatively impact results.
The revenues generated by the operation of our generating stations are subject to market risks that are beyond our control. Generation output will either be used to satisfy wholesale contract requirements, other bilateral contracts or be sold into competitive power markets. Participants in the competitive power markets are not guaranteed any specified rate of return on their capital investments. Generation revenues and results of operations are dependent upon prevailing market prices for energy, capacity, ancillary services and fuel supply in the markets served.
Our generation business frequently involves the establishment of forward sale positions in the wholesale energy markets on long-term and short-term bases. To the extent that we have produced or purchased energy in excess of our contracted obligations, a reduction in market prices could reduce profitability. Conversely, to the extent that we have contracted obligations in excess of energy we have produced or purchased, an increase in market prices could reduce profitability. If the strategy we utilize to hedge our exposure to these various risks is not effective, we could incur significant losses. Our market positions can also be adversely affected by the level of volatility in the energy markets that, in turn, depends on various factors,
including weather in various geographical areas, short-term supply and demand imbalances, customer migration and pricing differentials at various geographic locations. These cannot be predicted with certainty.
Increases in market prices also affect our ability to hedge generation output and fuel requirements as the obligation to post margin increases with increasing prices and could require the maintenance of liquidity resources that would be prohibitively expensive.
Any inability to recover the carrying amount of our assets could result in future impairment charges which could have a material adverse impact on our financial condition, results of operations and cash flows.
In accordance with accounting guidance, management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate or market conditions, could potentially indicate an asset’s or group of assets’ carrying amount may not be recoverable. Significant reductions in our expected revenues or cash flows for an extended period of time resulting from such events could result in future asset impairment charges, which could have a material adverse impact on our financial condition and results of operations.
Inability to access sufficient capital at reasonable rates or commercially reasonable terms or maintain sufficient liquidity in the amounts and at the times needed could adversely impact our business.
Capital for projects and investments has been provided primarily by internally-generated cash flow and external financings. We have significant capital requirements and will need continued access to debt capital from outside sources in order to efficiently fund the construction and other cash flow needs of our businesses. The ability to arrange financing and the costs of capital depend on numerous factors including, among other things, general economic and market conditions, the availability of credit from banks and other financial institutions, investor confidence, the success of current projects and the quality of new projects.
The ability to have continued access to the credit and capital markets at a reasonable economic cost is dependent upon our current and future capital structure, financial performance, our credit ratings and the availability of capital under reasonable terms and conditions. As a result, no assurance can be given that we will be successful in obtaining re-financing for maturing debt, financing for projects and investments or funding the equity commitments required for such projects and investments in the future.
Financial market performance directly affects the asset values of our nuclear decommissioning trust funds and defined benefit plan trust funds. Sustained decreases in asset value of trust assets could result in the need for significant additional funding.
The performance of the financial markets will affect the value of the assets that are held in trust to satisfy our future obligations under our pension and postretirement benefit plans and to decommission our nuclear generating plants. A decline in the market value of our pension assets similar to the one experienced in 2008 could result in the need for us to make significant contributions in the future to maintain our funding at sufficient levels.
An extended economic recession would likely have a material adverse effect on our businesses.
Our results of operations may be negatively affected by sustained downturns or sluggishness in the economy, including low levels in the market prices of commodities. Adverse conditions in the economy affect the markets in which we operate and can negatively impact our results. Declines in demand for energy will reduce overall sales and lessen cash flows, especially as customers reduce their consumption of electricity and gas. Although our utility business is subject to regulated allowable rates of return, overall declines in electricity and gas sold and/or increases in non-payment of customer bills would materially adversely affect our liquidity, financial condition and results of operations.
We may be adversely affected by equipment failures, accidents, severe weather events or other incidents that impact our ability to provide safe and reliable service to our customers and remain competitive.
The success of our businesses is dependent on our ability to continue providing safe and reliable service to our customers while minimizing service disruptions. We are also exposed to the risk of accidents, severe weather events such as we experienced from Hurricane Irene and Superstorm Sandy, or other incidents which could result in damage to or destruction of our facilities or damage to persons or property. The physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns and other related phenomena have exacerbated these risks. Such issues experienced at our facilities, or by others in our industry, could adversely impact our revenues, increase costs to repair and maintain our systems, subject us to potential litigation and/or damage claims and increase the level of oversight of our utility and generation operations and infrastructure through investigations or through the imposition of additional regulatory or legislative requirements. Such actions could affect our costs, competitiveness and future investments, which could be material to our financial position, results of operations and cash flow.
Acts of war, terrorism or cybersecurity breaches could adversely affect our operations.
Our businesses and industry may be impacted by acts and threats of war or terrorism. These actions could result in increased political, economic and financial market instability and volatility in fuel prices which could materially adversely affect our operations. In addition, our infrastructure facilities, such as our generating stations, transmission and distribution facilities and information management systems for customer-related operations, could be direct or indirect targets or be affected by terrorist or other criminal activity.
Our businesses could also be impacted by cybersecurity breaches. Cybersecurity threats include:
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operational interference, such as attacks on our generation facilities, transmission lines or the power grid,
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information theft as to employees, shareholders, vendors and/or customers, such as personal financial and health records, and
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business system interruption or compromise.
Such events could severely disrupt business operations and prevent us from servicing our customers or collecting revenues. These events could also result in significant expenses to repair security breaches or system damage as well as increased capital, insurance and operating costs, including increased security costs for our facilities. A breach of certain business systems could affect our ability to record, process and/or report financial information correctly. In addition, new or updated security regulations may require us to make changes to our current measures which could also result in additional expenses.
Inability to successfully develop or construct generation, transmission and distribution projects within budget could adversely impact our businesses.
Our business plan calls for extensive investment in capital improvements and additions, including the installation of required environmental upgrades and retrofits, construction and/or acquisition of additional generation units and transmission facilities and modernizing existing infrastructure. Currently, we have several significant projects underway or being contemplated.
Our success will depend, in part, on our ability to complete these projects within budgets, on commercially reasonable terms and conditions and, in our regulated businesses, our ability to recover the related costs through rates. Any delays, cost escalations or otherwise unsuccessful construction and development could materially affect our financial position, results of operations and cash flows.
We may be unable to achieve, or continue to sustain, our expected levels of operating performance.
One of the key elements to achieving the results in our business plan is the ability to sustain generating operating performance and capacity factors at expected levels since our forward sales of energy and capacity assume acceptable levels of operating performance. This is especially important at our lower-cost facilities. Operations at any of our plants could degrade to the point where the plant has to shut down or operate at less than full capacity. Some issues that could impact the operation of our facilities are:
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breakdown or failure of equipment, processes or management effectiveness,
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disruptions in the transmission of electricity,
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labor disputes,
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fuel supply interruptions,
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transportation constraints,
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limitations which may be imposed by environmental or other regulatory requirements,
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permit limitations, and
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operator error or catastrophic events such as fires, earthquakes, explosions, floods, severe storms, acts of terrorism or other similar occurrences.
Identifying and correcting any of these issues may require significant time and expense. Depending on the materiality of the issue, we may choose to close a plant rather than incur the expense of restarting it or returning it to full capacity. In either event, to the extent that our operational targets are not met, we could have to operate higher-cost generation facilities or meet our obligations through higher-cost open market purchases.
Challenges associated with retention of a qualified workforce could adversely impact our businesses.
Our operations depend on the retention of a skilled workforce. The loss or retirement of key executives or other employees, including those with the specialized knowledge required to support our generation, transmission and distribution operations, could result in various operational challenges. These challenges may include the lack of appropriate replacements, the loss of institutional and industry knowledge and the increased costs to hire and train new personnel. This has the potential to become more critical over the next several years as a growing number of employees become eligible to retire.
In addition, because a significant portion of our employees are covered under collective bargaining agreements, our success will depend on our ability to successfully renegotiate these agreements as they expire. Inability to do so may result in employee strikes or work stoppages which would disrupt our operations and could also result in increased costs.
Our receipt of payment of receivables related to our domestic leveraged leases is dependent upon the credit quality and the ability of lessees to meet their obligations.
Our receipt of payments of equity rent, debt service and other fees related to our leveraged lease portfolio in accordance with the lease contracts can be impacted by various factors. The factors which may impact future lease cash flow include, but are not limited to, new environmental legislation regarding air quality and other discharges in the process of generating electricity, market prices for fuel and electricity, including the impact of low gas prices on our coal generation investments, overall financial condition of lease counterparties and the quality and condition of assets under lease. If a lessee were to default, we could potentially be required to impair our current investment balances. For additional information relating to these leases, see Item 7. MD&A-Critical Accounting Estimates and Item 8. Financial Statements and Supplementary Data-Note 8. Financing Receivables.
ITEM 1B.
ITEM 1B. UNRESOLVED STAFF COMMENTS
PSEG, Power and PSE&G
None.
ITEM 2.
ITEM 2. PROPERTIES
Our subsidiaries own all of our physical property. We believe that we and our subsidiaries maintain adequate insurance coverage against loss or damage to plants and properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost. For a discussion of nuclear insurance, see Item 8. Financial Statements and Supplementary Data-Note 13. Commitments and Contingent Liabilities.
Generation Facilities
Power
As of December 31, 2012, Power’s share of summer installed generating capacity is shown in the following table:
(A)
Operated by GenOn Northeast Management Company
(B)
Operated by Exelon Generation
(C)
Operated by Jersey Central Power & Light Company
PSE&G
As of December 31, 2012, PSE&G had 73 MW of installed solar capacity throughout New Jersey.
Energy Holdings
Energy Holdings had investments in the following generation facilities as of December 31, 2012:
Transmission and Distribution Facilities
As of December 31, 2012, PSE&G’s electric transmission and distribution system included 23,856 circuit miles, of which 8,357 circuit miles were underground, and 838,236 poles, of which 546,614 poles were jointly-owned. Approximately 99% of this property is located in New Jersey.
In addition, as of December 31, 2012, PSE&G owned four electric distribution headquarters and five subheadquarters in four operating divisions, all located in New Jersey.
As of December 31, 2012, the daily gas capacity of PSE&G’s 100%-owned peaking facilities (the maximum daily gas delivery available during the three peak winter months) consisted of liquid petroleum air gas (LPG) and liquefied natural gas (LNG) and aggregated 2,790,500 therms (270,932,330 cubic feet on an equivalent basis of 100,000 Btu/therm and 1,030 Btu/cubic foot) as shown in the following table:
As of December 31, 2012, PSE&G owned and operated 17,713 miles of gas mains, owned 12 gas distribution headquarters and two subheadquarters, all in four operating regions located in New Jersey and owned one meter shop in New Jersey serving all such areas. In addition, PSE&G operated 62 natural gas metering and regulating stations, all located in New Jersey, of which 26 were located on land owned by customers or natural gas pipeline suppliers and were operated under lease, easement or other similar arrangement. In some instances, the pipeline companies owned portions of the metering and regulating facilities.
PSE&G’s First and Refunding Mortgage, securing the bonds issued thereunder, constitutes a direct first mortgage lien on substantially all of PSE&G’s property.
PSE&G’s electric lines and gas mains are located over or under public highways, streets, alleys or lands, except where they are located over or under property owned by PSE&G or occupied by it under easements or other rights. PSE&G deems these easements and other rights to be adequate for the purposes for which they are being used.
In addition, as of December 31, 2012, PSE&G owned 42 switching stations in New Jersey with an aggregate installed capacity of 25,103 megavolt-amperes (MVA) and 246 substations with an aggregate installed capacity of 8,179 MVA. In addition, four of our substations in New Jersey having an aggregate installed capacity of 109 MVA were operated on leased property.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
We are party to various lawsuits and regulatory matters, including in the ordinary course of business. For information regarding material legal proceedings, other than those discussed below, see Item 1. Business-Regulatory Issues and Environmental Matters and Item 8. Financial Statements and Supplementary Data-Note 13. Commitments and Contingent Liabilities.
Con Edison (Con Ed)
In 2001, Con Ed filed a complaint with the FERC against PSE&G, PJM and NYISO asserting a failure to comply with agreements between PSE&G and Con Ed covering 1,000 MW of transmission. On September 16, 2010, the FERC approved a settlement agreement entered into by PSE&G, Con Ed, PJM, NYISO and others. This settlement provides the basis for moving forward with Con Ed after the current contracts expire in 2012 and settles all issues associated with the existing contracts, including cases pending in the D.C. Circuit Court of Appeals. However, dismissal of these court cases is contingent upon receipt of a final, non-appealable order from the FERC. One party to the proceeding sought rehearing of the FERC approval order, which the FERC denied in an order issued on April 8, 2011. The party then appealed this decision to the D.C. Circuit Court of Appeals. This appeal is pending.
Electric Discount and Energy Competition Act (Competition Act)
In 2007, PSE&G and Transition Funding were served with a purported class action complaint (Complaint) in New Jersey Superior Court challenging the constitutional validity of certain stranded cost recovery provisions of the Competition Act, seeking injunctive relief against continued collection from PSE&G’s electric customers of the Transition Bond Charge (TBC) of Transition Funding, as well as recovery of TBC amounts previously collected. The Superior Court subsequently granted PSE&G’s motion to dismiss the Complaint, which dismissal was upheld by the Appellate Division.
In July 2007, the same plaintiff also filed a petition with the BPU requesting review and adjustment to PSE&G’s recovery of the same stranded cost charges. In June 2010, the BPU granted PSE&G’s motion to dismiss, and the plaintiff/petitioner subsequently appealed this dismissal to the Appellate Division. In June 2012, the Appellate Division affirmed the BPU’s decision, concluding that the BPU had correctly found that the plaintiff’s claims failed as a matter of law. The petitioner subsequently filed a Notice of Petition for Certification with the New Jersey Supreme Court. By order dated November 16, 2012, the New Jersey Supreme Court denied this Notice. On February 11, 2013, the Court denied the plaintiff's subsequent motion for reconsideration.
Environmental Matters
The following items are environmental matters involving governmental authorities not discussed elsewhere in this Form 10-K. We do not expect expenditures for any such site relating to the items listed below, individually or for all such current sites in the aggregate, to have a material effect on our financial condition, results of operations and net cash flows.
(1)
Claim made in 1985 by the U.S. Department of the Interior under CERCLA with respect to the Pennsylvania Avenue and Fountain Avenue municipal landfills in Brooklyn, New York, for damages to natural resources. The United States Government alleges damages of approximately $200 million. To PSE&G’s knowledge there has been no action on this matter since 1988.
(2)
Various Spill Act directives were issued by the NJDEP to PRPs, including PSE&G with respect to the PJP Landfill in Jersey City, Hudson County, New Jersey, ordering payment of costs associated with operation and maintenance, interim remedial measures and a Remedial Investigation and Feasibility Study (RI/FS) in excess of $25 million. The directives also sought reimbursement of the NJDEP’s past and future oversight costs and the costs of any future remedial action.
(3)
Claim by the EPA, Region III, under CERCLA with respect to a Cottman Avenue Superfund Site, a former non-ferrous scrap reclamation facility located in Philadelphia, Pennsylvania, owned and formerly operated by Metal Bank of America, Inc. PSE&G, other utilities and other companies are alleged to be liable for contamination at the site and PSE&G has been named as a PRP. A Final Remedial Design Report was submitted to the EPA in September of 2002. This document presented the design details of the EPA’s selected remediation remedy. PSE&G and other utility companies as members of a PRP group entered into a Consent Decree and agreed to implement a negotiated EPA selected remediation remedy. The PRP group implementation of the remedy was completed in 2010. Although subject to EPA approval and oversight, long term monitoring activities designed to demonstrate the effectiveness of the implemented remedy are planned through 2018 at an estimated cost of $2.8 million.
(4)
The Klockner Road site is located in Hamilton Township, Mercer County, New Jersey, and occupies approximately two acres on PSE&G’s Trenton Switching Station property. In 1996, PSE&G entered into a memorandum of
agreement with the NJDEP for the Klockner Road site pursuant to which PSE&G conducted an RI/FS and remedial action at the site to address the presence of soil and groundwater contamination. Anticipated future activities at the site include the filing of certification(s) with the NJDEP once every two years regarding the effectiveness of engineering and institutional controls, quarterly groundwater monitoring for several years and the installation of additional off-site groundwater monitoring wells as directed by the NJDEP.
(5)
In 1996, Morton International, Inc., a subsidiary of The Dow Chemical Company, filed a lawsuit against the former customers of a former mercury refining operation located on the banks of Berry’s Creek in Wood-Ridge, New Jersey. The lawsuit seeks to recover cleanup costs incurred and to be incurred in remediating the site. PSE&G was among the former customers sued based on allegations that mercury originating at its Kearny Generating Station was sent to the site for refining.
(6)
The EPA sent Power, PSE&G and approximately 157 other entities a notice that the EPA considered each of the entities to be a PRP with respect to contamination in Berry’s Creek in Bergen County, New Jersey and requesting that the PRPs perform a RI/FS on Berry’s Creek and the connected tributaries and wetlands. Berry’s Creek flows through approximately 6.5 miles of areas that have been used for a variety of industrial purposes and landfills. The EPA estimates that the study could be completed in approximately five years at a total cost of approximately $18 million. As members of a PRP Group, Power and certain of the other entities named in the EPA Notice entered into an Administrative Settlement Agreement and Order on Consent to conduct the RI/FS.
(7)
In January 2010, we received a letter from the NJDEP asserting that we are the current owner of the Gates Construction Corporation Landfill and that the subject landfill has not been properly closed in accordance with NJDEP Solid Waste Regulations.
ITEM 4.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our common stock is listed on the New York Stock Exchange, Inc. As of December 31, 2012, there were 78,842 registered holders.
The graph below shows a comparison of the five-year cumulative return assuming $100 invested on December 31, 2007 in our common stock and the subsequent reinvestment of quarterly dividends, the S&P Composite Stock Price Index, the Dow Jones Utilities Index and the S&P Electric Utilities Index.
The following table indicates the high and low sale prices for our common stock and dividends paid for the periods indicated:
On February 19, 2013, our Board of Directors approved $0.36 per share of common stock dividend for the first quarter of 2013. This reflects an indicated annual dividend rate of $1.44 per share.
The following table indicates our common share repurchases in the open market to satisfy obligations under various equity compensation award grants during the fourth quarter of 2012:
The following table indicates the securities authorized for issuance under equity compensation plans as of December 31, 2012:
(A)
Shares issuable under our Long-Term Incentive Plan.
(B)
Shares issuable under our Employee Stock Purchase Plan.
For additional discussion of specific plans concerning equity-based compensation, see Item 8. Financial Statements and Supplementary Data-Note 18. Stock Based Compensation.
Power
We own all of Power’s outstanding limited liability company membership interests. For additional information regarding Power’s ability to pay dividends, see Item 7. MD&A-Overview of 2012 and Future Outlook.
PSE&G
We own all of the common stock of PSE&G. For additional information regarding PSE&G’s ability to continue to pay dividends, see Item 7. MD&A-Overview of 2012 and Future Outlook.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
PSEG
The information presented below should be read in conjunction with the MD&A and the Consolidated Financial Statements and Notes to Consolidated Financial Statements (Notes).
`
(A)
Income from Continuing Operations for 2011 and 2008 includes after-tax charges of $170 million and $490 million, respectively, related to certain leveraged leases.
(B)
Includes capital lease obligations.
Power and PSE&G
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
ITEM 7.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (MD&A)
This combined MD&A is separately filed by Public Service Enterprise Group Incorporated (PSEG), PSEG Power LLC (Power) and Public Service Electric and Gas Company (PSE&G). Information contained herein relating to any individual company is filed by such company on its own behalf. Power and PSE&G each make representations only as to itself and make no representations whatsoever as to any other company.
PSEG's business consists of three reportable segments, which are:
•
Power, our wholesale energy supply company that integrates its generating asset operations with its wholesale energy, fuel supply, energy trading and marketing and risk management activities primarily in the Northeast and Mid-Atlantic United States,
•
PSE&G, our public utility company which provides transmission and distribution of electric energy and gas in New Jersey; implements demand response and energy efficiency programs and invests in solar generation, and
•
Energy Holdings, which principally owns and manages a portfolio of lease investments and solar generation projects.
Our business discussion in Part I, Item 1. Business provides a review of the regions and markets where we operate and compete, as well as our strategy for conducting our businesses within these markets, focusing on operational excellence, financial strength and making disciplined investments. Our risk factor discussion in Part I Item 1A provides information about factors that could have a material adverse impact on our businesses. The following discussion provides an overview of the significant events and business developments that have occurred during 2012 and key factors that we expect will drive our future performance. This discussion refers to the Consolidated Financial Statements (Statements) and the Related Notes to Consolidated Financial Statements (Notes). This discussion should be read in conjunction with such Statements and Notes.
OVERVIEW OF 2012 AND FUTURE OUTLOOK
2012 Overview
During 2012, our financial results continued to be adversely impacted by lower prices for electricity and natural gas in the markets we serve. Electricity prices remained low due to a combination of a slow recovery in demand growth and sustained low natural gas prices. The slow economic recovery negatively impacts utility sales, and the wholesale energy and capacity markets in which we operate. The continued decline in wholesale natural gas prices resulting from greater supply from shale production has further contributed to the steady decline in the wholesale price of electricity.
In the face of reduced pricing and lower demand for electricity, we continued to pursue our three-pronged strategy of operational excellence, financial strength and disciplined investment. Our focus has been to change the business mix of our operations with increased investments in our regulated utility. Through our regulated utility operations, we secured higher and more stable transmission revenues in 2012 resulting from our annual transmission formula rate update filing with the Federal Energy Regulatory Commission (FERC) and made additional solar and energy efficiency investments in New Jersey, on which we receive contemporaneous returns. Through allocating capital to transmission and distribution infrastructure projects, we were able to take advantage of a low interest rate environment and tap into an available labor pool in the region, while enhancing the reliability of our service to our customers. Additionally, these sources of revenue allowed us to partially offset the impact of lower prices for electricity and natural gas, while the reduction in supply costs allows us to continue to invest in infrastructure improvements without raising our utility customers' rates.
While we have been successfully increasing our regulated utility earnings, we have not fully compensated for the reduction in generation earnings. Over the past few years, we experienced a decline in wholesale energy prices. Basic Generation Service (BGS) rates also declined, resulting in lower revenues for our generation business. As BGS rates reached a level closer to current spot market prices, customer migration away from BGS supply contracts continued in 2012, but at a slower pace as there was less incentive to switch to third party suppliers.
In addition, at year-end we were severely impacted by Superstorm Sandy, which resulted in the highest level of customer outages in our history. We sustained significant damage to some of our generation, transmission and distribution facilities. We received an order from the New Jersey Board of Public Utilities (BPU) allowing us to defer incurred, uninsured, incremental storm restoration costs associated with our gas and electric distribution systems.
As of December 31, 2012, Power had incurred approximately $85 million in costs related to Superstorm Sandy, primarily comprised of repairs at certain generating stations and damage to materials and supplies, both at our fossil fleet. All the costs were recognized in Operation and Maintenance Expense, offset by $19 million of a pending future recovery of insurance proceeds. Power estimates that it will incur additional future costs primarily relating to repairs to, and replacement of, equipment and property up to approximately $215 million.
As of December 31, 2012, PSE&G had incurred approximately $295 million of costs to restore service to PSE&G's distribution and transmission systems and $5 million to repair its infrastructure and return it to pre-storm conditions. Of the costs incurred, approximately $40 million was recognized in Operation and Maintenance Expense, $75 million was recorded as Property, Plant and Equipment and $180 million was recorded as a Regulatory Asset because such costs were deferred as approved by the BPU under an Order received in December 2012. PSE&G recognized $6 million of insurance proceeds.
We are working with our insurance carriers with regard to other losses and expenses due to the storm but no assurances can be given relative to the timing or amount of insurance recovery. For additional information on the impacts of Superstorm Sandy, see Item 8. Financial Statements and Supplementary Data-Note 13. Commitments and Contingent Liabilities.
There have also been significant regulatory and legislative developments during the year which may affect our operations and financial results in the future as new rules and regulations are developed. Competitive wholesale power market design is of particular importance to our results. Through litigation and the regulatory processes, we advocated for policies and rules in response to subsidized generation and procurement activities in New Jersey in connection with the Long-Term Capacity Agreement Pilot Program (LCAPP), and in Maryland through the Maryland Public Service Commission's Request for Proposal. After a favorable stakeholder vote, PJM filed proposed modifications to the Minimum Offer Price Rule (MOPR) with the FERC. In February 2013, the FERC issued a deficiency letter to PJM seeking additional information regarding the proposed MOPR changes. If the FERC approves the proposal, these modifications should significantly improve the MOPR rules and appropriately reduce the ability for subsidized generation assets to artificially suppress wholesale market prices. Litigation with respect to the New Jersey LCAPP and Maryland's efforts to subsidize new generation and challenges to the BPU's implementation of LCAPP continues. See Item 1. Business, Federal Regulation, FERC - Capacity Market Issues for further information.
We continued to monitor and advocate for the development and implementation of fair and reasonable rules by the U.S. Environmental Protection Agency (EPA). The EPA is proceeding to implement its regulatory initiatives but the outcome of judicial review remains uncertain. The EPA's 316(b) rule on cooling water intake could adversely impact future nuclear and fossil operations and costs. However, we believe our generation business remains well-positioned for Clean Air Act regulations, if and when they are implemented. For additional information on the potential impacts of the 316(b) rule, see Item 8. Financial Statements and Supplementary Data-Note 13. Commitments and Contingent Liabilities.
Another regulatory development in 2012 that could have a material impact on our business are FERC rules under Order 1000, which altered the right of first refusal previously held by incumbent utilities to build all transmission within their respective service territories. We are opposing these rules in litigation and have worked with PJM to develop implementing rules that mitigate the impact of Order 1000. We cannot predict the final outcome or impact on us; however, specific implementation of Order 1000 within our service territory may expose us to competition for certain types of transmission projects, while at the same time affording us opportunities to construct transmission outside of our service territory. See Item 1. Business, Federal Regulation, FERC -Transmission Regulation.
We are making progress in addressing these challenges, but regulatory uncertainty remains a concern.
In 2012, our continued focus on operational excellence provided the foundation for our financial strength, in turn enabling us to invest in a disciplined way for growth, providing value for our customers, employees and shareholders and allowing us to best succeed in a sustained low electricity price environment. Some specific highlights in the areas of operational excellence, financial strength and disciplined investment in 2012 are discussed in more detail below.
Operational Excellence
We seek to emphasize operational performance while developing opportunities in our competitive and regulated businesses. Low commodity prices continue to stress margins, but the flexibility of our generating fleet has allowed us to take advantage of market opportunities as we remain diligent in managing costs. In 2012, we
•
constructed approximately $656M million of gross plant additions to our transmission assets currently in service,
•
continued to achieve high nuclear capacity factors, which averaged 91.1% for our nuclear fleet in 2012,
•
improved fossil plant summer output,
•
realized high combined cycle gas turbine fleet capacity utilization factors,
•
optimized fleet-switching from coal to gas to improve dispatch economics,
•
extended collective bargaining agreements with four of our labor unions for four years,
•
implemented more efficient plant staffing,
•
were awarded the 2011 National Reliability Excellence Award for “demonstrating sustained leadership, innovation and achievement in the area of electric reliability," representing the fifth time in eight years we received this recognition, and eleven straight years that we garnered the ReliabilityOne Award for the Mid-Atlantic region, and
•
received other award recognition for reliability and outage response.
Financial Strength
Our financial metrics remained strong in 2012. We maintained
•
a strong balance sheet and operating cash flow,
•
substantial liquidity resources, including total credit capacity of $4.3 billion and $379 million of cash on hand as of December 31, 2012, with a portion of available credit facilities extending until 2017,
•
stable credit ratings,
•
dividend payments of $1.42 per share for 2012, representing a change in our dividend policy moving from a strict earnings payout based approach to one that takes into consideration the growing contribution to earnings and cash from our regulated operations and continued cash flow from our generation business, and
•
a well-funded position for our pension obligation, having made a $224 million contribution to our pension plan in 2012.
We also funded our capital program with internally generated cash and external debt financing.
In addition, we entered into a closing agreement settling our dispute with the Internal Revenue Service (IRS) over certain international leveraged lease transactions with finality for all tax periods in which we realized tax deductions from these transactions. Also, we executed settlement agreements covering all audit issues for tax years 1997 through 2006, concluding ten years of open audits for us. For additional information on the IRS audit settlements, see Item 8. Financial Statements and Supplementary Data-Note 20. Income Taxes.
Disciplined Investment
We seek to invest in areas that complement our existing businesses and provide attractive risk-adjusted returns. These areas include upgrading our energy infrastructure, responding to trends in environmental protection and providing new energy supplies in domestic markets with growing demand. We also have several projects where we are investing to continue to improve our operational performance. As noted above, over the past few years, we have shifted our focus to investing at the utility. Our capital expenditure forecast includes approximately $6.1 billion in spending over the next three years, 80% of which is at PSE&G. In addition, in 2012 we:
•
invested approximately $1.1 billion in transmission infrastructure projects,
•
completed the Peach Bottom steam path retrofit,
•
added 400 MW of additional capacity with new peaking plants in New Jersey and Connecticut,
•
completed solar projects in Arizona and Delaware, with the expectation to complete an additional Arizona solar project in 2013,
•
made additional investments in our Capital Infrastructure Program (CIP II) and our Energy Efficiency and Demand Response Programs, and
•
obtained BPU and NJDEP approvals of the North Central Reliability transmission project.
On February 20, 2013, we filed a petition with the BPU describing $3.9 billion of improvements we recommend making to our electric and gas distribution systems over a ten year period to harden and improve resiliency for the future. In addition, we anticipate investing an additional $1.5 billion in improvements to our transmission system for the same reason. See Capital Requirements for additional information.
There is no guarantee that our projects currently underway or any future initiatives will be achieved since many issues need to be favorably resolved, such as regulatory approvals. Delays in the construction schedules of our projects could impact their costs as well as the timing of expected revenues.
Future Outlook
Our future success will depend on our ability to continue to maintain strong operational and financial performance in a difficult economy and cost-constrained environment and to respond to the issues and challenges described below and take advantage of these and other regulatory and legislative initiatives. In order to do this, we must continue to:
•
focus on controlling costs while maintaining our safety, reliability and compliance standards,
•
successfully re-contract our open supply positions,
•
execute our capital investment program, including investments for growth that yield contemporaneous and attractive risk-adjusted returns while enhancing the reliability of the service we provide to our customers,
•
advocate for measures to ensure the implementation by PJM and FERC of market design rules that continue to protect competition and achieve appropriate RPM and BGS pricing, and
•
reach out to and engage multiple stakeholders, including regulators, government officials, customers and investors.
For 2013 and beyond, the key issues and challenges we expect our business to confront include
•
the continuing potential for sustained lower natural gas and electricity prices, both at market hubs and at locations where we operate,
•
challenges to competitive markets, including support for subsidized generation in many states, particularly in New Jersey,
•
customer migration away from our BGS supply contracts,
•
uncertainty in the national and regional economic recovery and continuing customer conservation efforts, which impact customer demand,
•
regulatory and political uncertainty, particularly with regard to future energy policy, design of energy and capacity markets, transmission policy and environmental regulation,
•
the aftermath of Hurricane Irene and Superstorm Sandy, including addressing the BPU's review of performance and communications, as well as cost recovery and opportunities for investment in system strengthening and improvements,
•
compressed margins and reduced utilization at coal plants,
•
uncertain pension expenses and funding requirements given market volatility,
•
liquidating the remaining portfolio of non-core assets where possible, while managing risk,
•
monitoring financially stressed power plant leveraged lease investments, and
•
successfully managing the transition to our operation of Long Island Power Authority's (LIPA) transmission and distribution system.
RESULTS OF OPERATIONS
(A)
Power's and PSE&G's results in 2012 include after-tax expenses of $39 million and $24 million, respectively, for Operation and Maintenance (O&M) costs due to severe damage caused by Superstorm Sandy. See Item 8. Financial Statements and Supplementary Data-Note 13. Commitments and Contingencies.
(B)
PSE&G’s results in 2010 include an after-tax charge of $72 million related to an agreement to refund previous Market Transition Charge (MTC) collections in the succeeding two years.
(C)
Energy Holdings’ results include an after-tax charge of $170 million taken in 2011 related to the reserve for assets underlying a leveraged lease receivable. See Item 8. Financial Statements and Supplementary Data-Note 8. Financing Receivables.
(D)
Other includes parent company interest and financing costs, donations, certain administrative and general expenses.
(E)
See Item 8. Financial Statements and Supplementary Data-Note 4. Discontinued Operations and Dispositions.
The 2012 year-over-year decrease in our Income from Continuing Operations was driven by the following:
•
lower average pricing and volumes for electricity sold under our BGS contracts,
•
lower average prices realized on generation sold into various power pools,
•
unfavorable amounts related to the MTM activity, discussed below,
•
higher Operation and Maintenance costs due to severe damage caused by Superstorm Sandy to our transmission and distribution system throughout our service territory as well as to some of our generation infrastructure in the northern part of New Jersey.
The decreases were partially offset by:
•
the absence of the $170 million after-tax charge taken in 2011 on leveraged leases related to Dynegy and the settlement proceeds received in 2012 (see Item 8. Financial Statements and Supplementary Data-Note 8. Financing Receivables), and
•
higher transmission revenues at PSE&G.
The 2011 year-over-year decrease in our Income from Continuing Operations was driven by the following:
•
the $170 million after-tax charge on leveraged leases related to Dynegy,
•
the absence of an after-tax charge of $72 million related to an agreement to refund previous MTC collections in the succeeding two years,
•
lower average pricing and volumes for electricity sold under our BGS contracts,
•
lower realized prices and/or lower sales volumes in the various power pools,
•
higher interest costs and depreciation expense related to the completion of installation of back-end technology at two of our fossil plants, and
•
the absence of realized gains recognized in 2010 due to restructuring of the investments in our Rabbi Trust.
The decreases were partially offset by:
•
favorable amounts related to the MTM activity reported below,
•
an increase in revenues from new wholesale contracts entered into in the first half of 2011, and
•
lower Operation and Maintenance costs primarily due to lower pension and OPEB costs.
Our results include the realized gains, losses and earnings on Power’s Nuclear Decommissioning Trust (NDT) Fund and other related NDT activity. Net realized gains, interest and dividend income and other costs related to the NDT Fund are recorded in Other Income and Deductions, and impairments on certain NDT securities are recorded as Other-Than-Temporary Impairments. Interest accretion expense on Power's nuclear Asset Retirement Obligation (ARO) is recorded in Operation and Maintenance Expense, as well as the depreciation related to the ARO asset. In September 2012, we restructured a portion of our NDT Fund and realized gains of $59 million. The investments were transitioned to new investment managers.
Our results also include the after-tax impacts of non-trading mark-to-market (MTM) activity, which consist of the financial impact from positions with forward delivery dates.
The combined after-tax impact on Income from Continuing Operations for the years ended December 31, 2012, 2011 and 2010 include the changes related to NDT Fund and MTM activity shown in the chart below:
PSEG
Our results of operations are primarily comprised of the results of operations of our operating subsidiaries, Power, PSE&G and Energy Holdings, excluding charges related to intercompany transactions, which are eliminated in consolidation. We also include certain financing costs, charitable contributions and general and administrative costs at the parent company. For additional information on intercompany transactions, see Item 8. Financial Statements and Supplementary Data-Note 23. Related-Party Transactions.
For a detailed explanation of the variances, see the discussions for Power, PSE&G and Energy Holdings below.
Power
The 2012 year-over-year decrease in Income from Continuing Operations was driven by the following:
•
lower average prices realized on generation sold into the PJM and New York (NY) power pools and MTM losses due from the realization of prior year unrealized gains and adverse changes in unrealized prices in 2012 for forward positions,
•
lower average pricing and lower volumes of electricity sold under our BGS contracts, net of lower cost to serve,
•
lower volumes on wholesale load contracts in PJM, lower operating reserve, ancillary and Reliability Must Run (RMR) revenues primarily in PJM and New England,
•
lower average pricing and volumes of gas sold under our BGSS contracts, net of lower cost to serve, and
•
higher Operation and Maintenance Expense due to damage to our generation infrastructure, primarily our fossil fleet, from Superstorm Sandy and higher refueling and maintenance costs at our nuclear plants.
These decreases were partially offset by
•
lower planned outages and maintenance costs in 2012 at certain of our fossil plants, and
•
lower interest expense due to the maturity of Senior Notes in April 2011 and the early redemption of Senior Notes in December 2011.
For the year ended December 31, 2011, the primary reasons for the decrease in Income from Continuing Operations were
•
lower average pricing and lower volumes of electricity sold under our BGS contracts, as a result of customer migration,
•
higher Operation and Maintenance expense related to planned outage work at certain of our fossil plants, and
•
higher depreciation expense related to the completion of installation of back-end technology at two of our fossil plants.
The decreases were partially offset by
•
favorable amounts related to the MTM activity,
•
favorable results from our coal optimization efforts, and
•
an increase from new wholesale contracts entered into in the first half of 2011.
The year-over-year detail for these variances for these periods is discussed below:
Year ended December 31, 2012 as compared to 2011
Operating Revenues decreased $1,278 million due to
Generation Revenues decreased $975 million due primarily to
•
lower net revenues of $564 million due primarily to lower average realized prices for our generation sold into the PJM and NY power pools and MTM losses due from the realization of prior year unrealized gains and adverse changes in unrealized prices in 2012 for forward positions,
•
a decrease of $264 million due primarily to lower average pricing and lower volumes of electricity sold under our BGS contracts, primarily as a result of warmer winter weather in 2012 as well as customer migration, and
•
a net decrease of $154 million due to lower volumes on wholesale load contracts in the PJM and New England (NE) regions,
•
partially offset by a net increase of $7 million in other revenues consisting of higher net capacity revenues, partially offset by lower operating reserve, ancillary and RMR revenues.
Gas Supply Revenues decreased $336 million due primarily to
•
a decrease of $306 million in sales under the BGSS contract, substantially comprised of lower average gas prices on lower volumes of sales in 2012 due to warmer average temperatures during the first quarter of 2012, and
•
a net decrease of $31 million due primarily to lower average prices, partially offset by higher sales volumes to third party customers.
Trading Revenues increased $33 million in 2012 due to the discontinuation of trading activities in the second quarter of 2011. As a result, the increase is due primarily to the absence of losses on electric energy supply contracts recognized in 2011.
Operating Expenses
Energy Costs represent the cost of generation, which includes fuel costs for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $663 million due to
•
Gas costs decreased $312 million, principally related to obligations under the BGSS contract, reflecting lower average gas inventory costs coupled with lower sales volumes in 2012 due primarily to warmer average temperatures during the first quarter of 2012.
•
Generation costs decreased $351 million due primarily to $227 million of lower fuel costs, reflecting the utilization of lower volumes of coal and lower average natural gas prices, partially offset by the utilization of higher volumes of natural gas and higher nuclear fuel prices in 2012. The decrease was also attributable to $152 million of lower energy purchases, primarily in the PJM region as a result of lower load contract volumes in 2012, and $31 million of lower emission charges due to lower coal generation in the PJM and NE regions and impairment charges recorded in 2011 related to excess SO2 emission allowances. These decreases were partially offset by an increase of $59 million due primarily to higher congestion costs in the PJM region.
Operation and Maintenance increased $20 million due primarily to
•
an increase of $85 million due to damage from Superstorm Sandy for repairs to certain of our generation plants, primarily those in our fossil fleet, and to recognize the estimated loss of use of fossil materials and supplies, partially offset by a $19 million insurance recovery, and
•
a net increase of $64 million due to higher refueling costs in 2012 for refueling outages at our 100%-owned Hope Creek nuclear unit and our 57%-owned Salem Unit 2 as compared to refueling outages for both of our 57%-owned Salem nuclear units in 2011,
•
partially offset by a net decrease of $109 million largely due to lower fossil planned outages in 2012 and lower maintenance costs, principally at our gas-fired Bethlehem Energy Center (BEC) in New York, gas-fired Bergen and Linden facilities, coal/gas-fired Hudson and Mercer coal/gas-fired plants in New Jersey, and 23%-owned coal-fired Conemaugh plant in Pennsylvania, as well as to the absence of costs incurred for the cancellation and renegotiation of a major contractual agreement for parts and services in 2011.
Depreciation and Amortization increased $13 million due primarily to higher depreciable asset bases at Fossil and Nuclear, including placing into service the new gas-fired peaking units at Kearny, New Jersey and New Haven, Connecticut on June 1, 2012 and completion of the steam path retrofit upgrades at our co-owned Peach Bottom Units 2 and 3 in October 2012 and October 2011, respectively.
Other Income (Deductions) experienced no material change.
Other-Than-Temporary Impairments decreased $2 million due to lower impairments in 2012 on the NDT and Rabbi Trust Funds.
Interest Expense decreased $41 million due primarily to a decrease of $55 million resulting primarily from the maturity of $606 million of 7.75% Senior Notes in early April 2011 and the early redemption of $600 million of 6.95% Senior Notes in December 2011, partially offset by increases of $12 million due to two $250 million Senior Notes issuances in September 2011 and $3 million in higher interest costs since interest capitalization ceased for our Kearny and New Haven projects on their June 1, 2012 in-service date.
Income Tax Expense decreased $252 million in 2012 due primarily to lower pre-tax income.
Income (Loss) from Discontinued Operations
In 2011, we sold our two 1,000 MW combined-cycle generating facilities in Texas in separate transactions. In March 2011, we completed the sale of one plant for proceeds of $352 million at an after-tax gain of $54 million. In July 2011, we completed the sale of the second plant for proceeds of $335 million at an after-tax gain of $25 million. The results of operations for both
plants for 2011 and 2010, including the gains in 2011 on the sales of the plants, are included in this category. See Item 8. Financial Statements and Supplementary Data-Note 4. Discontinued Operations and Dispositions for additional information.
Year ended December 31, 2011 as compared to 2010
Operating Revenues decreased $415 million due to
Gas Supply Revenues decreased $290 million due primarily to
•
a net decrease of $283 million in sales under the BGSS contract, substantially comprised of lower average gas prices on lower volumes of sales in 2011 due to warmer average temperatures during the fourth quarter of 2011,
•
a net decrease of $7 million due primarily to lower average gas prices partially offset by higher sales volumes to third party customers.
Generation Revenues decreased $143 million due primarily to
•
a net decrease of $305 million due primarily to lower average pricing and lower volumes of electricity sold under our BGS contracts as a result of customer migration,
•
a decrease of $70 million due primarily to lower capacity payments from the various power pools resulting from lower market prices, and
•
a decrease of $8 million due to lower operating reserve revenue in 2011.
These were partially offset by
•
an increase of $136 million from new wholesale load contracts in the PJM and NE regions commencing in January 2011 and April 2011, respectively, net of lower average realized prices in the NE region, and
•
higher net revenues of $108 million due primarily to MTM gains on economic hedging activity of $228 million, partially offset by lower realized prices in the PJM and NY power pools and lower volumes of generation sold in the PJM and NE power pools of $120 million.
Trading Revenues increased $18 million due primarily to lower net losses in 2011 on certain electric energy supply contracts as well as the discontinuation of trading activities in the second quarter of 2011.
Operating Expenses
Energy Costs represent the cost of generation, which includes fuel purchases for generation as well as purchased energy in the market, and gas purchases to meet Power’s obligation under its BGSS contract with PSE&G. Energy Costs decreased $328 million due to
•
Gas costs decreased $282 million, principally related to obligations under the BGSS contract, reflecting lower average gas inventory costs coupled with lower sales volumes in 2011 due to warmer average temperatures during the fourth quarter of 2011.
•
Generation costs decreased by $46 million due primarily to $211 million of lower fuel costs, including $251 million of lower fossil fuel costs primarily reflecting the utilization of lower volumes of both coal and oil, favorable results from our coal optimization efforts, and lower natural gas prices, partially offset by higher MTM losses and higher nuclear fuel costs in 2011. The decrease was also attributable to $16 million of lower emission charges, including $10 million of lower impairment charges related to excess SO2 emission allowances. These decreases were partially offset by an increase of $153 million in higher energy purchases in 2011 in the PJM and NE power pools as the result of lower generation and the need to meet higher load contract demand in 2011 and $23 million of higher operating reserve obligations in the PJM region.
Operation and Maintenance increased $56 million due primarily to
•
a net increase of $47 million due largely to planned outage costs, including hot gas path inspection outage costs at our BEC and Linden facilities as well as higher outage costs at our Bergen, and Keystone facilities, partially offset by higher outage and repair costs at certain of our other fossil plants in 2010,
•
$20 million of costs incurred for the cancellation and renegotiation of a major contractual agreement for parts and services for our combined cycle Bethlehem Energy (BEC) facility in New York and Linden and Bergen facilities in New Jersey, and
•
a net increase of $3 million due to refurbishment projects at our Salem nuclear facilities,
•
partially offset by a decrease of $13 million due to a decrease in pension and OPEB costs tempered by higher labor costs and incentive awards.
Depreciation and Amortization increased $49 million due primarily to
•
a $37 million increase due to completion of installation of back-end technology at the end of 2010 at our Mercer and Hudson generating facilities, and
•
a $12 million increase due to higher depreciable asset bases at Nuclear and Fossil.
Other Income and (Deductions) The net decrease of $6 million was due primarily to
•
a $17 million premium paid on the early extinguishment of 6.95% Senior Notes due in June 2012, and
•
the absence of $7 million of gains realized in 2010 from restructuring the Rabbi Trust,
•
partially offset by higher net realized gains of $19 million on our NDT Fund.
Other-Than-Temporary Impairments increased $11 million due primarily to higher impairments on the NDT Fund in 2011.
Interest Expense increased $18 million due primarily to
•
Higher interest expense of $49 million resulting primarily from the installation by year-end 2010 of back-end technology at our Mercer and Hudson stations for which we had been allowed to capitalize interest costs in 2010 while such projects were under construction,
•
partially offset by lower interest expense of $30 million due primarily to the redemption of $606 million of 7.75% Senior Notes in early April 2011 and lower debt issuance costs of $3 million.
Income Tax Expense decreased $93 million in 2011 due primarily to lower pre-tax income.
Income (Loss) from Discontinued Operations
See explanation above for year ended December 31, 2012 as compared to 2011.
PSE&G
For the year ended December 31, 2012, the primary reasons for the increase in Income from Continuing Operations were
•
higher transmission revenues due to increased investments in transmission projects, and
•
tax benefits related to settlement of IRS audits,
•
partially offset by higher Operation and Maintenance expense, including higher storm costs and higher pension and OPEB expenses.
For the year ended December 31, 2011, the primary reasons for the increase in Income from Continuing Operations were
•
the absence of a $72 million after-tax charge recorded in June 2010 related to the refund of previous MTC collections,
•
higher annualized base rates for electric and gas delivery as well as transmission, and
•
lower Operation and Maintenance expense, largely due to lower pension and OPEB expenses.
The year-over-year details for these variances for these periods are discussed below:
Year ended December 31, 2012 as compared to 2011
Operating Revenues decreased $700 million due primarily to
Commodity Revenue decreased $792 million due to lower Electric and Gas revenues. This is entirely offset as savings in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS to retail customers.
•
Electric revenues decreased $488 million due primarily to $431 million in lower BGS revenues and $57 million in lower revenues from the sale of Non-Utility Generation (NUG) energy and collections of Non-Utility Generation Charges (NGC) due primarily to lower prices. BGS sales decreased 12% due primarily to customer migration to third party suppliers (TPS); in contrast, delivery sales decreased only 1%.
•
Gas revenues decreased $304 million due to lower BGSS volumes of $115 million and lower BGSS prices of $189 million. The average price of natural gas was 15% lower in 2012 than in 2011.
Delivery Revenues increased $81 million due primarily to an increase in transmission revenues.
•
Transmission revenues were $83 million higher due to increased investments in transmission projects.
•
Electric distribution revenues decreased $6 million due primarily to lower Transitional Energy Facilities Assessment (TEFA) revenue of $22 million due to a lower TEFA rate and lower sales volumes of $13 million, partially offset by higher Solar, Energy Efficiency and Conservation Program (Solar/EE) revenue of $20 million and higher Capital Infrastructure Program (CIP) revenue of $9 million.
•
Gas distribution revenues increased $4 million due primarily to higher Weather Normalization Clause (WNC) revenue of $52 million and higher CIP revenue of $8 million, partially offset by lower sales volumes of $43 million, and lower TEFA revenue of $13 million due to a lower TEFA rate.
Clause Revenues increased $12 million due primarily to higher Securitization Transition Charge (STC) revenues of $19 million, partially offset by lower Societal Benefit Charges (SBC) of $6 million and a lower Margin Adjustment Clause (MAC) of $2 million. The changes in STC and SBC amounts were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, Depreciation and Amortization and Interest Expense. PSE&G does not earn margin on SBC, MAC or STC collections.
Energy Costs decreased $792 million. This is entirely offset by Commodity Revenue.
•
Electric costs decreased $488 million or 18% due to $258 million in lower BGS and NUG volumes, $202 million of lower BGS prices, and $28 million for decreased deferred cost recovery. BGS and NUG volumes decreased 10% due primarily to customer migration to TPS.
•
Gas costs decreased $304 million or 24% due to $115 million or 9% in lower sales volumes due primarily to weather and $189 million or 15% in lower prices.
Operation and Maintenance increased $136 million, of which the most significant components were
•
a $32 million increase in costs recognized related to SBC, Solar/EE and CIP,
•
a $27 million increase in pension and other postretirement benefits (OPEB) expenses,
•
a $17 million increase in storm damages,
•
a $10 million increase in transmission related costs, and
•
a $7 million increase in payroll costs.
Depreciation and Amortization increased $59 million due primarily to
•
a $39 million increase in amortization of Regulatory Assets, and
•
a $21 million increase in additional plant in service.
Taxes Other Than Income Taxes decreased $35 million due to a lower TEFA rate and lower sales volumes for electric and gas.
Other Income and (Deductions) net increase of $26 million was due primarily to
•
a $14 million increase in capitalized allowance for equity funds used during construction,
•
an $8 million increase in solar loan interest income, and
•
a $4 million increase in Rabbi Trust interest and gains.
Other-Than-Temporary Impairments experienced no material change.
Interest Expense decreased $15 million due primarily to the partial redemption of securitization debt and higher interest capitalization related to higher construction work in progress, partially offset by interest relating to the new debt issued in 2012. See Note 9. Changes in Capitalization for details.
Income Tax Expense decreased $33 million due primarily to changes in tax reserves related to settlement of IRS tax audits.
Year ended December 31, 2011 as compared to 2010
Operating Revenues decreased $543 million due primarily to
Commodity Revenue decreased $704 million due to lower Electric and Gas revenues. This is entirely offset as savings in Energy Costs. PSE&G earns no margin on the provision of BGS and BGSS.
•
Electric revenues decreased $397 million due primarily to $466 million in lower BGS revenues, partially offset by $69 million in higher revenues from the sale of NUG energy and collections of NGC due primarily to higher prices. BGS sales decreased 16% due primarily to customer migration to TPS; in contrast, delivery sales decreased only 2%.
•
Gas revenues decreased $307 million due to lower BGSS prices of $259 million and lower BGSS volumes of $48 million. The average price of gas was 3% lower in 2011 than in 2010.
Delivery Revenues increased $74 million due primarily to an increase in prices for electric and gas distribution and transmission.
•
Transmission revenues were $42 million higher due primarily to increased investments in transmission projects.
•
Gas distribution revenues increased $32 million due primarily to higher WNC revenue of $19 million and the impact of base rate increases of $17 million, partially offset by lower CIP revenue of $5 million.
•
Electric distribution revenues were flat due primarily to the impact of base rate increases of $17 million and higher CIP revenue of $1 million, offset by lower sales volumes of $18 million.
Clause Revenues increased $73 million due primarily to the absence of $122 million charge recorded in June 2010 related to our agreement to refund previous MTC collections over two years and higher SBC and MAC of $49 million, partially offset by lower STC revenues of $98 million. The changes in STC, SBC and MAC amounts were entirely offset by the amortization of related costs (Regulatory Assets) in O&M, Depreciation and Amortization and Interest Expense. PSE&G earns no margins on SBC, STC or MAC collections.
Other Operating Revenues increased $14 million due primarily to increased revenues from our appliance repair business and miscellaneous electric operating revenues.
Energy Costs decreased $704 million. This is entirely offset by Commodity Revenue.
•
Electric costs decreased $397 million due to $405 million in lower BGS and NUG volumes and $75 million of lower BGS and NUG prices, partially offset by $83 million for increased deferred cost recovery. BGS and NUG volumes decreased 14% due primarily to customer migration to TPS.
•
Gas costs decreased $307 million or 19% due to $259 million or 16% in lower prices and $48 million or 3% in lower sales volumes due primarily to weather.
Operation and Maintenance decreased $70 million due primarily to
•
a $71 million decrease in pension and OPEB expenses,
•
$20 million of lower net deferred expenses associated with SBC, Regional Greenhouse Gas Initiative and Stimulus clauses, and
•
the absence of $15 million in expenses relating to 2010 rate case disallowances.
These were partially offset by
•
a $9 million increase in storm restoration work,
•
a $6 million increase in costs relating to tree trimming,
•
a $3 million increase in bad debt expense, and
•
a $3 million increase in incentive payments.
Depreciation and Amortization decreased $31 million due primarily to
•
a decrease of $63 million for amortization of Regulatory Assets,
•
partially offset by an increase of $28 million for additional plant in service, and an increase of $3 million in net other charges.
Other Income and (Deductions) experienced no material change.
Other-Than-Temporary Impairments experienced no material change.
Interest Expense decreased $8 million due primarily to lower average debt balances.
Income Tax Expense increased $108 million due primarily to higher pre-tax income.
Energy Holdings
For the year ended December 31, 2012, the primary reasons for the increase in Income from Continuing Operations were
•
the absence of the $170 million after-tax charge on leveraged leases related to Dynegy in 2011 and the settlement proceeds received in 2012 (see Item 8. Financial Statements and Supplementary Data-Note 8. Financing Receivables), and
•
the tax benefits related to the settlement of IRS tax audits in the first quarter of 2012.
For the year ended December 31, 2011, the primary reason for the decrease in Income from Continuing Operations was
•
the $170 million after-tax charge on leveraged leases related to Dynegy.
LIQUIDITY AND CAPITAL RESOURCES
The following discussion of our liquidity and capital resources is on a consolidated basis, noting the uses and contributions, where material, of our three direct operating subsidiaries.
Financing Methodology
We expect our capital requirements to be met through internally generated cash flows and external financings, consisting of short-term debt for working capital needs and long-term debt for capital investments.
PSE&G’s sources of external liquidity include a $600 million multi-year syndicated credit facility. PSE&G’s commercial paper program is the primary vehicle for meeting seasonal, intra-month and temporary working capital needs. PSE&G does not engage in any intercompany borrowing or lending. PSE&G maintains back-up facilities in an amount sufficient to cover 100% of commercial paper outstanding. PSE&G’s dividend payments to PSEG are consistent with its capital structure objectives which have been established to maintain investment grade credit ratings. PSE&G’s long-term financing plan is designed to replace maturities, fund a portion of its capital program and manage short-term debt balances. Generally, PSE&G uses either secured medium-term notes or first mortgage bonds to raise long-term capital.
PSEG, Power, Energy Holdings and PSEG Services Corporation participate in a corporate money pool, an aggregation of daily cash balances designed to efficiently manage their respective short-term liquidity needs. PSEG’s sources of external liquidity include multi-year syndicated credit facilities totaling $1 billion. These facilities are available to back-stop PSEG’s commercial paper program, issue letters of credit and for general corporate purposes. These facilities may also be used to provide support to PSEG's subsidiaries. PSEG’s credit facilities and the commercial paper program are available to support PSEG working capital needs or to temporarily fund growth opportunities in advance of obtaining permanent financing. From time to time, PSEG may make equity contributions or provide credit support to its subsidiaries.
Power’s sources of external liquidity include $2.7 billion of syndicated multi-year credit facilities. Additionally, from time to time, Power maintains bilateral credit agreements designed to enhance its liquidity position. Credit capacity is primarily used to provide collateral in support of hedging activities and to meet potential collateral postings in the event of a credit rating downgrade below investment grade. Power’s dividend payments to PSEG are also designed to be consistent with its capital structure objectives which have been established to maintain investment grade credit ratings and provide sufficient financial flexibility. Generally, Power issues senior unsecured debt to raise long-term capital.
Operating Cash Flows
We expect our operating cash flows combined with cash on hand and financing activities to be sufficient to fund capital expenditures and shareholder dividend payments.
For the year ended December 31, 2012, our operating cash flow decreased by $770 million. For the year ended December 31, 2011, our operating cash flow increased by $1,393 million. The net changes were due to net changes from our subsidiaries as discussed below.
Power
Power’s operating cash flow decreased $433 million from $1,812 million to $1,379 million for the year ended December 31, 2012, as compared to 2011, primarily resulting from lower earnings and a $173 million decrease from lower net collections of counterparty receivables, partially offset by
•
a decrease of $57 million in benefit plan funding,
•
a $73 million decrease in spending for fuel, materials and supplies, and
•
a $246 million decrease in net payment of counterparty payables.
Power’s operating cash flow increased $246 million from $1,566 million to $1,812 million for the year ended December 31, 2011, as compared to 2010, primarily resulting from
•
an increase of $368 million due to lower tax payments, primarily related to the benefits of accelerated tax depreciation under new tax provisions enacted in 2010 (see Item 8. Financial Statements and Supplementary Data-Note 20. Income Taxes for additional information), and
•
a $302 million increase from net collection of counterparty receivables.
These were partially offset by
•
a $171 million increase in net payment of counterparty payables,
•
a $161 million net increase in spending on fuel inventories, and
•
lower earnings.
PSE&G
PSE&G’s operating cash flow decreased $520 million from $1,776 million to $1,256 million for the year ended December 31, 2012, as compared to 2011, due primarily to
•
a lower tax receipt of $484 million due to lower benefit of accelerated tax depreciation, and
•
a decrease of $306 million due to lower collections from customer billings,
•
partially offset by a decrease of $117 million in benefit plan funding, and
•
a decrease of $88 million in net prepayments due primarily to the application of prior year prepayment carryforwards towards current year state tax liabilities.
PSE&G’s operating cash flow increased $765 million from $1,011 million to $1,776 million for the year ended December 31, 2011, as compared to 2010, due primarily to higher earnings combined with
•
an increase of $587 million due to lower tax payments, primarily related to the benefits of accelerated tax depreciation under new tax provisions enacted in 2010 (see Item 8. Financial Statements and Supplementary Data-Note 20. Income Taxes for additional information), and
•
an increase of $273 million due to higher collections of customer billings,
•
partially offset by a decrease of $108 million in net other working capital.
Energy Holdings
Energy Holdings’ operating cash flow increased $149 million for the year ended December 31, 2012, as compared to 2011, primarily due to lower tax payments in 2012 related to the absence of lease sale activity in 2012 and tax benefits related to settlement of IRS audits.
Energy Holdings’ operating cash flow increased $341 million for the year ended December 31, 2011, as compared to 2010, primarily due to lower tax payments in 2011 related to less lease sale activity in 2011.
Short-Term Liquidity
We continually monitor our liquidity and seek to add capacity as needed to meet our liquidity requirements. Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. Our total credit facilities and available liquidity as of December 31, 2012 were as follows:
As of December 31, 2012, our credit facility capacity is in excess of our projected maximum liquidity requirements over our 12 month planning horizon. Our maximum liquidity requirements are based on stress scenarios that incorporate changes in commodity prices and the potential impact of Power losing its investment grade credit rating. PSE&G’s credit facility primary use is to support its Commercial Paper Program under which as of December 31, 2012, $263 million was outstanding. For
additional information, see Item 8. Financial Statements and Supplementary Data-Note 13. Commitments and Contingent Liabilities and Note 14. Schedule of Consolidated Debt.
Long-Term Debt Financing
PSE&G had $150 million of 5.00% Medium Term Notes mature in January 2013 and issued $400 million of 3.80% Secured Medium-Term Notes, Series H, due January, 2043. PSE&G also has $300 million of 5.38% Medium Term Notes maturing in September 2013 and $275 million of 6.33% Medium Term Notes maturing in November 2013. Power has $300 million of 2.50% Senior Notes maturing in April 2013.
For a discussion of our long-term debt transactions during 2012 and into 2013, see Item 8. Financial Statements and Supplementary Data-Note 14. Schedule of Consolidated Debt.
Debt Covenants
Our credit agreements contain maximum debt to equity ratios and other restrictive covenants and conditions to borrowing. We are currently in compliance with all of our debt covenants. Continued compliance with applicable financial covenants will depend upon our future financial position, level of earnings and cash flows, as to which no assurances can be given.
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 to 1, and/or against retired Mortgage Bonds. As of December 31, 2012, PSE&G’s Mortgage coverage ratio was 3.6 to 1 and the Mortgage would permit up to approximately $2.6 billion aggregate principal amount of new Mortgage Bonds to be issued against additions and improvements to its property.
Default Provisions
Our bank credit agreements and indentures contain various default provisions that could result in the potential acceleration of payment under the defaulting company’s agreement. We have not defaulted under these agreements.
PSEG’s bank credit agreements contain cross default provisions under which events at Power or PSE&G, including payment defaults, bankruptcy events, the failure to satisfy certain final judgments or other events of default under their financing agreements, would each constitute an event of default. Under the bank credit agreements, it would be an event of default if both Power and PSE&G cease to be wholly owned by PSEG.
There are no cross default provisions to affiliates in Power’s or PSE&G’s credit agreements or indentures.
Ratings Triggers
Our debt indentures and credit agreements 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. In the event that we are not able to affirm representations and warranties on credit agreements, lenders would not be required to make loans.
Fluctuations in commodity prices or a deterioration of Power’s credit rating to below investment grade could increase Power’s required margin postings under various agreements entered into in the normal course of business. Power believes it has sufficient liquidity to meet the required posting of collateral which would likely result from a credit rating downgrade at today’s market prices.
In accordance with BPU requirements under the BGS contracts, PSE&G is required to maintain an investment grade credit rating. If PSE&G were to lose its investment grade rating, it would be required to file a plan to assure continued payment for the BGS requirements of its customers.
PSE&G is the servicer for the bonds issued by PSE&G Transition Funding LLC and PSE&G Transition Funding II LLC. Cash collected by PSE&G to service these bonds is commingled with PSE&G’s other cash until it is remitted to the bond trustee each month. If PSE&G were to lose its investment grade rating, PSE&G would be required to remit collected cash daily to the bond trustee. PSE&G is prohibited from advancing its own funds to make payments related to such bonds.
Common Stock Dividends
In 2012, dividend payments increased from $1.37 per share to $1.42 per share, representing a change in our dividend policy, moving from a strict earnings payout based approach to one that takes into consideration the growing contribution to earnings and cash from our regulated operations and continued cash flow from our generation business.
On February 19, 2013, our Board of Directors approved a $0.36 per share common stock dividend for the first quarter of 2013. This reflects an indicated annual dividend rate of $1.44 per share. We expect to continue to pay cash dividends on our common stock; however, the declaration and payment of future dividends to holders of our common stock will be at the discretion of the Board of Directors and will depend upon many factors, including our financial condition, earnings, capital requirements of our businesses, alternate investment opportunities, legal requirements, regulatory constraints, industry practice and other factors that the Board of Directors deems relevant.
Credit Ratings
If the rating agencies lower or withdraw our credit ratings, such revisions may adversely affect the market price of our securities and serve to materially increase our cost of capital and limit access to capital. Outlooks assigned to ratings are as follows: stable, negative (Neg) or positive (Pos). 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 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.
In May 2012, Moody's published updated credit opinions on PSEG, Power and PSE&G. Moody's upgraded PSE&G's Mortgage Bond Rating to A1 from A2 and revised the outlook to stable from positive. PSEG's and Power's ratings and outlooks remained unchanged. In October 2012, S&P published updated credit opinions that left the ratings and outlooks for Power and PSE&G unchanged. In November 2012, S&P published an updated credit opinion for PSEG that left its ratings and outlook unchanged. In July 2012, Fitch upgraded PSE&G's Mortgage Bond Rating to A+ from A and its stable outlook remained unchanged. In January 2013, Fitch published updated credit opinions on PSEG, Power and PSE&G. PSEG's, Power's and PSE&G's ratings and outlooks remained unchanged.
(A)
Moody’s ratings range from Aaa (highest) to C (lowest) for long-term securities and P1 (highest) to NP (lowest) for short-term securities.
(B)
S&P ratings range from AAA (highest) to D (lowest) for long-term securities and A1 (highest) to D (lowest) for short-term securities.
(C)
Fitch ratings range from AAA (highest) to D (lowest) for long-term securities and (highest) to D (lowest) for short-term securities.
Other Comprehensive Loss
For the year ended December 31, 2012, we had Other Comprehensive Loss of $51 million on a consolidated basis. Other Comprehensive Loss was due primarily to a $46 million increase in our consolidated liability for pension and postretirement benefits and $24 million of unrealized losses on derivative contracts accounted for as hedges and was partially offset by $19 million of net unrealized gains related to Available-for-Sale Securities.
CAPITAL REQUIREMENTS
It is expected that all of our capital requirements over the next three years will come from a combination of internally generated funds and external debt financing. Projected capital construction and investment expenditures, excluding nuclear fuel purchases, for the next three years are presented in the table below. These amounts are subject to change, based on various factors. We will continue to approach non-regulated solar and other renewables investments opportunistically, seeking projects that will provide attractive risk-adjusted returns for our shareholders.
Power
Power’s projected expenditures for the various items listed above are primarily comprised of the following:
•
Baseline Maintenance-investments to replace major parts and enhance operational performance.
•
Environmental/Regulatory-investments made in response to environmental, regulatory or legal mandates.
•
Nuclear Expansion-investments associated with various capital projects at existing facilities to either extend plants’ useful lives or increase operating output.
In 2012, Power made $438 million of capital expenditures, including interest capitalized during construction (IDC) but excluding $208 million for nuclear fuel, primarily related to various projects at Fossil and Nuclear.
PSE&G
PSE&G’s projections for future capital expenditures include material additions and replacements to its transmission and distribution systems to meet expected growth and to manage reliability. As project scope and cost estimates develop, PSE&G will modify its current projections to include these required investments. PSE&G’s projected expenditures for the various items reported above are primarily comprised of the following:
•
Reliability Enhancements-investments made to improve the reliability and efficiency of the system or function.
•
Facility Replacement-investments made to replace systems or equipment in kind.
•
Support Facilities-ancillary equipment needed to support the business lines, such as computers, office furniture and buildings and structures housing support personnel or equipment/inventory.
•
New Business-investments made in support of new business (e.g. to add new customers).
•
Environmental/Regulatory-investments made in response to environmental, regulatory or legal mandates.
•
Renewables-investments made in response to regulatory or legal mandates relating to renewable energy.
In 2012, PSE&G made $1,852 million of capital expenditures, including $1,770 million of investment in plant, primarily for transmission and distribution system reliability and $82 million in solar loan investments. This does not include expenditures for certain energy efficiency and renewable programs of $8 million or cost of removal, net of salvage, of $116 million, which are included in operating cash flows.
Additional Projects
The estimated project expenditures related to the following filings or transmission infrastructure investments are not included in our $6.1 billion three-year capital forecast table.
In February 2013, we filed a petition with the BPU describing the improvements we recommend making to our electric and gas distribution systems over a ten year period to harden and improve resiliency for the future. In this petition, we sought approval to invest $0.9 billion in our gas distribution system and $1.7 billion in our electric distribution over an initial five year period, plus associated expenses, and to receive contemporaneous recovery of and on such investments. This matter is pending. The current estimated cost of the entire program, including the first five years of investments for which we sought approval in this petition, is $3.9 billion. We anticipate seeking BPU approval to complete our investment under the program at a later date. We also intend to invest $1.5 billion in FERC jurisdictional investments in transmission infrastructure over the next ten years.
In July 2012, we filed for an extension of our Solar 4 All program. In this filing, we are seeking BPU approval for up to $690 million to develop 136 MW of utility-owned solar photovoltaic systems over a five year period starting in 2013. Consistent with the existing Solar 4 All program, we propose to sell the energy and capacity from the solar systems in the PJM wholesale energy and capacity markets which will offset the cost of the program.
We also filed for an additional extension of our Solar Loan program (Solar Loan III) in July 2012. In the filing, we are seeking BPU approval to provide financing support for the installation of 97.5 MW of solar systems by providing loans to qualified customers. The total investment of the proposed Solar Loan III program is anticipated to be up to $193 million once the program is fully subscribed, projects are built and loans are closed.
Disclosures about Long-Term Maturities, Contractual and Commercial Obligations and Certain Investments
The following table reflects our contractual cash obligations and other commercial commitments in the respective periods in which they are due. See Item 8. Financial Statements and Supplementary Data -Note 13. Commitments and Contingent Liabilities for a discussion of contractual commitments related to the construction activity, discussed above, and for a variety of services for which annual amounts are not quantifiable. In addition, the table summarizes anticipated recourse and non-recourse debt maturities for the years shown. For additional information, see Item 8. Financial Statements and Supplementary Data-Note 14. Schedule of Consolidated Debt. The table below does not reflect any anticipated cash payments for pension obligations due to uncertain timing of payments or liabilities for uncertain tax positions since we are unable to reasonably estimate the timing of liability payments in individual years beyond 12 months due to uncertainties in the timing of the effective settlement of tax positions. See Item 8. Financial Statements and Supplementary Data-Note 20. Income Taxes for additional information.
OFF-BALANCE SHEET ARRANGEMENTS
Power
Power issues guarantees in conjunction with certain of its energy contracts. See Item 8. Financial Statements and Supplementary Data-Note 13. Commitments and Contingent Liabilities for further discussion.
Energy Holdings
We have certain investments that are accounted for under the equity method in accordance with GAAP. Accordingly, amounts recorded on the Consolidated Balance Sheets for such investments represent our equity investment, which is increased for our pro-rata share of earnings less any dividend distribution from such investments. One of the companies in which we invest that is accounted for under the equity method has an aggregate $28 million of long-term debt on its Consolidated Balance Sheet. Our pro-rata share of such debt is $14 million. This debt is non-recourse to us. We are generally not required to support the debt service obligations of this company. However, default with respect to this non-recourse debt could result in a loss of invested equity.
Through Energy Holdings, we have investments in leveraged leases that are accounted for in accordance with GAAP Accounting for Leases. Leveraged lease investments generally involve three parties: an owner/lessor, a creditor and a lessee. In a typical leveraged lease arrangement, 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 secured by the property subject to the lease. Such long-term financing is non-recourse to the lessor and is not presented on our Consolidated Balance Sheets. In the event of default, the leased asset, and in some cases the lessee, secures the loan. As a lessor, Energy Holdings has ownership rights to the property and rents the property to the lessees for use in their business operations. For additional information, see Item 8. Financial Statements and Supplementary Data-Note 7. Long-Term Investments.
In the event that collectability of the minimum lease payments to be received by Energy Holdings is no longer reasonably assured, the accounting treatment for some of the leases may change. In such cases, Energy Holdings may deem that a lessee has a high probability of defaulting on the lease obligation, and would reclassify the lease from a leveraged lease to an operating lease and would consider the need to record an impairment of its investment. Should this event occur, 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.
CRITICAL ACCOUNTING ESTIMATES
Under GAAP, many accounting standards 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. We have determined that the following estimates are considered critical to the application of rules that relate to the respective businesses.
Accounting for Pensions
We calculate pension costs using various economic and demographic assumptions.
Assumptions and Approach Used: 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.
Our 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, our measurement date. The discount rate used to determine year-end obligations is also used to develop the following year’s net periodic pension cost.
Our 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 and long-term inflation assumptions.
Based on the above assumptions, we have estimated net periodic pension expense of approximately $110 million, net of amounts capitalized, and contributions of up to $145 million in 2013.
Effect if Different Assumptions Used: As part of the business planning process, we have modeled future costs assuming an 8.00% rate of return and a 4.20% discount rate for 2013, a 4.50% discount rate for 2014, increasing annually by 25 basis points to 5.25% in 2017. Actual future pension expense and funding levels will depend on future investment performance, changes in discount rates, market conditions, funding levels relative to our projected benefit obligation and accumulated benefit obligation and various other factors related to the populations participating in the pension plans.
The following chart reflects the sensitivities associated with a change in certain assumptions. The effects of the assumption changes shown below solely reflect the impact of that specific assumption.
See Item 7A.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK
The market risk inherent in our market-risk sensitive instruments and positions is the potential loss arising from adverse changes in commodity prices, equity security prices and interest rates as discussed in the Notes to Consolidated Financial Statements. It is our policy to use derivatives to manage risk consistent with business plans and prudent practices. We have a Risk Management Committee comprised of executive officers who utilize a risk oversight function to ensure compliance with our corporate policies and risk management practices.
Additionally, we are exposed to counterparty credit losses in the event of non-performance or non-payment. We have a credit management process, which is used to assess, monitor and mitigate counterparty exposure. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on our financial condition, results of operations or net cash flows.
Commodity Contracts
The availability and price of energy-related commodities are subject to fluctuations from factors such as weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market rules and other events. To reduce price risk caused by market fluctuations, we enter into supply contracts and derivative contracts, including forwards, futures, swaps and options with approved counterparties. These contracts, in conjunction with physical sales and other services, help reduce risk and optimize the value of owned electric generation capacity.
Value-at-Risk (VaR) Models
VaR represents the potential losses, under normal market conditions, for instruments or portfolios due to changes in market factors, for a specified time period and confidence level. We estimate VaR across our commodity businesses.
MTM VaR consists of MTM derivatives that are economic hedges, some of which qualify for hedge accounting. The MTM VaR calculation does not include market risks associated with activities that are subject to accrual accounting, primarily our generating facilities and some load serving activities.
The VaR models used are variance/covariance models adjusted for the change of positions with 95% and 99.5% confidence levels and a one-day holding period for the MTM activities. The models assume no new positions throughout the holding periods; however, we actively manage our portfolio.
(A)
As of December 31, 2012 and December 31, 2011, there was no trading VaR since we discontinued trading activities in the second quarter of 2011.
See Item 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
This combined Form 10-K is separately filed by PSEG, Power and PSE&G. Information contained herein relating to any individual company is filed by such company on its own behalf. Power and PSE&G each make representations only as to itself and make no representations as to any other company.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors of
Public Service Enterprise Group Incorporated:
We have audited the accompanying consolidated balance sheets of Public Service Enterprise Group Incorporated and subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15(B)(a). These consolidated financial statements and consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and consolidated financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Sole Member and Board of Directors of
PSEG Power LLC:
We have audited the accompanying consolidated balance sheets of PSEG Power LLC and subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, member’s equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15(B)(b). These consolidated financial statements and consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and consolidated financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, 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, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, 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.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Sole Stockholder and Board of Directors of
Public Service Electric and Gas Company:
We have audited the accompanying consolidated balance sheets of Public Service Electric and Gas Company and subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated statements of operations, comprehensive income, common stockholder’s equity, and cash flows for each of the three years in the period ended December 31, 2012. Our audits also included the consolidated financial statement schedule listed in the Index at Item 15(B)(c). These consolidated financial statements and consolidated financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on the consolidated financial statements and consolidated financial statement schedule based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, 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, 2012 and 2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2012, 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.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
Millions
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED BALANCE SHEETS
Millions
See Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
See the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
Millions
See Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS
Millions
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED BALANCE SHEETS
Millions
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.
PSEG POWER LLC
CONSOLIDATED STATEMENTS OF MEMBER’S EQUITY
Millions
See disclosures regarding PSEG Power LLC included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
Millions
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Millions
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Millions
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED BALANCE SHEETS
Millions
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Millions
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
Millions
See disclosures regarding Public Service Electric and Gas Company included in the Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies
Public Service Enterprise Group Incorporated, (PSEG) is a holding company with a diversified business mix within the energy industry. Its operations are primarily in the Northeastern and Mid Atlantic United States and in other select markets. PSEG’s principal direct wholly owned subsidiaries are:
•
PSEG Power LLC (Power)-which is a multi-regional, wholesale energy supply company that integrates its generating asset operations and gas supply commitments with its wholesale energy, fuel supply and energy trading functions through three principal direct wholly owned subsidiaries. Power’s subsidiaries are subject to regulation by the Federal Energy Regulatory Commission (FERC), the Nuclear Regulatory Commission (NRC) and the states in which they operate.
•
Public Service Electric and Gas Company (PSE&G)-which is an operating public utility engaged principally in the transmission of electricity and distribution of electricity and natural gas in certain areas of New Jersey. PSE&G is subject to regulation by the New Jersey Board of Public Utilities (BPU) and the FERC. PSE&G also invests in solar generation projects and has implemented energy efficiency and demand response programs, which are regulated by the BPU.
•
PSEG Energy Holdings L.L.C. (Energy Holdings)-which primarily has investments in leveraged leases and solar generation projects through its direct wholly owned subsidiaries. Certain Energy Holdings’ subsidiaries are subject to regulation by the FERC and the states in which they operate. Energy Holdings has also been awarded a contract to manage the transmission and distribution assets of the Long Island Power Authority (LIPA) starting in 2014.
•
PSEG Services Corporation (Services)-which provides management, administrative and general services to PSEG and its subsidiaries at cost.
Basis of Presentation
The respective financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (SEC) applicable to Annual Reports on Form 10-K and in accordance with accounting guidance generally accepted in the United States (GAAP).
Significant Accounting Policies
Principles of Consolidation
Each company consolidates those entities in which it has a controlling interest or is the primary beneficiary. See Note 3. Variable Interest Entities. Entities over which the companies 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 the investor is not the primary beneficiary, the cost method of accounting is applied. All significant intercompany accounts and transactions are eliminated in consolidation, except as discussed in Note 23. Related-Party Transactions.
Power and PSE&G also have undivided interests in certain jointly-owned facilities, with each responsible for paying its respective ownership share of construction costs, fuel purchases and operating expenses. Power and PSE&G consolidated their portion of any revenues and expenses related to these facilities in the appropriate revenue and expense categories.
Accounting for the Effects of Regulation
In accordance with accounting guidance for rate-regulated entities, PSE&G’s financial statements must reflect the economic effects of regulation. PSE&G 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 competitive position, the associated Regulatory Asset or Liability is charged or credited to income. Management believes that PSE&G’s transmission and distribution businesses continue to meet the accounting requirements for rate-regulated entities. For additional information, see Note 6. Regulatory Assets and Liabilities.
Derivative Financial Instruments
Each company uses derivative financial instruments to manage risk from changes in interest rates, commodity prices, congestion costs and emission credit prices, pursuant to its business plans and prudent practices.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Derivative instruments, not designated as normal purchases or sales, are recognized 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, 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, and that is designated and qualifies as, a cash flow hedge are recorded in Accumulated Other Comprehensive Income (Loss) until earnings are affected by the variability of cash flows of the hedged transaction. Any hedge ineffectiveness is included in current period earnings. For derivative contracts that do not qualify as cash flow or fair value hedges or are not designated as normal purchases or sales, changes in fair value are recorded in current period earnings.
Many non-trading contracts qualify for the normal purchases and normal sales exemption and are accounted for upon settlement.
For additional information regarding derivative financial instruments, see Note 16. Financial Risk Management Activities.
Revenue Recognition
The majority of Power’s revenues relate to bilateral contracts, which are accounted for on the accrual basis as the energy is delivered. Power’s revenue also includes changes in the value of non-trading energy derivative contracts that are not designated as normal purchases or sales or as cash flow or fair value hedges of other positions. Power records margins from energy trading on a net basis. See Note 16. Financial Risk Management Activities for further discussion.
PSE&G’s revenues are recorded based on services rendered to customers. 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.
Energy Holdings’ revenues are earned primarily from income relating to its investments in leveraged leases, which is recognized by a method which produces a constant after-tax rate of return on the outstanding 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 in Operating Revenues as these events occur in the ordinary course of business of managing the investment portfolio. See Note 7. Long-Term Investments for further discussion.
Depreciation and Amortization
Power calculates depreciation on generation-related assets under the straight-line method based on the assets’ estimated useful lives. The estimated useful lives are:
•
general plant assets-3 years to 20 years
•
fossil production assets-10 years to 79 years
•
nuclear generation assets-approximately 60 years
•
pumped storage facilities-76 years
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 or the FERC. The depreciation rate stated as a percentage of original cost of depreciable property was as follows:
Taxes Other Than Income Taxes
Excise taxes and transitional energy facilities assessment (TEFA) collected from PSE&G’s customers are presented in the financial statements on a gross basis. For the years ended December 31, 2012, 2011 and 2010, TEFA is included in the following captions in the Consolidated Statements of Operations:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Interest Capitalized During Construction (IDC) and Allowance for Funds Used During Construction (AFUDC)
IDC represents the cost of debt used to finance construction at Power and Energy Holdings. AFUDC represents the cost of debt and equity funds used to finance the construction of new utility assets at PSE&G. The amount of IDC or AFUDC capitalized as Property, Plant and Equipment is included as a reduction of interest charges or other income for the equity portion. The amounts and average rates used to calculate IDC or AFUDC for the years ended December 31, 2012, 2011 and 2010 were as follows:
Income Taxes
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 deferred in prior years are being amortized over the useful lives of the related property.
Uncertain income tax positions are accounted for using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. See Note 20. Income Taxes for further discussion.
Impairment of Long-Lived Assets
In accordance with accounting guidance, management evaluates long-lived assets for impairment whenever events or changes in circumstances, such as significant adverse changes in regulation, business climate or market conditions, could potentially indicate an asset’s or asset group’s carrying amount may not be recoverable. In such an event, an undiscounted cash flow analysis is performed to determine if an impairment exists. When a long-lived asset's carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset's fair value is less than its carrying amount. An impairment would result in a reduction of the long-lived asset value through a non-cash charge to earnings.
Cash and Cash Equivalents
Cash equivalents consist of short-term, highly liquid investments with original maturities of three months or less.
Accounts Receivable-Allowance for Doubtful Accounts
PSE&G’s accounts receivable are reported in the balance sheet as gross outstanding amounts adjusted for doubtful accounts. The allowance for doubtful accounts reflects PSE&G’s best estimates of losses on the accounts receivable balances. The allowance is based on accounts receivable aging, historical experience, write-off forecasts and other currently available evidence.
Accounts receivable are charged off in the period in which the receivable is deemed uncollectible. Recoveries of accounts receivable are recorded when it is known they will be received.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Materials and Supplies and Fuel
Materials and supplies for Power and Energy Holdings are valued at the lower of average cost or market. Fuel inventory at Power includes the weighted average costs of stored natural gas, coal, fuel oil and propane used to generate power and to satisfy obligations under Power’s gas supply contracts with PSE&G. The costs of fuel, including transportation costs, are included in inventory when purchased and charged at average cost to Energy Costs when used or sold. PSE&G’s materials and supplies are carried at average cost consistent with the rate-making process.
Restricted Funds
PSE&G’s restricted funds represent revenues collected from its retail electric customers that must be used to pay the principal, interest and other expenses associated with the securitization bonds of PSE&G Transition Funding LLC (Transition Funding) and PSE&G Transition Funding II LLC (Transition Funding II).
Property, Plant and Equipment
Power capitalizes 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 prevent future environmental contamination or if the costs improve existing assets’ environmental safety or efficiency. All other environmental expenditures are expensed as incurred.
PSE&G’s additions to and replacements of existing property, plant and equipment are capitalized at original cost. The cost of maintenance, repair and replacement of minor items of property is charged to expense as incurred. At the time units of depreciable property are retired or otherwise disposed of, the original cost, adjusted for net salvage value, is charged to accumulated depreciation.
Available-for-Sale Securities
These securities are comprised of the Nuclear Decommissioning Trust (NDT) Fund, a master independent external trust account maintained to provide for the costs of decommissioning upon termination of operations of Power’s nuclear facilities and amounts comprising Other Special Funds that are deposited to fund a Rabbi Trust which was established to meet the obligations related to non-qualified pension plans and deferred compensation plans.
Realized gains and losses on available-for-sale securities are recorded in earnings and unrealized gains and losses on such securities are recorded as a component of Accumulated Other Comprehensive Income (Loss) (except credit loss on debt securities which is recorded in earnings). Securities with unrealized losses that are deemed to be other-than-temporarily impaired are recorded in earnings. See Note 9. Available-for-Sale Securities for further discussion.
Pension and Other Postretirement Benefits (OPEB) Plan Assets
The market-related value of plan assets held for the qualified pension and OPEB plans is equal to the fair value of those assets as of year-end. Fair value is determined using quoted market prices and independent pricing services based upon the security type as reported by the trustee at the measurement dates (December 31) for all plan assets. See Note 12. Pension, OPEB and Savings Plans for further discussion.
Basis Adjustment
Power and PSE&G have recorded a Basis Adjustment in their respective Consolidated Balance Sheets related 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, 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, $986 million, net of tax, was recorded as a Basis Adjustment on Power’s and PSE&G’s Consolidated Balance Sheets. The $986 million is a reduction of Power’s Member’s Equity and an addition to PSE&G’s Common Stockholder’s Equity. These amounts are eliminated on PSEG’s consolidated financial statements.
Use of Estimates
The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions regarding certain types of assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements.
Reclassifications
During 2011, Power sold its two natural gas combined cycle power plants in Texas that were owned and operated by its subsidiary, PSEG Texas. As a result, amounts related to these plants were reclassified as Discontinued Operations in the financial statements of PSEG and Power for the years ended December 31, 2011 and 2010. See Note 4. Discontinued Operations and Dispositions.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 2. Recent Accounting Standards
New Standards Adopted during 2012
Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in GAAP and International Financial Reporting Standards (IFRS)
This accounting standard updates guidance related to fair value measurements and disclosures as a step towards achieving convergence between GAAP and IFRS. The updated guidance
•
clarifies intent about application of existing fair value measurements and disclosures,
•
changes some requirements for fair value measurements, and
•
requires expanded disclosures.
We adopted this standard prospectively effective January 1, 2012. Upon adoption there was no material impact on our consolidated financial position, results of operations or cash flows; however, it has resulted in expanded disclosures. For additional information, see Note 17. Fair Value Measurements.
Presentation of Comprehensive Income
This accounting standard addresses the presentation of comprehensive income as a step towards achieving convergence between GAAP and IFRS. The updated guidance
•
allows an entity to present components of net income and other comprehensive income in one continuous statement, referred to as the statement of comprehensive income, or in two separate, but consecutive statements, and
•
eliminates the current option to report other comprehensive income and its components in the statement of changes in equity.
We adopted this standard retrospectively effective January 1, 2012. Upon adoption of the new amended guidance, there was no impact on our consolidated financial position, results of operations or cash flows, but there was a change in the presentation of the components of other comprehensive income.
New Accounting Standards Issued But Not Yet Adopted
Disclosures about Offsetting Assets and Liabilities
This accounting standard requires balance sheet offsetting disclosures to facilitate comparability between financial statements prepared on the basis of GAAP and IFRS. This standard requires entities
•
to disclose information about offsetting and related arrangements to enable users of financial statements to understand the effect of those arrangements on an entity's financial position, and
•
to present both net (offset amounts) and gross information in the notes to the financial statements for relevant assets and liabilities that are offset.
The guidance is applicable to certain financial instruments (i.e. derivatives, repurchase agreements and reverse repurchase agreements) and securities borrowing and lending transactions. It is effective for fiscal years and interim periods beginning on or after January 1, 2013. As this standard requires disclosures only, it will not have any impact on our consolidated financial position, results of operations or cash flows.
Reclassification Adjustments out of Accumulated Other Comprehensive Income (AOCI)
This accounting standard requires entities to disclose the following information about reclassification adjustments related to AOCI:
•
changes in AOCI balances by components; and
•
significant amounts reclassified out of AOCI by respective line items of net income (for amounts that are required by GAAP to be reclassified to net income in their entirety in the same reporting period). For other types of reclassifications, reference to other note disclosures would be required.
The guidance is effective for fiscal years and interim periods beginning on or after January 1, 2013. As this standard requires disclosures only, it will not have any impact on our consolidated financial position, results of operations or cash flows.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 3. Variable Interest Entities (VIEs)
VIEs for which PSE&G is the Primary Beneficiary
PSE&G is the primary beneficiary of and consolidates two marginally capitalized VIEs, Transition Funding and Transition Funding II, which were created for the purpose of issuing transition bonds and purchasing bond transitional property of PSE&G, which is pledged as collateral to the trustee for these bonds. PSE&G acts as the servicer for these entities to collect securitization transition charges authorized by the BPU. These funds are remitted to Transition Funding and Transition Funding II and are used for interest and principal payments on the transition bonds and related costs.
The assets and liabilities of these VIEs are presented separately on the face of the Consolidated Balance Sheets of PSEG and PSE&G because the Transition Funding and Transition Funding II assets are restricted and can only be used to settle their respective obligations. The Transition Funding and Transition Funding II creditors do not have any recourse to the general credit of PSE&G in the event the transition charges are not sufficient to cover the bond principal and interest payments of Transition Funding and Transition Funding II, respectively.
PSE&G’s maximum exposure to loss is equal to its equity investment in these VIEs which was $16 million as of December 31, 2012 and 2011. PSE&G considers the risk of actual loss to be remote. PSE&G did not provide any financial support to Transition Funding or Transition Funding II in 2012 or 2011. Further, PSE&G does not have any contractual commitments or obligations to provide financial support to Transition Funding and Transition Funding II.
Note 4. Discontinued Operations and Dispositions
Discontinued Operations
Power
In March 2011, Power completed the sale of its 1,000 MW gas-fired Guadalupe generating facility for a total sale price of $352 million, resulting in an after-tax gain of $54 million.
In July 2011, Power completed the sale of its 1,000 MW gas-fired Odessa generating facility for a total sale price of $335 million, resulting in an after-tax gain of $25 million.
PSEG Texas’ operating results for years ended December 31, 2011 and 2010, which were reclassified to Discontinued Operations, are summarized below:
Dispositions
Leveraged Leases
For the year ended December 31, 2011, Energy Holdings sold its leveraged lease investment in an office building in Denver, Colorado for gross proceeds of $215 million. Proceeds net of sales costs were $175 million.
For the year ended December 31, 2010, Energy Holdings sold its interest in six leveraged leases, including five international leases.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 5. Property, Plant and Equipment and Jointly-Owned Facilities
Information related to Property, Plant and Equipment as of December 31, 2012 and 2011 is detailed below:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Power and PSE&G have ownership interests in and are responsible for providing their respective shares of the necessary financing for the following jointly-owned facilities. All amounts reflect the share of Power’s and PSE&G’s jointly-owned projects and the corresponding direct expenses are included in the Consolidated Statements of Operations as operating expenses.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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. Each owner is responsible for any financing with respect to its pro rata share of capital expenditures.
Power co-owns Salem and Peach Bottom with Exelon Generation. Power is the operator of Salem and Exelon Generation is the operator of Peach Bottom. A committee appointed by the co-owners provides oversight. Proposed Operation and Maintenance (O&M) budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process.
GenOn Northeast Management Company is a co-owner and the operator for Keystone Generating Station and Conemaugh Generating Station. A committee appointed by the co-owners provides oversight. Proposed O&M budgets and requests for major capital expenditures are reviewed and approved as part of the normal Power governance process.
Power is a co-owner in the Yards Creek Pumped Storage Generation Facility. Jersey Central Power & Light Company (JCP&L) is also a co-owner and the operator of this facility. JCP&L submits separate capital and O&M budgets, subject to Power's approval as part of the normal Power governance process.
Power is a minority owner in the Merrill Creek Reservoir and Environmental Preserve in Warren County, New Jersey. Merrill Creek Owners Group is the owner-operator of this facility. The operator submits separate capital and O&M budgets, subject to Power's approval as part of the normal Power governance process.
Note 6. Regulatory Assets and Liabilities
PSE&G prepares its financial statements in accordance with GAAP accounting for regulated utilities. 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 FERC or PSE&G’s experience with prior rate cases. Most of PSE&G’s Regulatory Assets and Liabilities as of December 31, 2012 are supported by written orders, either explicitly or implicitly through the BPU’s treatment of various cost items.
Regulatory Assets are subject to prudence reviews and 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSE&G had the following Regulatory Assets and Liabilities:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(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 Regulatory Assets and Liabilities in the table above are defined as follows:
•
Underrecovered Electric Energy Costs: These costs represent the underrecovered amounts associated with BGS, as approved by the BPU.
•
SBC: The SBC, as authorized by the BPU and the New Jersey Electric Discount and Energy Competition Act (Competition Act), includes costs related to PSE&G's electric and gas business as follows: 1) the USF; 2) Energy Efficiency and Renewable Energy Programs; 3) Social Programs (electric only) which include electric bad debt expense; and 4) the RAC for incurred MGP remediation expenditures. All components accrue interest on both over and underrecoveries.
•
RRC: These costs are amounts associated with various renewable energy and energy efficiency programs. Components of the RRC include: Carbon Abatement, Energy Efficiency Economic Stimulus Program, Energy Efficiency Economic Extension Program, the Demand Response Program, Solar Generation Investment Program (Solar 4 All) and Solar Loan II Program.
•
SPRC: This charge is designed to recover the revenue requirements associated with the PSE&G Solar Pilot Program (Solar Loan I) per the BPU Order, less the net proceeds from the sale of associated Solar Renewable Energy Certificates (SRECs) or cash received in lieu of SRECs. The net recovery is subject to deferred accounting. Interest at the two-year constant maturity treasury rate plus 60 basis points will be accrued monthly on any under- or over-recovered balances.
•
Capital Stimulus Undercollection: PSE&G has received approval from the BPU for programs that provide for accelerated investment in utility infrastructure. The goal of these accelerated capital investments is to improve the reliability of PSE&G's infrastructure and New Jersey's economy through job creation.
•
WNC Deferral: This represents the over or under collection of gas margin refundable or recoverable under the BPU's weather normalization clause. The WNC requires PSE&G to calculate, at the end of each October-to-May period, the level by which margin revenues differed from what would have resulted if normal weather had occurred.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
•
New Jersey Clean Energy Program: The BPU approved future funding requirements for Energy Efficiency and Renewable Energy Programs through the first half of 2013. Once the rates are measured, they are recovered through the SBC.
•
Stranded Costs To Be Recovered: This reflects deferred costs, which are being recovered through the securitization transition charges authorized by the BPU in irrevocable financing orders and being collected by PSE&G, as servicer on behalf of Transition Funding and Transition Funding II, respectively. Collected funds collected are remitted to Transition Funding and Transition Funding II and are used for interest and principal payments on the transition bonds and related costs and taxes.
Transition Funding and Transition Funding II are wholly owned, bankruptcy-remote subsidiaries of PSE&G that purchased certain transition property from PSE&G and issued transition bonds secured by such property. The transition property consists principally of the rights to receive electricity consumption-based per kilowatt-hour (kWh) charges from PSE&G electric distribution customers, which represent irrevocable rights to receive amounts sufficient to recover certain of PSE&G's transition costs related to deregulation, as approved by the BPU.
•
MGP Remediation Costs: Represents the low end of the range for the remaining environmental investigation and remediation program cleanup costs for manufactured gas plants that are probable of recovery in future rates. Once these costs are incurred, they are recovered through the RAC in the SBC.
•
Pension and Other Postretirement: Pursuant to the adoption of accounting guidance for employers' defined benefit pension and OPEB plans, PSE&G recorded the unrecognized costs for defined benefit pension and other OPEB plans on the balance sheet as a Regulatory Asset. These costs represent actuarial gains or losses, prior service costs and transition obligations as a result of adoption, which have not been expensed. These costs are amortized and recovered in future rates.
•
Deferred Income Taxes: These amounts represent the portion of deferred income taxes that will be recovered or refunded through future rates, based upon established regulatory practices.
•
RAC (Other SBC): Costs incurred to clean up manufactured gas plants which are recovered over seven years.
•
MTM Contracts: The estimated fair value of long-term standard offer capacity agreements (SOCAs), gas hedge contracts and gas cogeneration supply contracts. The regulatory asset/liability is offset by a derivative asset/liability and, with respect to the gas hedge contracts only, an intercompany receivable/payable on the Consolidated Balance Sheets.
•
Unamortized Loss on Reacquired Debt and Debt Expense: Represents losses on reacquired long-term debt, which are recovered through rates over the remaining life of the debt.
•
Conditional Asset Retirement Obligation: These costs represent the differences between rate regulated cost of removal accounting and asset retirement accounting under GAAP. These costs will be recovered in future rates.
•
Gas Margin Adjustment Clause: PSE&G defers the margin differential received from Transportation Gas Service Non-Firm Customers versus bill credits provided to BGSS-Firm customers.
•
Storm Damage Deferral: Costs incurred in the cleanup of 2012, 2011 and 2010 storms, as approved by the BPU under an Order received in December 2012 authorizing the deferral of incremental costs.
•
MTC Refund, net: These costs represent the overrecovered amounts associated with MTC.
•
Overrecovered Gas and Electric Costs: These costs represent the overrecovered amounts associated with BGSS and BGS, as approved by the BPU. Interest is accrued on overrecovered balances.
•
FERC Formula Rate True-up: Overcollection or undercollection of transmission earnings calculated using a FERC approved formula.
•
NGC: Represents the difference between the cost of non-utility generation and the amounts realized from selling that energy at market rates through PJM and ratepayer collections.
•
Electric Cost of Removal: PSE&G accrues and collects for cost of removal in rates. The liability for non-legally required cost of removal is classified as a Regulatory Liability. This liability is reduced as removal costs are incurred. Accumulated cost of removal is a reduction to the rate base.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Significant 2012 orders and pending rate filings are as follows:
•
Storm Damage Deferral-In December 2012, the BPU granted PSE&G's request to defer on its books actually incurred, uninsured, incremental storm restoration costs to its gas and electric distribution systems associated with extraordinary storms, including Hurricane Irene and Superstorm Sandy. In February 2013, the BPU announced that it would initiate a generic proceeding to evaluate the prudency of extraordinary, storm-related costs incurred by all of the regulated utilities as a result of the natural disasters experienced in New Jersey in 2011 and 2012 and in this proceeding will consider the manner in which such prudent costs shall be recovered.
•
Transmission Formula Rates-PSE&G's 2012 Annual Formula Rate Update with the FERC provided for approximately $94 million in increased annual transmission revenues effective January 1, 2012. PSE&G filed its 2013 Annual Formula Rate Update with FERC in October 2012, which provides for approximately $174 million in increased annual transmission revenues effective January 1, 2013.
•
SBC/NGC-In March 2012, PSE&G made an annual SBC/NGC filing requesting a $5 million electric increase and a $29 million gas increase. PSE&G updated the filing with actual data through August 31, 2012, resulting in a decrease of $77 million for electric customers while the gas increase remained unchanged. A Stipulation signed by the Parties was approved by the BPU effective February 1, 2013.
•
Universal Service Fund (USF)/Lifeline-The USF is an energy assistance program mandated by the BPU to provide payment assistance to low income customers. The Lifeline program is a separate mandated energy assistance program to provide payment assistance to elderly and disabled customers. In June 2012, New Jersey's electric and gas utilities, including PSE&G, filed requests to reset the statewide rates for the USF and the Lifeline program. The filed USF rates were set to recover approximately $230 million on a statewide basis. Of this amount, the statewide electric rates are set to recover $173 million with the remaining $57 million recovered through gas rates. The rates for the Lifeline program were set to recover $66 million, $46 million for electric and $20 million for gas. The filed rates were subsequently updated and approved effective October 1, 2012. PSE&G earns no margin on the collection of the USF and Lifeline programs resulting in no impact on Net Income.
•
Capital Infrastructure Programs (CIP I and CIP II)-In December 2012, the BPU approved stipulations regarding our CIP I and CIP II filings resulting in a combined increase of $40 million and $23 million for electric and gas customers, respectively effective January 1, 2013.
•
WNC- In June 2012, PSE&G filed a petition and testimony with the BPU, including eight months of actual and four months of forecasted data, which sought BPU approval to recover $41 million in deficiency revenues from its customers during the 2012-2013 Winter Period (October 1 to May 31) and a carryover deficiency of $16 million to the 2013-2014 Winter Period. In September 2012, an Order approving the stipulation for provisional rates was signed. In December 2012, PSE&G made a supplemental filing incorporating twelve months of actual financial data, which would, if approved by the BPU, result in no change to customer rates during the 2012-2013 Winter Period. The supplemental filing would, however, result in an increase of the carryover deficiency to the 2013-2014 Winter Period from $16 million to $24 million. PSE&G is awaiting a final Order.
•
RAC-In November 2011, PSE&G filed a RAC 19 petition with the BPU requesting a decrease in electric and gas RAC revenues on an annual basis of $9 million and $10 million, respectively. In October 2012, PSE&G received the Administrative Law Judge's (ALJ) Initial Decision allowing full recovery of RAC 19 costs including costs of the Passaic River and Newark Bay Superfund (CERCLA) matters and the Occidental litigation that were allocated to PSE&G and included in this request. In October 2012, the BPU issued a final Order approving the ALJ's Initial Decision.
•
RRC-In July 2012, PSE&G filed a petition with the BPU requesting an increase in the RRC seeking to recover approximately $62 million in electric revenue and $8 million in gas revenue on an annual basis. The discovery phase of this proceeding is underway.
•
SPRC-In July 2012, the BPU approved a Stipulation regarding our March 2010 SPRC (Solar Loan I) filing authorizing an increase in rates of $3 million for PSE&G's electric customers effective August 1, 2012. In July 2012, PSE&G filed a petition with the BPU for an annual increase in the electric SPRC of $17 million. The discovery phase of this proceeding is underway.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 7. Long-Term Investments
Long-Term Investments as of December 31, 2012 and 2011 included the following:
(A)
During the three years ended December 31, 2012, 2011 and 2010, the amount of dividends from these investments was $17 million, $3 million and $5 million, respectively. Energy Holdings’ share of income and cash flow distribution percentages were at 50% as of December 31, 2012.
(B)
Reflects Energy Holdings' investments in certain companies in which it does not have the ability to exercise significant influence. Such investments are accounted for under the cost method.
Leases
Energy Holdings has investments in domestic energy and real estate assets subject primarily to leveraged lease accounting. A leveraged lease is typically comprised of an investment by an equity investor and debt provided by a third party debt investor. The debt is recourse only to the assets subject to lease and is not included on PSEG’s Consolidated Balance Sheets. As an equity investor, Energy Holdings’ equity investments in the leases are comprised of the total expected lease receivables over the lease terms plus the estimated residual values at the end of the lease terms, reduced for any income not yet earned on the leases. This amount is included in Long-Term Investments on PSEG’s Consolidated Balance Sheets. The more rapid depreciation of the leased property for tax purposes creates tax cash flow that will be repaid to the taxing authority in later periods. As such, the liability for such taxes due is recorded in Deferred Income Taxes on PSEG’s Consolidated Balance Sheets. The following table shows Energy Holdings’ gross and net lease investment as of December 31, 2012 and 2011, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The pre-tax income and income tax effects, excluding gains and losses on sales, related to investments in leases were as follows:
Equity Method Investments
Power and Energy Holdings had the following equity method investments as of December 31, 2012:
Note 8. Financing Receivables
PSE&G
PSE&G sponsors a solar loan program designed to help finance the installation of solar power systems throughout its electric service area. The loans are generally paid back with SRECS generated from the installed solar electric system. The following table reflects the outstanding short and long-term loans by class of customer, none of which would be considered “non-performing.”
Energy Holdings
Energy Holdings had a net investment in domestic energy and real estate assets subject primarily to leveraged lease accounting of $117 million and $165 million as of December 31, 2012 and 2011, respectively (See Note 7. Long-Term Investments).
The corresponding receivables associated with the lease portfolio are reflected below, net of non-recourse debt. The ratings in the table represent the ratings of the entities providing payment assurance to Energy Holdings. “Not Rated” counterparties relate to investments in leases of commercial real estate properties.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The “B” and “D” ratings above represent lease receivables related to coal-fired assets in Illinois and Pennsylvania. As of December 31, 2012, the gross investment in the leases of such assets, net of non-recourse debt, was $559 million ($19 million, net of deferred taxes). A more detailed description of such assets under lease is presented in the following table.
The credit exposure for lessors is partially mitigated through various credit enhancement mechanisms within the lease transactions. These credit enhancement features vary from lease to lease and may include letters of credit or affiliate guarantees. Upon the occurrence of certain defaults, indirect subsidiary companies of Energy Holdings would exercise their rights and attempt to seek recovery of their investment, potentially including stepping into the lease directly to protect their investments. While these actions could ultimately protect or mitigate the loss of value, they could require the use of significant capital investments and trigger certain material tax obligations. A bankruptcy of a lessee would likely delay any efforts on the part of the lessors to assert their rights upon default and could delay the monetization of claims. Failure to recover adequate value could ultimately lead to a foreclosure on the lease by the lenders. If foreclosures were to occur, Energy Holdings could potentially record a pre-tax write-off up to its gross investment in these facilities and may also be required to pay significant cash tax liabilities.
Of facilities under lease by indirect subsidiary companies of Energy Holdings to GenOn REMA, LLC (GenOn REMA), a subsidiary of GenOn Energy Inc. (GenOn), which was acquired by NRG Energy, Inc. in December 2012. Keystone has installed flue gas desulfurization control for sulfur dioxide (SO2), selective catalytic reduction (SCR) equipment for nitrogen oxide (NOx) and mercury control to meet current environmental requirements. Conemaugh has flue gas desulfurization control, while SCR and mercury control are scheduled to be installed and operational in the first quarter of 2015. GenOn's plan for the coal-fired units at the Shawville facility is to place them in a “long-term protective layup” by April 2015 while continuing to pay the required rent and maintaining the facility in accordance with the lease terms or terminating the lease for obsolescence in which case the lessee would be required, among other things, to pay the contractual termination value structured to recover Energy Holdings' indirect subsidiaries' lease investment as specified in the lease agreement.
Although all lease payments from the GenOn REMA leases are current, no assurances can be given that future payments in accordance with the lease contracts will continue. Factors which may impact future lease cash flows include, but are not limited
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
to, new environmental legislation and regulation regarding air quality, water and other discharges in the process of generating electricity, market prices for fuel and electricity, overall financial condition of lease counterparties and the quality and condition of assets under lease.
With respect to Edison Mission Energy's (EME) Midwest Generation (MWG) leases on the Powerton and Joliet coal units in Illinois, the lessee, MWG, substantially completed investments in mercury removal (Activated Carbon Injection) and NOx emission controls (low NOx burners and Selective Non-Catalytic Reduction systems), and plans to invest in SO2 emission controls (Dry Sorbent Injection (Trona) systems). EME does not anticipate a material change in this current approach in order to comply with existing federal and Illinois environmental rules. On November 30, 2012, MWG filed a variance request with the Illinois Pollution Control Board seeking two additional years to meet upcoming air emission compliance deadlines under Illinois law. EME and MWG remain in litigation with the U.S. Environmental Protection Agency (EPA) and the State of Illinois regarding certain air emissions. On March 16, 2011, the federal district court dismissed new source review claims in reference to Powerton and Joliet, but certain opacity claims remain pending against MWG. The EPA and the State of Illinois have appealed the dismissal of the new source review claims. On November 11, 2011, the federal district court stayed proceedings in connection with the opacity claims until the appeal by the EPA and the State of Illinois is resolved.
On December 17, 2012, EME and MWG filed for relief under Chapter 11 of the U.S. Bankruptcy Code. Immediately prior to that filing, EME, MWG, Nesbitt Asset Recovery, LLC (which is an indirect, wholly owned subsidiary of Energy Holdings), and Associates Capital Investments, L.L.P., as well as certain affiliated owner lessors and owner participants, entered into a forbearance agreement with holders of a majority of the lease debt that financed the original sale-leaseback transaction. The forbearance agreement, which was approved by the bankruptcy court and limited the ability of the lease indenture trustee to accelerate or exercise other remedies with respect to that nonrecourse debt, expired on February 15, 2013. A new forbearance agreement is currently being negotiated by the parties. MWG has not determined whether to assume or reject those leases. MWG did not make its scheduled rent payments (which related to the prior six month period) totaling approximately $48 million on the Powerton and Joliet leases due on January 2, 2013, most of which is a pre-petition bankruptcy claim. Rental for the utilization of the facilities by MWG during pendency of the bankruptcy will likely be treated as an administrative expense in bankruptcy. In mid-February, pursuant to the terms of the forbearance agreement, a rental payment of approximately $5 million was received covering the period from the date of the petition filing through January 2, 2013.
On December 13, 2011, indirect subsidiary companies of Energy Holdings and Dynegy Incorporated (Dynegy) reached a settlement agreement resolving disputes that had arisen between them with regard to Dynegy Holding’s (DH) rejection of the Dynegy leases. The settlement agreement resolved certain disputes regarding Energy Holdings' Dynegy leases, including claims under Tax Indemnity Agreements that indirect subsidiaries of Energy Holdings have with DH. The original terms of the settlement agreement included a cash payment to Energy Holdings of $7.5 million, which was received on January 4, 2012, and an allowed claim in Bankruptcy Court of $110 million against DH. On December 30, 2011, the effective date of the court order authorizing the Dynegy lease rejections, the leases no longer qualified for leveraged lease accounting treatment under GAAP. As a result, Energy Holdings wrote off the $264 million gross lease investment against the previously recorded reserve. The Energy Holdings' indirect subsidiary companies that are owners/lessors of the two plants ceased leveraged lease accounting and recorded the generation assets and related nonrecourse project debt on their balance sheets at their respective fair values (See Note 17. Fair Value Measurements).
On June 1, 2012, an amended and restated settlement agreement entered into by DH, Dynegy and their creditors (including indirect subsidiary companies of Energy Holdings) was approved by the Bankruptcy Court. The agreement allocated proceeds from the sale of the facilities to pay DH’s creditors, including the lease bondholders, and grants the lease bondholders claims in agreed upon amounts against DH in its bankruptcy proceedings. The settlement agreement also included an exchange of releases by various settling claimants, including parties to the leases with respect to claims arising out of the leases. On October 1, 2012, Dynegy emerged from bankruptcy and distributed cash and stock settlements to the claimants. The total recovery of Energy Holdings' indirect subsidiary companies from the Dynegy leases was approximately $63 million, of which $50 million was recorded in Operating Revenues in the fourth quarter of 2012.
Note 9. Available-for-Sale Securities
NDT Fund
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. Power is required to file periodic reports with the NRC demonstrating that the NDT Fund meets the formula-based minimum NRC funding requirements.
Power maintains an external master NDT to fund its share of decommissioning for its five nuclear facilities upon their respective termination of operation. The trust contains two separate funds: a qualified fund and a non-qualified fund.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Section 468A of the Internal Revenue Code limits the amount of money that can be contributed into a qualified fund. Power’s share of decommissioning costs related to its five nuclear units was estimated to be between $2.2 billion and $2.4 billion, including contingencies. The liability for decommissioning recorded on a discounted basis as of December 31, 2012 was approximately $348 million and is included in the Asset Retirement Obligation. The trust funds are managed by third-party investment advisors who operate under investment guidelines developed by Power. In September 2012, Power revised the asset structure for a portion of its NDT Fund and realized gains of $59 million. The investments were transitioned to new investment managers to remove under-performing managers.
Power classifies investments in the NDT Fund as available-for-sale. The following tables show the fair values and gross unrealized gains and losses for the securities held in the NDT Fund:
These amounts do not include receivables and payables for NDT Fund transactions which have not settled at the end of each period. Such amounts are included in Accounts Receivable and Accounts Payable on the Consolidated Balance Sheets as shown in the following table.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table shows the value of securities in the NDT Fund that have been in an unrealized loss position for less than 12 months and greater than 12 months:
(A)
Equity Securities-Investments in marketable equity securities within the NDT Fund are primarily in common stocks within a broad range of industries and sectors. The unrealized losses are distributed over hundreds of companies with limited impairment durations. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2012.
(B)
Debt Securities (Government)-Unrealized losses on Power’s NDT investments in United States Treasury obligations and Federal Agency mortgage-backed securities were caused by interest rate changes. Since these investments are guaranteed by the United States government or an agency of the United States government, it is not expected that these securities will settle for less than their amortized cost basis, since Power does not intend to sell nor will it be more-likely-than-not required to sell. Power does not consider these securities to be other-than-temporarily impaired as of December 31, 2012.
(C)
Debt Securities (Corporate)-Power’s investments in corporate bonds are primarily in investment grade securities. It is not expected that these securities would settle for less than their amortized cost. Since Power does not intend to sell these securities nor will it be more-likely-than-not required to sell, Power does not consider these debt securities to be other-than-temporarily impaired as of December 31, 2012.
The proceeds from the sales of and the net realized gains on securities in the NDT Fund were:
Net realized gains disclosed in the above table were recognized in Other Income and Other Deductions in PSEG’s and Power’s Consolidated Statements of Operations. Net unrealized gains of $84 million (after-tax) are included in Accumulated Other Comprehensive Loss on Power’s Consolidated Balance Sheet as of December 31, 2012.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The available-for-sale debt securities held as of December 31, 2012 had the following maturities:
The cost of these securities was determined on the basis of specific identification.
Power periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, management considers the ability and intent to hold for a reasonable time to permit recovery in addition to the severity and duration of the loss. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). In 2012, other-than-temporary impairments of $18 million were recognized on securities in the NDT Fund. Any subsequent recoveries in the value of these securities would be recognized in Accumulated Other Comprehensive Income (Loss) unless the securities are sold, in which case, any gain would be recognized in income. The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities.
Rabbi Trust
PSEG maintains certain unfunded nonqualified benefit plans to provide supplemental retirement and deferred compensation benefits to certain key employees. Certain assets related to these plans have been set aside in a grantor trust commonly known as a “Rabbi Trust.”
In March 2012, PSEG restructured the fixed income component of its Rabbi Trust and realized a gain of $5 million. In August 2010, PSEG revised the asset structure of the Rabbi Trust and realized gains of approximately $31 million as the investments were transitioned to a new asset allocation and investment manager.
PSEG classifies investments in the Rabbi Trust as available-for-sale. The following tables show the fair values, gross unrealized gains and losses and amortized cost bases for the securities held in the Rabbi Trust.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of December 31, 2012, amounts in the above table do not include Accounts Receivable of $4 million and Accounts Payable of $5 million for Rabbi Trust Fund transactions which had not yet settled. These amounts are included on the Consolidated Balance Sheets.
Gross realized gains disclosed in the above table were recognized in Other Income in the Consolidated Statements of Operations. Net unrealized gains of $6 million (after-tax) were recognized in Accumulated Other Comprehensive Loss on the Consolidated Balance Sheets as of December 31, 2012. The Rabbi Trust available-for-sale debt securities held as of December 31, 2012 had the following maturities:
The cost of these securities was determined on the basis of specific identification.
PSEG periodically assesses individual securities whose fair value is less than amortized cost to determine whether the investments are considered to be other-than-temporarily impaired. For equity securities, the Rabbi Trust is invested in a commingled indexed mutual fund. Due to the commingled nature of this fund, PSEG does not have the ability to hold these securities until expected recovery. As a result, any declines in fair market value below cost are recorded as a charge to earnings. For fixed income securities, management considers its intent to sell or requirement to sell a security prior to expected recovery. In those cases where a sale is expected, any impairment would be recorded through earnings. For fixed income securities where there is no intent to sell or likely requirement to sell, management evaluates whether credit loss is a component of the impairment. If so, that portion is recorded through earnings while the noncredit loss component is recorded through Accumulated Other Comprehensive Income (Loss). The assessment of fair market value compared to cost is applied on a weighted average basis taking into account various purchase dates and initial cost of the securities. In 2012, there were no other-than-temporary impairments recognized on investments of the Rabbi Trust.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The fair value of the Rabbi Trust related to PSEG, Power and PSE&G are detailed as follows:
Note 10. Goodwill and Other Intangibles
As of each of December 31, 2012 and 2011, Power had goodwill of $16 million related to the Bethlehem Energy Center. Power conducted an annual review for goodwill impairment as of October 31, 2012 and concluded that goodwill was not impaired. No events occurred subsequent to that date which would require a further review of goodwill for impairment.
In addition to goodwill, as of December 31, 2012 and 2011, Power had intangible assets of $34 million and $131 million, respectively, related to emissions allowances and renewable energy credits. Emissions expense includes impairments of emissions allowances and costs for emissions, which is recorded as emissions occur. As load is served under contracts requiring energy from renewable sources, the related expense is recorded. Such expenses for the years ended December 31, 2012, 2011 and 2010 were as follows:
Note 11. Asset Retirement Obligations (AROs)
PSEG, Power and PSE&G have recorded various AROs which represent legal obligations to remove or dispose of an asset or some component of an asset at retirement.
Power’s ARO liability primarily relates to the decommissioning of its nuclear power plants in accordance with NRC requirements. To estimate this decommissioning obligation related to its nuclear power plants, Power uses a probability weighted, discounted cash flow model which, on a unit by unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning studies, cost escalation rates, inflation rates and discount rates. Power has an independent external trust that is intended to fund decommissioning of its nuclear facilities upon termination of operation. For additional information, see Note 9. Available-for-Sale Securities. Power also identified conditional AROs primarily related to Power’s fossil generation units, including liabilities for
•
removal of asbestos, stored hazardous liquid material and underground storage tanks from industrial power sites,
•
restoration of leased office space to rentable condition upon lease termination,
•
permits and authorizations,
•
restoration of an area occupied by a reservoir when the reservoir is no longer needed, and
•
demolition of certain plants, and the restoration of the sites at which they reside, when the plants are no longer in service.
PSE&G has a conditional ARO for legal obligations related to the removal of asbestos and underground storage tanks at certain industrial establishments, removal of wood poles, leases and licenses, removal of solar panels from leased property and the requirement to seal natural gas pipelines at all sources of gas when the pipelines are no longer in service. PSE&G did not record an ARO for its protected steel and poly-based natural gas transmission lines, as management believes that these categories of transmission lines have an indeterminable life.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The changes to the ARO liabilities for PSEG, Power and PSE&G during 2011 and 2012 are presented in the following table:
(A)
Not reflected as expense in Consolidated Statements of Operations
During 2012, Power recorded an increase in its ARO liabilities, primarily due to an increase in the estimated cost to decommission its nuclear power plants and increased accretion. The increase in the estimated costs to decommission Power's nuclear plants resulted primarily from the receipt of updated decommissioning cost studies in 2012 and the impact of lower discount rates. This change in the ARO did not result in any material impact in Power's Consolidated Statement of Operations.
Note 12. Pension, OPEB and Savings Plans
PSEG sponsors several qualified and nonqualified pension plans and OPEB plans covering PSEG’s and its participating affiliates’ current and former employees who meet certain eligibility criteria. Eligible employees of Power, PSE&G, Energy Holdings and Services 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 below.
PSEG, Power and PSE&G are required to record the under or over funded positions of their defined benefit pension and OPEB plans on their respective balance sheets. Such funding positions of each PSEG company are required to be measured as of the date of its respective year-end Consolidated Balance Sheets. For under funded plans, the liability is equal to the difference between the plan’s benefit obligation and the fair value of plan assets. For defined benefit pension plans, the benefit obligation is the projected benefit obligation. For OPEB plans, the benefit obligation is the accumulated postretirement benefit obligation. In addition, accounting guidance requires that the total unrecognized costs for defined benefit pension and OPEB plans be recorded as an after-tax charge to Accumulated Other Comprehensive Income (Loss), a separate component of Stockholders’ Equity. However, for PSE&G, because the amortization of the unrecognized costs is being collected from customers, the accumulated unrecognized costs are recorded as a Regulatory Asset. The unrecognized costs represent actuarial gains or losses, prior service costs and transition obligations arising from the adoption of the revised accounting guidance for pensions and OPEB, which had not been expensed.
For Power, the charge to Accumulated Other Comprehensive Income (Loss) is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations. For PSE&G, the Regulatory Asset is amortized and recorded as net periodic pension cost in the Consolidated Statements of Operations.
The following table provides a roll-forward of the changes in the benefit obligation and the fair value of plan assets during each of the two years in the periods ended December 31, 2012 and 2011. It also provides the funded status of the plans and the amounts recognized and amounts not recognized on the Consolidated Balance Sheets at the end of both years.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(A)
Includes $827 million ($485 million, after-tax) and $745 million ($438 million, after-tax) in Accumulated Other Comprehensive Loss related to Pension and OPEB as of December 31, 2012 and 2011, respectively.
The pension benefits table above provides information relating to the funded status of all qualified and nonqualified pension plans and OPEB plans on an aggregate basis. As of December 31, 2012, PSEG had funded approximately 83% of its projected benefit obligation. This percentage does not include $185 million of assets in the Rabbi Trust as of December 31, 2012, which are used to partially fund the nonqualified pension plans. The fair values of the Rabbi Trust assets are included in the Consolidated Balance Sheets.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Accumulated Benefit Obligation
The accumulated benefit obligation for all PSEG’s defined benefit pension plans was $4.9 billion as of December 31, 2012 and $4.3 billion as of December 31, 2011.
The following table provides the components of net periodic benefit cost for the years ended December 31, 2012, 2011 and 2010.
Pension costs and OPEB costs for PSEG, Power and PSE&G are detailed as follows:
The following table provides the pre-tax changes recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Deferred Assets:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Amounts that are expected to be amortized from Accumulated Other Comprehensive Loss, Regulatory Assets and Deferred Assets into Net Periodic Benefit Cost in 2013 are as follows:
The following assumptions were used to determine the benefit obligations and net periodic benefit costs:
Plan Assets
All the investments of pension plans and OPEB plans are held in a trust account by the trustee and consist of an undivided interest in an investment account of the Master Trust. The investments in the pension and OPEB plans are measured at fair value within a hierarchy that prioritizes the inputs to fair value measurements into three levels. See Note 17. Fair Value Measurements for more information on fair value guidance. Use of the Master Trust permits the commingling of pension plan assets and OPEB plan assets for investment and administrative purposes. Although assets of both plans are commingled in the Master Trust, the Trustee maintains supporting records for the purpose of allocating the net gain or loss of the investment account to the respective participating plans. The net investment income of the investment assets is allocated by the Trustee to each participating plan based on the relationship of the interest of each plan to the total of the interests of the participating
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
plans. As of December 31, 2012, the pension plan interest and OPEB plan interest in such assets of the Master Trust were approximately 94% and 6%, respectively.
The following tables present information about the investments measured at fair value on a recurring basis as of December 31, 2012 and 2011, including the fair value measurements and the levels of inputs used in determining those fair values.
(A)
Certain temporary investment funds are valued using inputs such as time-to-maturity, coupon rate, quality rating and current yield (primarily Level 2).
(B)
Wherever possible, fair values of equity investments in stocks and in commingled funds are derived from quoted market prices as substantially all of these instruments have active markets (primarily Level 1). Most investments in stocks are priced utilizing the principal market close price or in some cases midpoint, bid or ask price.
(C)
Investments in fixed income securities including bond funds are priced using an evaluated pricing approach or the most recent exchange or quoted bid (primarily Level 2).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(D)
The fair value of real estate investments is based on annual independent appraisals. The investments are also valued internally every quarter by the investment managers based on significant changes in property operations and market conditions (primarily Level 3).
(E)
Limited partnership interests in private equity funds are valued using significant unobservable inputs as there is little, if any, market activity. In addition, there may be transfer restrictions on private equity securities. The process for determining the fair value of such securities relied on commonly accepted valuation techniques, including the use of earnings multiples based on comparable public securities, industry-specific non-earnings-based multiples and discounted cash flow models. These inputs require significant management judgment or estimation (primarily Level 3).
Reconciliations of the beginning and ending balances of the Pension and OPEB Plans’ Level 3 assets for the years ended December 31, 2012 and 2011 follow:
(A)
During the year ended December 31, 2011, $23 million of the temporary investment funds in the Pension and OPEB Fund were transferred from Level 3 to Level 2, due to more observable pricing for the underlying securities. As per PSEG’s policy, this transfer was recognized as of the beginning of the first quarter (i.e. the quarter in which the transfer occurred).
The following table provides the percentage of fair value of total plan assets for each major category of plan assets held for the qualified pension and OPEB plans as of the measurement date, December 31:
PSEG utilizes forecasted returns, risk, and correlation of all asset classes in order to develop a portfolio designed to produce the maximum return opportunity per unit of risk. In 2011, PSEG completed its latest asset/liability study. The results from the study indicated that a long-term target asset allocation of 70% equities and 30% fixed income is consistent with the funds’ financial objectives. Derivative financial instruments are used by the plans’ investment managers primarily to rebalance the fixed
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
income/equity allocation of the portfolio and hedge the currency risk component of foreign investments. The expected long-term rate of return on plan assets was 8.00% as of December 31, 2012 and will remain unchanged for 2013. This expected return was determined based on the study discussed above and considered the plans’ historical annualized rate of return since inception, which was an annualized return of 9.3%.
Plan Contributions
PSEG may contribute up to $145 million into its pension plans and $14 million into its OPEB plan for calendar year 2013.
Estimated Future Benefit Payments
The following pension benefit and postretirement benefit payments are expected to be paid to plan participants.
401(k) Plans
PSEG sponsors two 401(k) plans, which are Employee Retirement Income Security Act defined contribution retirement plans. Eligible represented employees of PSEG's subsidiaries participate in the PSEG Employee Savings Plan (Savings Plan), while eligible non-represented employees of PSEG's subsidiaries 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. PSEG matches 50% of such employee contributions up to 7% of pay for Savings Plan participants and up to 8% of pay for Thrift Plan participants.
The amount paid for employer matching contributions to the plans for PSEG, Power and PSE&G are detailed as follows:
Note 13. Commitments and Contingent Liabilities
Guaranteed Obligations
Power’s activities primarily involve the purchase and sale of energy and related products under transportation, physical, financial and forward contracts at fixed and variable prices. These transactions are with numerous counterparties and brokers that may require cash, cash-related instruments or guarantees.
Power has unconditionally guaranteed payments to counterparties by its subsidiaries in commodity-related transactions in order to
•
support current exposure, interest and other costs on sums due and payable in the ordinary course of business, and
•
obtain credit.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Under these agreements, guarantees cover lines of credit between entities and are often reciprocal in nature. The exposure between counterparties can move in either direction.
In order for Power to incur a liability for the face value of the outstanding guarantees, its subsidiaries would have to
•
fully utilize the credit granted to them by every counterparty to whom Power has provided a guarantee, and
•
all of the related contracts would have to be “out-of-the-money” (if the contracts are terminated, Power would owe money to the counterparties).
Power believes the probability of this result is unlikely. For this reason, Power believes that the current exposure at any point in time is a more meaningful representation of the potential liability under these guarantees. This current exposure consists of the net of accounts receivable and accounts payable and the forward value on open positions, less any collateral posted.
Power is subject to
•
counterparty collateral calls related to commodity contracts, and
•
certain creditworthiness standards as guarantor under performance guarantees of its subsidiaries.
Changes in commodity prices can have a material impact on collateral requirements under such contracts, which are posted and received primarily in the form of cash and letters of credit. Power also routinely enters into futures and options transactions for electricity and natural gas as part of its operations. These futures contracts usually require a cash margin deposit with brokers, which can change based on market movement and in accordance with exchange rules.
In addition to the guarantees discussed above, Power has also provided payment guarantees to third parties on behalf of its affiliated companies. These guarantees support various other non-commodity related contractual obligations.
The face value of outstanding guarantees, current exposure and margin positions as of December 31, 2012 and 2011 are shown below:
As part of determining credit exposure, Power nets receivables and payables with the corresponding net energy contract balances. See Note 16. Financial Risk Management Activities for further discussion. In accordance with PSEG's accounting policy, where it is applicable, cash (received)/deposited is allocated against derivative asset and liability positions with the same counterparty on the face of the Balance Sheet. The remaining balances of net cash (received)/deposited after allocation are generally included in Accounts Payable and Receivable, respectively.
In the event of a deterioration of Power’s credit rating to below investment grade, which would represent a two level downgrade from its current S&P ratings or a three level downgrade from its current Moody’s and Fitch ratings, many of these agreements allow the counterparty to demand further performance assurance. See table above.
During 2012, the SEC and the Commodity Futures Trading Commission (CFTC) continued efforts to implement new rules to enact stricter regulation over swaps and derivatives. The CFTC has issued Final Rules regarding the definition of a swap dealer
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
and the definition of a swap. However, in September 2012, a federal court vacated the CFTC's rule on monitoring of position limits for several commodities, including natural gas, thereby indefinitely delaying the effectiveness of these position limits rules. The CFTC has appealed the court's decision to vacate the position limits rules. PSEG is carefully monitoring all of these new rules as they are issued to analyze the potential impact on its swap and derivatives transactions, including any potential increase in its collateral requirements.
In addition to amounts for outstanding guarantees, current exposure and margin positions, Power had posted letters of credit to support various other non-energy contractual and environmental obligations. See table above.
Environmental Matters
Passaic River
Historic operations of PSEG companies and the operations of hundreds of other companies along the Passaic and Hackensack Rivers are alleged by Federal and State agencies to have discharged substantial contamination into the Passaic River/Newark Bay Complex.
Federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA)
The EPA has determined that an eight-mile stretch of the Passaic River in the area of Newark, New Jersey is a “facility” within the meaning of that term under CERCLA. The EPA has determined the need to perform a study of the entire 17-mile tidal reach of the lower Passaic River.
PSE&G and certain of its predecessors conducted operations at properties in this area on or adjacent to the Passaic River. The properties included one operating electric generating station (Essex Site), which was transferred to Power, one former generating station and four former manufactured gas plant (MGP) sites. When the Essex Site was transferred from PSE&G to Power, PSE&G obtained releases and indemnities for liabilities arising out of the former Essex generating station and Power assumed any environmental liabilities.
The EPA believes that certain hazardous substances were released from the Essex Site and one of PSE&G’s former MGP locations (Harrison Site). In 2006, the EPA notified the potentially responsible parties (PRPs) that the cost of its Remedial Investigation and Feasibility Study (RI/FS) would greatly exceed the original estimated cost of $20 million. The total cost of the RI/FS is now estimated at approximately $110 million. Seventy-three PRPs, including Power and PSE&G, agreed to assume responsibility for the RI/FS and formed the Cooperating Parties Group (CPG) to divide the associated costs according to a mutually agreed upon formula. The CPG group, currently 70 members, is presently executing the RI/FS. Approximately five percent of the RI/FS costs are attributable to PSE&G’s former MGP sites and approximately one percent to Power’s generating stations. Power has provided notice to insurers concerning this potential claim.
In 2007, the EPA released a draft “Focused Feasibility Study” (FFS) that proposed six options to address the contamination cleanup of the lower eight miles of the Passaic River. The EPA estimated costs for the proposed remedy range from $1.3 billion to $3.7 billion. The work contemplated by the FFS is not subject to the cost sharing agreement discussed above. The EPA's revised proposed FFS may be released for public comment as early as April 2013.
In June 2008, an agreement was announced between the EPA and Tierra Solutions, Inc. and Maxus Energy Corporation (Tierra/Maxus) for removal of a portion of the contaminated sediment in the Passaic River at an estimated cost of $80 million. Phase I of the removal work has been completed. Phase II is contingent on the approval of an appropriate sediment disposal facility. Tierra/Maxus have reserved their rights to seek contribution for the removal costs from the other PRPs, including Power and PSE&G.
The EPA has advised that the levels of contaminants at Passaic River mile 10.9 will require removal in advance of the completion of the RI/FS. The CPG members, with the exception of Tierra/Maxus, which are no longer members, have agreed to fund the removal, currently estimated at approximately $30 million. PSEG’s share of that effort is approximately three percent.
Except for the Passaic River 10.9 mile removal, Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to the Passaic River matters.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
New Jersey Spill Compensation and Control Act (Spill Act)
In 2005, the New Jersey Department of Environmental Protection (NJDEP) filed suit against a PRP and its related companies in the New Jersey Superior Court seeking damages and reimbursement for costs expended by the State of New Jersey to address the effects of the PRP’s discharge of hazardous substances into both the Passaic River and the balance of the Newark Bay Complex. Power and PSE&G are alleged to have owned, operated or contributed hazardous substances to a total of 11 sites or facilities that impacted these water bodies. In February 2009, third party complaints were filed against some 320 third party defendants, including Power and PSE&G, claiming that each of the third party defendants is responsible for its proportionate share of the clean-up costs for the hazardous substances it allegedly discharged into the Passaic River and the Newark Bay Complex. The third party complaints seek statutory contribution and contribution under the Spill Act to recover past and future removal costs and damages. Power and PSE&G filed answers to the complaints in June 2010. A special master for discovery has been appointed by the court and document production has commenced. In October 2012, the Court issued a 90 day stay of discovery for the third party defendants to explore a possible settlement of this matter with the State of New Jersey. The original stay has been extended, most recently until March 23, 2013, and is likely to be extended again, to permit the parties to continue forward with a settlement process. Power and PSE&G believe they have good and valid defenses to the allegations contained in the third party complaints and will vigorously assert those defenses. Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to this matter.
Natural Resource Damage Claims
In 2003, the NJDEP directed PSEG, PSE&G and 56 other 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 Spill Act. The NJDEP alleged that hazardous substances had been discharged from the Essex Site and the Harrison Site. The NJDEP estimated the cost of interim natural resource injury restoration activities along the lower Passaic River at approximately $950 million. In 2007, agencies of the United States Department of Commerce and the United States Department of the Interior sent letters to PSE&G and other PRPs inviting participation in an assessment of injuries to natural resources that the agencies intended to perform. In 2008, PSEG and a number of other PRPs agreed to share certain immaterial costs the trustees have incurred and will incur going forward, and to work with the trustees to explore whether some or all of the trustees’ claims can be resolved in a cooperative fashion. That effort is continuing. PSE&G is unable to estimate its portion of the possible loss or range of loss related to this matter.
Newark Bay Study Area
The EPA has established the Newark Bay Study Area, which it defines as Newark Bay and portions of the Hackensack River, the Arthur Kill and the Kill Van Kull. In August 2006, the EPA sent PSEG and 11 other entities notices that it considered each of the entities to be a PRP with respect to contamination in the Study Area. The notice letter requested that the PRPs fund an EPA-approved study in the Newark Bay Study Area and encouraged the PRPs to contact Occidental Chemical Corporation (OCC) to discuss participating in the Remedial Investigation/Feasibility Study that OCC was conducting. The notice stated the EPA’s belief that hazardous substances were released from sites owned by PSEG companies and located on the Hackensack River, including two operating electric generating stations (Hudson and Kearny sites) and one former MGP site. PSEG has participated in and partially funded the second phase of this study. Notices to fund the next phase of the study have been received but it is uncertain at this time whether the PSEG companies will consent to fund the third phase. Power and PSE&G are unable to estimate their portion of the possible loss or range of loss related to this matter.
MGP Remediation Program
PSE&G is working with the NJDEP to assess, investigate and remediate environmental conditions at its former MGP sites. To date, 38 sites requiring some level of remedial action have been identified. Based on its current studies, PSE&G has determined that the estimated cost to remediate all MGP sites to completion could range between $588 million and $675 million through 2021. Since no amount within the range is considered to be most likely, PSE&G has recorded a liability of $588 million as of December 31, 2012. Of this amount, $113 million was recorded in Other Current Liabilities and $475 million was reflected as Environmental Costs in Noncurrent Liabilities. PSE&G has recorded a $588 million Regulatory Asset with respect to these costs. PSE&G periodically updates its studies taking into account any new regulations or new information which could impact future remediation costs and adjusts its recorded liability accordingly.
Prevention of Significant Deterioration (PSD)/New Source Review (NSR)
The PSD/NSR regulations, promulgated under the Clean Air Act (CAA), 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 may order companies that are not in compliance with the PSD/NSR regulations to install the best available control technology at the affected plants and to pay monetary penalties ranging from $25,000 to $37,500 per day for each violation, depending upon when the alleged violation occurred.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In 2009, the EPA issued a notice of violation to Power and the other owners of the Keystone coal-fired plant in Pennsylvania, alleging, among other things, that various capital improvement projects were completed at the plant which are considered modifications (or major modifications) causing significant net emission increases of PSD/NSR air pollutants, beginning in 1985 for Keystone Unit 1 and in 1984 for Keystone Unit 2. The notice of violation states that none of these modifications underwent PSD/NSR permitting process prior to being put into service, which the EPA alleges was required under the CAA. The notice of violation states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties. Power owns approximately 23% of the plant. Power cannot predict the outcome of this matter.
Hazardous Air Pollutants Regulation
In accordance with a ruling of the U.S. Court of Appeals of the District of Columbia (Court of Appeals), the EPA published a Maximum Achievable Control Technology (MACT) regulation on February 16, 2012. These Mercury Air Toxics Standards (MATS) are scheduled to go into effect on April 16, 2015 and establish allowable emission levels for mercury as well as other hazardous air pollutants pursuant to the CAA. In February 2012, members of the electric generating industry filed a petition challenging the existing source National Emission Standard for Hazardous Air Pollutants (NESHAP), new source NESHAP and the New Source Performance Standard (NSPS). In March 2012, PSEG filed a motion to intervene with the Court of Appeals in support of the EPA's implementation of MATS. Litigation of these matters remains pending and the impact on the implementation schedule is unknown at this time.
Power believes that it will not be necessary to install any material controls at its other New Jersey facilities. Additional controls may be necessary at Power’s Bridgeport Harbor coal-fired unit at an immaterial cost. In December 2011, to comply with the MACT regulators, a decision was reached to upgrade the previously planned two flue gas desulfurization scrubbers and install Selective Catalytic Reduction (SCR) systems at Power’s jointly owned coal-fired generating facility at Conemaugh in Pennsylvania. This installation is expected to be completed in the first quarter of 2015. Power's share of this investment is approximately $147 million.
NOx Regulation
In April 2009, the NJDEP finalized revisions to NOx emission control regulations that impose new NOx emission reduction requirements and limits for New Jersey fossil fuel-fired electric generation units. The rule has an impact on Power’s generation fleet, as it imposes NOx emissions limits that will require capital investment for controls or the retirement of up to 86 combustion turbines (approximately 1,750 MW) and four older New Jersey steam electric generation units (approximately 400 MW) by May 30, 2015. Retirement notifications for the combustion turbines, except for Salem Unit 3, have been filed with PJM. The Salem Unit 3 combustion turbine (38 MW) will be transitioning to an emergency generator. Evaluations are ongoing for the steam electric generation units.
Under current Connecticut regulations, Power’s Bridgeport and New Haven facilities have been utilizing Discrete Emission Reduction Credits (DERCs) to comply with certain NOx emission limitations that were incorporated into the facilities’ operating permits. In 2010, Power negotiated new agreements with the State of Connecticut extending the continued use of DERCs for certain emission units and equipment until May 31, 2014.
Clean Water Act Permit Renewals
Pursuant to the Federal Water Pollution Control Act (FWPCA), National Pollutant Discharge Elimination System (NPDES) permits expire within five years of their effective date. In order to renew these permits, but allow a plant to continue to operate, an owner or operator must file a permit application no later than six months prior to expiration of the permit. States with delegated federal authority for this program manage these permits. The New Jersey Department of Environmental Protection manages the permits under the New Jersey Pollutant Discharge Elimination System (NJPDES) program. Connecticut and New York also have permits to manage their respective pollutant discharge elimination system programs.
One of the most significant NJPDES permits governing cooling water intake structures at Power is for Salem. In 2001, the NJDEP issued a renewed NJPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water intake system. In February 2006, Power filed with the NJDEP a renewal application allowing Salem to continue operating under its existing NJPDES permit until a new permit is issued. Power prepared its renewal application in accordance with the FWPCA Section 316(b) and the 316(b) rules published in 2004.
As a result of several legal challenges to the 2004 316(b) rule by certain northeast states, environmentalists and industry groups, the rule has been suspended and has been returned to the EPA to be consistent with a 2009 United States Supreme Court decision which concluded that the EPA could rely upon cost-benefit analysis in setting the national performance standards and in providing for cost-benefit variances from those standards as part of the Phase II regulations.
In late 2010, the EPA entered into a settlement agreement with environmental groups that established a schedule to develop a new 316(b) rule by July 27, 2012. In April 2011, the EPA published a new proposed rule which did not establish any particular technology as the best technology available (e.g. closed cycle cooling). Instead, the proposed rule established marine life
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
mortality standards for existing cooling water intake structures with a design flow of more than two million gallons per day. In June 2012, the EPA posted two Notices of Data Availability (NODA) requesting comment on aspects of the April 2011 proposed rule. In July 2012, PSEG and industry trade associations submitted comments on both NODAs and the EPA and environmental groups agreed to delay the deadline for finalization of the Rule to June 27, 2013 to allow for more time to address public comments and analyze data submitted in response to the NODAs.
Power is unable to predict the outcome of this proposed rulemaking, the final form that the proposed regulations may take and the effect, if any, that they may have on its future capital requirements, financial condition, results of operations or cash flows. The results of further proceedings on this matter could have a material impact on Power’s ability to renew permits at its larger once-through cooled plants, including Salem, Hudson, Mercer, Bridgeport and possibly Sewaren and New Haven, without making significant upgrades to existing intake structures and cooling systems. The costs of those upgrades to one or more of Power’s once-through cooled plants would be material, and would require economic review to determine whether to continue operations at these facilities. For example, in Power’s application to renew its Salem permit, filed with the NJDEP in February 2006, the estimated costs for adding cooling towers for Salem were approximately $1 billion, of which Power’s share would have been approximately $575 million. These cost estimates have not been updated. Currently, potential costs associated with any closed cycle cooling requirements are not included in Power’s forecasted capital expenditures.
Capital Expenditures
The construction programs of PSEG and its subsidiaries are currently estimated to include a base level total investment of approximately $6.1 billion for the three years ended 2015. The three year capital expenditures for PSEG, Power and PSE&G are as follows:
Power's projected capital expenditures include baseline maintenance, investments in response to environmental or legal mandates and nuclear expansion. PSE&G's projections include material additions and replacements in its transmission and distribution systems to meet expected growth and manage reliability.
Basic Generation Service (BGS) and Basic Gas Supply Service (BGSS)
PSE&G obtains its electric supply requirements for customers who do not purchase electric supply from third party suppliers through the annual New Jersey BGS auctions. Pursuant to applicable BPU rules, PSE&G enters into the Supplier Master Agreement with the winners of these BGS auctions following the BPU’s approval of the auction results. PSE&G has entered into contracts with Power, as well as with other winning BGS suppliers, to purchase BGS for PSE&G’s load requirements. The winners of the auction (including Power) are responsible for fulfilling all the requirements of a PJM Load Serving Entity including the provision of capacity, energy, ancillary services, transmission and any other services required by PJM. BGS suppliers assume all volume risk and customer migration risk and must satisfy New Jersey’s renewable portfolio standards.
Power seeks to mitigate volatility in its results by contracting in advance for the sale of most of its anticipated electric output as well as its anticipated fuel needs. As part of its objective, Power has entered into contracts to directly supply PSE&G and other New Jersey electric distribution companies (EDCs) with a portion of their respective BGS requirements through the New Jersey BGS auction process, described above.
PSE&G has contracted for its anticipated BGS-Fixed Price eligible load, as follows:
(A)
Prices set in the 2013 BGS auction will become effective on June 1, 2013 when the 2010 BGS auction agreements expire.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
PSE&G has a full requirements contract with Power to meet the gas supply requirements of PSE&G’s gas customers. Power has entered into hedges for a portion of these anticipated BGSS obligations, as permitted by the BPU. The BPU permits PSE&G to recover the cost of gas hedging up to 115 billion cubic feet or 80% of its residential gas supply annual requirements through the BGSS tariff. Current plans call for Power to hedge on behalf of PSE&G approximately 70 billion cubic feet or 50% of its residential gas supply annual requirements. For additional information, see Note 23. Related-Party Transactions.
Minimum Fuel Purchase Requirements
Power has various long-term fuel purchase commitments for coal through 2017 to support its fossil generation stations and for supply of nuclear fuel for the Salem, Hope Creek and Peach Bottom nuclear generating stations and for firm transportation and storage capacity for natural gas.
Power’s strategy is to maintain certain levels of uranium and to make periodic purchases to support such levels. As such, the commitments referred to in the following table may include estimated quantities to be purchased that deviate from contractual nominal quantities. Power’s nuclear fuel commitments cover approximately 100% of its estimated uranium, enrichment and fabrication requirements through 2015 and a portion through 2017 at Salem, Hope Creek and Peach Bottom.
Power’s various multi-year contracts for firm transportation and storage capacity for natural gas are primarily used to meet its gas supply obligations to PSE&G. These purchase obligations are consistent with Power’s strategy to enter into contracts for its fuel supply in comparable volumes to its sales contracts.
As of December 31, 2012, the total minimum purchase requirements included in these commitments were as follows:
Regulatory Proceedings
New Jersey Clean Energy Program
In 2008, the BPU approved funding requirements for each New Jersey EDC applicable to its Renewable Energy and Energy Efficiency programs for the years 2009 to 2012. In late 2012, the BPU approved additional funding requirements for these programs for the first half of 2013. The aggregate funding for the first half of 2013 is $195 million. PSE&G’s share is $153 million which it recorded as a current liability as of December 31, 2012. The liability is reduced as normal payments are made. The liability has been recorded with an offsetting Regulatory Asset, since the costs associated with this program are recovered from PSE&G ratepayers through the SBC.
The BPU has started a new Comprehensive Resource Analysis proceeding to determine SBC funding for the years 2013-2016. The proceeding has no impact on current SBC assessments.
Long-Term Capacity Agreement Pilot Program (LCAPP)
In 2011, New Jersey enacted the LCAPP Act that resulted in the selection of three generators to build a total of approximately 2,000 MW of new combined-cycle generating facilities located in New Jersey. Each of the New Jersey EDCs, including PSE&G, was directed to execute a standard offer capacity agreement (SOCA) with the three selected generators, but did so under protest preserving their legal rights. The SOCA provides for the EDCs to guarantee specified annual capacity payments to the generators subject to the terms and conditions of the agreement. Legal challenges to the BPU’s implementation of the LCAPP Act were filed in New Jersey appellate court and this appeal is pending. In addition, the LCAPP Act itself has been challenged on constitutional grounds in federal court.
In May 2012, two of the three generators cleared the Reliability Pricing Model auction for the 2015/2016 delivery year in the aggregate notional amount of approximately 1,300 MW of installed capacity. SOCA payments are for a 15 year term, which are scheduled to commence for one of the generators in the 2015/2016 delivery year and for the other generator in the 2016/2017
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
delivery year. Based upon the expected percentage of state load that PSE&G will be serving during the term of these contracts, PSE&G would be responsible for approximately 52% or 676 MW of this amount.
Under current accounting guidance, the current estimated fair value of the SOCAs is recorded as a Derivative Asset or Liability with an offsetting Regulatory Asset or Liability on PSE&G’s Consolidated Balance Sheets. See Note 17. Fair Value Measurements for additional information.
Superstorm Sandy
In late October 2012, Superstorm Sandy caused severe damage to PSE&G's transmission and distribution system throughout its service territory as well as to some of Power's generation infrastructure in the northern part of New Jersey. Strong winds resulted in a storm surge that caused damage to switching stations, substations and generating infrastructure.
As of December 31, 2012, Power had incurred approximately $85 million in costs related to Superstorm Sandy, primarily comprised of repairs at certain generating stations and damage to materials and supplies, both at our fossil fleet. All the costs were recognized in Operation and Maintenance Expense, offset by $19 million of a pending future recovery of insurance proceeds. Power expects that it will incur additional future costs, primarily relating to repairs to, and replacement of, equipment and property, which could be material.
As of December 31, 2012, PSE&G had incurred approximately $295 million of costs to restore service to PSE&G's distribution and transmission systems and $5 million to repair its infrastructure and return it to pre-storm conditions. Of the costs incurred, approximately $40 million was recognized in Operation and Maintenance Expense, $75 million was recorded as Property, Plant and Equipment and $180 million was recorded as a Regulatory Asset because such costs were deferred as approved by the BPU under an Order received in December 2012. PSE&G recognized $6 million of insurance proceeds.
PSEG maintains insurance coverage against loss or damage to plants and certain properties, subject to certain exceptions, to the extent such property is usually insured and insurance is available at a reasonable cost. PSEG is seeking recovery from its insurers for the property damage, above its self-insured retentions; however, no assurances can be given relative to the timing or amount of such recovery. PSEG received an authorization for $25 million from its insurance carriers as an advance payment which was recorded in 2012. PSEG believes that additional insurance recoveries are not estimable as of December 31, 2012. PSEG is at the early stages of documenting its insurance claim which then will need to be submitted to and reviewed by its insurers. PSEG does not believe that it has a basis for estimating additional probable insurance recoveries at this time.
Leveraged Lease Investments
On January 31, 2012, PSEG entered into a specific matter closing agreement with the Internal Revenue Service (IRS) settling all matters related to cross border lease transactions. This agreement settles the leasing dispute with finality for all tax periods in which PSEG realized tax deductions from these transactions. On January 31, 2012, PSEG also signed a Form 870-AD settlement agreement covering all audit issues for tax years 1997 through 2003. On March 26, 2012, PSEG executed a Form 870-AD settlement agreement covering all audit issues for tax years 2004 through 2006. These two agreements conclude ten years of audits for PSEG and the leasing issue for all tax years. For PSEG, the impact of these agreements is an increase in financial statement Income Tax Expense of approximately $175 million. In prior periods, PSEG had established financial statement tax liabilities for uncertain tax positions in the amount of $246 million with respect to these tax years. Accordingly, the settlement resulted in a net $71 million decrease in the Income Tax Expense of PSEG.
Cash Impact
For tax years 1997 through 2003, the tax and interest PSEG owes the IRS as a result of this settlement will be reduced by the $320 million PSEG has on deposit with the IRS for this matter. PSEG paid a net deficiency for these years of approximately $4 million during the second quarter of 2012. Based upon the closing agreement and the Form 870-AD for tax years 2004 through 2006, PSEG owes the IRS approximately $620 million in tax and interest for tax years from 2004 through 2006. Based on the settlement of the leasing dispute, for tax years 2007 through 2010, the IRS owes PSEG approximately $676 million. PSEG has filed amended returns for tax years 2007-2010 reflecting the impact of the settlement. These returns have been audited by the IRS and accepted as filed. As required by statute, the IRS presented the refund claim to the Joint Committee on Taxation for approval. On October 16, 2012, PSEG was notified that the Joint Committee took no exception to the refund claim. The IRS is now processing those claims and preparing interest computations. In spite of the progress noted above, it is still possible that PSEG would have to pay $620 million over the next year to the IRS and wait while the IRS processes the $676 million refund claim in the normal course; it could take several years for the IRS to process these claims. In addition to the above, PSEG will claim a tax deduction for the accrued deficiency interest associated with this settlement in 2012, which will give rise to a cash tax savings of approximately $100 million.
Nuclear Insurance Coverages and Assessments
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, Hope Creek and Peach Bottom. NEIL also provides excess
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 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. NEIL makes a distinction between certified and non-certified acts of terrorism, as defined under the Terrorism Risk Insurance Act (TRIA), and thus its policies respond accordingly. For non-certified acts of terrorism, 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 any act of terrorism, Power’s nuclear liability policies will respond similarly to other covered events. For certified acts, Power’s nuclear property NEIL policies will respond similarly to 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 United States 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 $12.6 billion. All owners of nuclear reactors, 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 $118 million per reactor per incident, payable at $18 million per reactor per incident per year. If the damages exceed the “limit of liability,” the President is to submit to Congress a plan for providing additional compensation to the injured parties. Congress could impose further revenue-raising measures on the nuclear industry to pay claims. Power’s maximum aggregate assessment per incident is $370 million (based on Power’s ownership interests in Hope Creek, Peach Bottom and Salem) and its maximum aggregate annual assessment per incident is $55 million. 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:
(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 that is subject to reinstatement at ANI discretion.
(B)
Retrospective premium program under the Price-Anderson Act 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 United States that produces greater than 100 MW of electrical power. This retrospective assessment can be adjusted for inflation every five years. The last adjustment was effective as of October 29, 2008. The next
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
adjustment is due on or before October 29, 2013. This retrospective program is in excess of 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 $1.25 billion, Power participates in a Blanket Limit policy where the $850 million limit is shared by Power with Exelon Generation among the Braidwood, Byron, Clinton, Dresden, La Salle, Limerick, Oyster Creek, Quad Cities, TMI-1 facilities owned by Exelon Generation 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.
(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.
Minimum Lease Payments
Power, PSE&G and Energy Holdings have entered into various operating leases. The total future minimum payments of these operating leases as of December 31, 2012 are:
Note 14. Schedule of Consolidated Debt
Long-Term Debt
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
`
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(A)
PSEG entered into various interest rate swaps to hedge the fair value of certain debt at Power. The fair value adjustments from these hedges are reflected as offsets to long-term debt on the Consolidated Balance Sheet. For additional information, see Note 16. Financial Risk Management Activities.
(B)
In September 2009, Power completed an exchange offer with eligible holders of Energy Holdings’ 8.50% Senior Notes due 2011 in order to manage long-term debt maturities. Since the debt exchange was between two subsidiaries of the same parent company, PSEG, and treated as a debt modification for accounting purposes, the resulting premium was deferred and is being amortized over the term of the newly issued debt. The deferred amount is reflected as an offset to Long-Term Debt on PSEG’s Consolidated Balance Sheet.
(C)
The Pennsylvania Economic Development Authority (PEDFA) bond and The Pollution Control Financing Authority of Salem County bonds for Power and PSE&G, respectively, are variable rate bonds that are in weekly reset mode.
(D)
Secured by essentially all property of PSE&G pursuant to its First and Refunding Mortgage.
(E)
Non-recourse financing transactions consist of loans from banks and other lenders that are typically secured by project assets and cash flows and 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 include the potential for loss of any invested equity by the parent.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(F)
As a result of the Dynegy bankruptcy proceedings, Energy Holdings ceased leveraged lease accounting and recorded the related nonrecourse project debt on its balance sheet at its fair value of $50 million. Upon settlement of the claims against Dynegy in 2012, Energy Holdings was released from this debt.
Long-Term Debt Maturities
The aggregate principal amounts of maturities for each of the five years following December 31, 2012 are as follows:
Long-Term Debt Financing Transactions
During 2012, PSEG and its subsidiaries had the following Long-Term Debt issuances, maturities and redemptions:
Power
•
redeemed $250 million of 5.00% Senior Notes due April 1, 2014,
•
redeemed and retired Pollution Control Notes servicing and securing $98 million of tax-exempt financings, including $14 million of 5.50% York County Industrial Development Authority Pollution Control Revenue Refunding Bonds due September 1, 2020; $19 million of 5.85% Indiana County Industrial Development Authority Pollution Control Revenue Refunding Bonds due June 1, 2027; $25 million of 5.75% Pollution Control Financing Authority of Salem County Pollution Control Revenue Refunding Bonds due April 1, 2031; and $40 million of 5.75% Connecticut Development Authority Solid Waste Disposal Facility Revenue Bonds due November 1, 2037,
•
paid $66 million of 5.00% Pollution Control Revenue Refunding Notes at maturity, and
•
paid cash dividends of $600 million to PSEG.
PSE&G
•
remarketed $50 million of weekly-reset variable rate demand bonds of the Pollution Control Financing Authority of Salem County due November 1, 2033, which are serviced and secured by PSE&G's First and Refunding Mortgage Bonds of like tenor,
•
paid $300 million of 5.13% Secured Medium-Term Notes at maturity,
•
issued $350 million of 3.65% Secured Medium-Term Notes, Series H due September 2042,
•
refinanced at par $50 million of 5.45% fixed rate Pollution Control Financing Authority of Salem County Authority Bonds due February 1, 2032, which were serviced and secured by PSE&G’s First and Refunding Mortgage Bonds of like tenor, with $50 million of weekly-reset variable rate demand bonds due April 1, 2046, which are serviced and secured by PSE&G’s First and Refunding Mortgage Bonds of like tenor,
•
redeemed and retired at par $23 million of 5.20% fixed rate Pollution Control Financing Authority of Salem County Authority Bonds due March 1, 2025, which were serviced and secured by PSE&G’s First and Refunding Mortgage Bonds of like tenor,
•
issued $450 million of 3.95% Secured Medium-Term Notes, Series H due May 2042,
•
paid $205 million of Transition Funding’s securitization debt, and
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
•
paid $11 million of Transition Funding II’s securitization debt.
Energy Holdings
•
was released from $50 million of nonrecourse project debt related to the Dynegy Leases, and
•
paid cash dividends of $500 million to PSEG.
PSE&G
In January 2013, PSE&G issued $400 million of 3.80% Secured Medium-Term Notes, Series H, due January 2043, and paid $150 million of 5.00% Secured Medium-Term Notes, at maturity.
Short-Term Liquidity
PSEG meets its short-term liquidity requirements primarily through the issuance of commercial paper. PSE&G maintains its own separate commercial paper program to meet its short-term liquidity requirements. Both commercial paper programs are fully back-stopped by their own separate credit facilities.
The commitments under our credit facilities are provided by a diverse bank group. As of December 31, 2012, no single institution represented more than 8% of the total commitments in our credit facilities.
As of December 31, 2012, our total credit capacity was in excess of our anticipated maximum liquidity requirements.
Each of our credit facilities is restricted as to availability and use to the specific companies as listed below; however, if necessary, the PSEG facilities can also be used to support our subsidiaries’ liquidity needs. Our total credit facilities and available liquidity as of December 31, 2012 were as follows:
(A)
Includes amounts related to letters of credit outstanding.
(B)
Includes amounts related to CP and letters of credit outstanding
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, 2012 and 2011. See Note 17. Fair Value Measurements for more information on fair value guidance and the hierarchy that prioritizes the inputs to fair value measurements into three levels.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(A)
Fair value represents net offsets to debt resulting from adjustments from interest rate swaps entered into to hedge certain debt at Power. Carrying amount represents such fair value reduced by the unamortized premium resulting from a debt exchange entered into between Power and Energy Holdings.
(B)
The debt fair valuation is based on the present value of each bond’s future cash flows. The discount rates used in the present value analysis are based on an estimate of new issue bond yields across the treasury curve. When a bond has embedded options, an interest rate model is used to reflect the impact of interest rate volatility into the analysis (primarily Level 2 measurements).
(C)
Fair value amounts as of December 31, 2011 include $50 million of non-recourse project debt related to Dynegy which is classified as a Level 3 measurement. As of the June 5, 2012, the effective date of the amended settlement agreement, the $50 million of Notes Payable was written off. See the Fair Value Option Section of Note 17. Fair Value Measurements for additional information. Non-recourse project debt of $44 million is valued as equivalent to the amortized cost and is classified as a Level 3 measurement.
Note 15. Schedule of Consolidated Capital Stock
(A)
PSEG did not issue any new shares under the Dividend Reinvestment and Stock Purchase Plan (DRASPP) and the Employee Stock Purchase Plan (ESPP) in 2012 or 2011. Total authorized and unissued shares of common stock available for issuance through PSEG’s DRASPP, ESPP and various employee benefit plans amounted to 7 million shares as of December 31, 2012.
As of December 31, 2012, there was an aggregate of 7.5 million shares of $100 par value and 10 million 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 16. Financial Risk Management Activities
The operations of PSEG, Power and PSE&G are exposed to market risks from changes in commodity prices, interest rates and equity prices that could affect their results of operations and financial condition. Exposure to these risks is managed through normal operating and financing activities and, when appropriate, through hedging transactions. Hedging transactions use derivative instruments to create a relationship in which changes to the value of the assets, liabilities or anticipated transactions exposed to market risks are expected to be offset by changes in the value of these derivative instruments.
Commodity Prices
The availability and price of energy commodities are subject to fluctuations due to weather, environmental policies, changes in supply and demand, state and federal regulatory policies, market conditions, transmission availability and other events. Power uses physical and financial transactions in the wholesale energy markets to mitigate the effects of adverse movements in fuel and electricity prices. Derivative contracts that do not qualify for hedge accounting or normal purchases/normal sales treatment are MTM with changes in fair value recorded in the income statement. The fair value for the majority of these contracts is obtained from quoted market sources. Modeling techniques using assumptions reflective of current market rates, yield curves and forward prices are used to interpolate certain prices when no quoted market exists.
Cash Flow Hedges
Power uses forward sale and purchase contracts, swaps and futures contracts to hedge
•
forecasted energy sales from its generation stations and the related load obligations,
•
the price of fuel to meet its fuel purchase requirements, and
•
certain forecasted natural gas sales and purchases made to support the BGSS contract with PSE&G.
These derivative transactions are designated and effective as cash flow hedges. During the second quarter of 2012, Power de-designated certain of its commodity derivative transactions that had previously qualified as cash flow hedges as they were deemed to no longer be highly effective as required by the relevant accounting guidance. As a result, since June 1, 2012, Power recognizes all gains and losses from changes in the fair value of these derivatives immediately in earnings rather than deferring any such amounts in Accumulated Other Comprehensive Income (Loss). The fair values of Power’s de-designated hedges were frozen in Accumulated Other Comprehensive Income (Loss) as the original forecasted transactions are still expected to occur and are reclassified into earnings as the original derivative transactions settle.
As of December 31, 2012 and 2011, the fair value and the impact on Accumulated Other Comprehensive Income (Loss) associated with accounting hedge activity was as follows:
The expiration date of the longest-dated cash flow hedge at Power is in 2014. Power’s after-tax unrealized gains on these derivatives that are expected to be reclassified to earnings during the next 12 months are $8 million. There was no ineffectiveness associated with qualifying hedges as of December 31, 2012.
Trading Derivatives
The primary purpose of Power’s wholesale marketing operation is to optimize the value of the output of the generating facilities via various products and services available in the markets it serves. Historically, Power engaged in trading of electricity and energy-related products where such transactions were not associated with the output or fuel purchase requirements of its facilities. This trading consisted mostly of energy supply contracts where Power secured sales commitments with the intent to supply the energy services from purchases in the market rather than from its owned generation. Such trading activities were marked to market through the income statement and represented less than one percent of gross margin (revenues less energy costs) on an annual basis. Effective July 2011, Power has not entered into any trading derivative contracts and anticipates that it will not do so in the future.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Other Derivatives
Power enters into additional contracts that are derivatives, but do not qualify for or are not designated as cash flow hedges. These transactions are intended to mitigate exposure to fluctuations in commodity prices and optimize the value of its expected generation. Trade types include financial options, futures, swaps, fuel purchases and forward purchases and sales of electricity. Changes in fair market value of these contracts are recorded in earnings.
PSE&G is a party to certain long-term natural gas sales contracts to optimize its pipeline capacity utilization. In addition, as further described in Note 13. Commitments and Contingent Liabilities, PSE&G was directed to execute long-term SOCAs with certain generators to support the LCAPP Act. Two of the three generators cleared the Reliability Pricing Model auction for the 2015/2016 delivery year. These two SOCA contracts qualify as derivatives and are marked to fair value with the offset recorded to Regulatory Assets and Liabilities.
Interest Rates
PSEG, Power and PSE&G are subject to the risk of fluctuating interest rates in the normal course of business. Exposure to this risk is managed by targeting a balanced debt maturity profile which limits refinancing in any given period or interest rate environment. In addition, they have used a mix of fixed and floating rate debt, interest rate swaps and interest rate lock agreements.
Fair Value Hedges
PSEG enters into fair value hedges to convert fixed-rate debt into variable-rate debt. In order to redeem Power's $250 million of 5% Senior Notes due April 2014 in December 2012, PSEG terminated its $250 million interest rate swap that had converted this debt into variable-rate. As of December 31, 2012, PSEG had seven interest rate swaps outstanding totaling $850 million. These swaps convert Power’s $300 million of 5.5% Senior Notes due December 2015, $300 million of Power’s $303 million of 5.32% Senior Notes due September 2016 and Power’s $250 million of 2.75% Senior Notes due September 2016 into variable-rate debt. These interest rate swaps are designated and effective as fair value hedges. The fair value changes of the interest rate swaps are fully offset by the changes in the fair value of the underlying forecasted interest payments of the debt. As of December 31, 2012 and 2011, the fair value of all the underlying hedges was $57 million and $62 million, respectively.
Cash Flow Hedges
PSEG uses interest rate swaps and other derivatives, which are designated and effective as cash flow hedges, to manage its exposure to the variability of cash flows, primarily related to variable-rate debt instruments. The Accumulated Other Comprehensive Income (Loss) (after tax) related to interest rate derivatives designated as cash flow hedges was $(2) million as of December 31, 2012 and 2011.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fair Values of Derivative Instruments
The following are the fair values of derivative instruments on the Consolidated Balance Sheets:
(A)
Represents the netting of fair value balances with the same counterparty (where the right of offset exists) and the application of collateral. As of December 31, 2012 and December 31, 2011, net cash collateral paid of $2 million and net cash collateral received of $82 million, respectively, was netted against the corresponding net derivative contract positions. Of the $2 million as of December 31, 2012, cash collateral of $(3) million was netted against current assets and cash collateral of $5 million was netted against current liabilities. Of the $82 million as of December 31, 2011, cash collateral of $(77) million and $(23) million were netted against current assets and noncurrent assets,
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
respectively, and cash collateral of $16 million and $2 million were netted against current liabilities and noncurrent liabilities, respectively.
Certain of Power’s derivative instruments contain provisions that require Power to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Power’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit risk-related contingent features stipulate that if Power were to be downgraded or lose its investment grade credit rating, it would be required to provide additional collateral. This incremental collateral requirement can offset collateral requirements related to other derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master agreements. Power also enters into commodity transactions on the New York Mercantile Exchange (NYMEX) and Intercontinental Exchange (ICE). The NYMEX and ICE clearing houses act as counterparties to each trade. Transactions on the NYMEX and ICE must adhere to comprehensive collateral and margin requirements.
The aggregate fair value of all derivative instruments with credit risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the NYMEX and ICE that are fully collateralized) was $98 million and $285 million as of December 31, 2012 and 2011, respectively. As of December 31, 2012 and 2011, Power had the contractual right of offset of $61 million and $149 million, respectively, related to derivative instruments that are assets with the same counterparty under master agreements and net of margin posted. If Power had been downgraded or lost its investment grade rating, it would have had additional collateral obligations of $37 million and $136 million as of December 31, 2012 and 2011, respectively, related to its derivatives, net of the contractual right of offset under master agreements and the application of collateral. This potential additional collateral is included in the $654 million and $812 million as of December 31, 2012 and 2011, respectively, discussed in Note 13. Commitments and Contingent Liabilities.
The following shows the effect on the Consolidated Statements of Operations and on Accumulated Other Comprehensive Income (AOCI) of derivative instruments designated as cash flow hedges for the years ended December 31, 2012, 2011 and 2010:
(A)
Includes amounts for PSEG parent.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following reconciles the AOCI for derivative activity included in the Accumulated Other Comprehensive Loss of PSEG on a pre-tax and after-tax basis:
The following shows the effect on the Consolidated Statements of Operations of derivative instruments not designated as hedging instruments or as normal purchases and sales for the years ended December 31, 2012, 2011 and 2010:
Power’s derivative contracts reflected in the preceding tables include contracts to hedge the purchase and sale of electricity and natural gas and the purchase of fuel. Not all of these contracts qualify for hedge accounting. Most of these contracts are marked to market. The tables above do not include contracts for which Power has elected the normal purchase/normal sales exemption, such as its BGS contracts and certain other energy supply contracts that it has with other utilities and companies with retail load. In addition, PSEG has interest rate swaps designated as fair value hedges. The effect of these hedges was to reduce interest expense by $22 million, $25 million and $24 million for the years ended December 31, 2012, 2011 and 2010, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following reflects the gross volume, on an absolute value basis, of derivatives as of December 31, 2012 and 2011:
Credit Risk
Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. We have established credit policies that we 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 allow for the netting of positive and negative exposures associated with a single counterparty. In the event of non-performance or non-payment by a major counterparty, there may be a material adverse impact on Power’s and PSEG’s financial condition, results of operations or net cash flows.
As of December 31, 2012, 94% of the credit for Power’s operations was with investment grade counterparties. Credit exposure is defined as any positive results of netting accounts receivable/accounts payable and the forward value of open positions (which includes all financial instruments including derivatives and non-derivatives and normal purchases/normal sales).
The following table provides information on Power’s credit risk from others, net of cash collateral, as of December 31, 2012. 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 quality of Power’s credit risk by credit rating of the counterparties.
(A)
Includes net exposure of $119 million with PSE&G. The remaining net exposure of $46 million is with a nonaffiliated power purchaser which is a regulated investment grade counterparty.
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 cash collateral than the outstanding exposure, in which case there would be no exposure.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
When letters of credit have been posted as collateral, the exposure amount is not reduced, but the exposure amount is transferred to the rating of the issuing bank. As of December 31, 2012, Power had 174 active counterparties.
Note 17. Fair Value Measurements
PSEG, Power and PSE&G adopted accounting standard update “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in GAAP and International Financial Reporting Standards (IFRS)” effective January 1, 2012. This standard defines fair value, establishes a framework for measuring fair value and expands disclosures about fair value measurements.
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance for fair value measurement emphasizes that fair value is a market-based measurement, not an entity-specific measurement, and establishes a fair value hierarchy that distinguishes between assumptions based on market data obtained from independent sources and those based on an entity’s own assumptions. The hierarchy prioritizes the inputs to fair value measurement into three levels:
Level 1-measurements utilize quoted prices (unadjusted) in active markets for identical assets or liabilities that PSEG, Power and PSE&G have the ability to access. These consist primarily of listed equity securities.
Level 2-measurements include quoted prices for similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, and other observable inputs such as interest rates and yield curves that are observable at commonly quoted intervals. These consist primarily of non-exchange traded derivatives such as forward contracts or options and most fixed income securities.
Level 3-measurements use unobservable inputs for assets or liabilities, based on the best information available and might include an entity’s own data and assumptions. In some valuations, the inputs used may fall into different levels of the hierarchy. In these cases, the financial instrument’s level within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. As of December 31, 2012, these consisted primarily of electric swaps whose basis is deemed significant to the fair value measurement, electric load deals, long-term electric capacity contracts and long-term gas supply contracts.
The following tables present information about PSEG’s, Power’s and PSE&G’s respective assets and (liabilities) measured at fair value on a recurring basis as of December 31, 2012 and December 31, 2011, including the fair value measurements and the levels of inputs used in determining those fair values. Amounts shown for PSEG include the amounts shown for Power and PSE&G.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(A)
Level 2-Fair values for energy-related contracts are obtained primarily using a market-based approach. Most derivative contracts (forward purchase or sale contracts and swaps) are valued using the average of the bid/ask midpoints from multiple broker or dealer quotes or auction prices. Prices used in the valuation process are also corroborated independently by management to determine that values are based on actual transaction data or, in the absence of transactions, bid and offers for the day. Examples may include certain exchange and non-exchange traded capacity and electricity contracts and natural gas physical or swap contracts based on market prices, basis adjustments and other premiums where adjustments and premiums are not considered significant to the overall inputs.
Level 3-For energy-related contracts, which include more complex agreements where limited observable inputs or pricing information are available, modeling techniques are employed using assumptions reflective of contractual
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
terms, current market rates, forward price curves, discount rates and risk factors, as applicable. Fair values of other energy contracts may be based on broker quotes that we cannot corroborate with actual market transaction data.
(B)
Interest rate swaps are valued using quoted prices on commonly quoted intervals, which are interpolated for periods different than the quoted intervals, as inputs to a market valuation model. Market inputs can generally be verified and model selection does not involve significant management judgment.
(C)
The NDT Fund maintains investments in various equity and fixed income securities classified as “available for sale.” The Rabbi Trust maintains investments in an S&P 500 index fund and various fixed income securities classified as “available for sale.” These securities are generally valued with prices that are either exchange provided (equity securities) or market transactions for comparable securities and/or broker quotes (fixed income securities).
Level 1-Investments in marketable equity securities within the NDT Fund are primarily investments in common stocks across a broad range of industries and sectors. Most equity securities are priced utilizing the principal market close price or, in some cases, midpoint, bid or ask price (primarily Level 1). The Rabbi Trust equity index fund is valued based on quoted prices in an active market (Level 1).
Level 2-NDT and Rabbi Trust fixed income securities are limited to investment grade corporate bonds and United States Treasury obligations or Federal Agency mortgage-backed securities with a wide range of maturities. Since many fixed income securities do not trade on a daily basis, they are priced using an evaluated pricing methodology that varies by asset class and reflects observable market information such as the most recent exchange price or quoted bid for similar securities. Market-based standard inputs typically include benchmark yields, reported trades, broker/dealer quotes, and issuer spreads (primarily Level 2). Short-term investments and certain commingled temporary investments are valued using observable market prices or market parameters such as time-to-maturity, coupon rate, quality rating and current yield (primarily Level 2).
(D)
For Non-Recourse Debt, see Fair Value Option discussion.
(E)
Cash collateral netting represents collateral amounts netted against derivative assets and liabilities as permitted under the accounting guidance for Offsetting of Amounts Related to Certain Contracts.
Additional Information Regarding Level 3 Measurements
For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations for contracts with tenors that extend into periods with no observable pricing. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 because the model inputs generally are not observable. PSEG’s Risk Management Committee approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The Risk Management Committee reports to the Audit Committee of the PSEG Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at PSEG. Forward price curves for the power market utilized by Power to manage the portfolio are maintained and reviewed by PSEG’s Enterprise Risk Management market pricing group and used for financial reporting purposes. PSEG considers credit and nonperformance risk in the valuation of derivative contracts categorized in Levels 2 and 3, including both historical and current market data, in its assessment of credit and nonperformance risk by counterparty. The impacts of credit and nonperformance risk were not material to the financial statements.
The following table provides detail surrounding significant Level 3 valuations, of which the most significant positions are electric swaps and electric load deals for Power and long-term electric capacity contracts and long-term natural gas supply contracts for PSE&G. For Power, in general, electric swaps are valued based on at least two pricing inputs, basis and underlying. To the extent the basis component is based on a single broker quote and is significant to the fair value of the electric swap, it is categorized as Level 3. The remaining balance of Power’s Level 3 positions consist primarily of certain long-term electric capacity contracts, electric load deals in which load consumption may change hourly and certain long-term natural gas supply contracts. Long-term electric capacity contracts are measured at fair value using capacity auction prices. If the fair value for the unobservable tenor is significant, then the entire capacity contract is categorized as Level 3. Electric load deals are fair valued using certain unobservable inputs, such as historic load variability. For Power and PSE&G, long-term gas supply contracts are measured at fair value using both actively traded pricing points as well as unobservable inputs such as gas prices beyond observable periods and long-term basis quotes and accordingly, the fair value measurements are classified in Level 3. For PSE&G, long-term electric capacity contracts are measured at fair value using both observable capacity prices and unobservable inputs consisting of forecasts of future long-term electric capacity prices and include adjustments for contingencies, such as litigation risk and plant construction risk. Accordingly, the fair value measurements are classified as Level 3.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The table below discloses the significant unobservable inputs used in developing the fair value of these Level 3 positions:
(A)
Includes long-term electric capacity and long-term gas supply positions which are immaterial.
(B)
Includes long-term gas supply and long-term electric capacity positions with various unobservable inputs. Significant unobservable inputs for the gas supply contracts include long-term basis prices in the range of $0 to $2/MMBTU of natural gas. Unobservable inputs for the long-term electric capacity contracts include forecasted capacity prices in the range of $100 to $400/MW day.
Significant unobservable inputs listed above would have a direct impact on the fair values of the above Level 3 instruments if they were adjusted. For energy-related contracts in cases where Power and PSE&G are sellers, an increase in either the power basis or the load variability or the longer-term basis amounts would decrease the fair value. For long-term electric capacity contracts where Power or PSE&G are buyers, an increase in the capacity price would increase the fair value.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation of the beginning and ending balances of Level 3 derivative contracts and securities for the years ended December 31, 2012 and 2011 follows:
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Year Ended December 31, 2012
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Changes in Level 3 Assets and (Liabilities) Measured at Fair Value on a Recurring Basis
for the Year Ended December 31, 2011
(A)
PSEG’s and Power’s gains and losses attributable to changes in net derivative assets and liabilities include $42 million and $17 million in Operating Income in 2012 and 2011, $0 million and $2 million in OCI in 2012 and 2011, and $3 million in Income from Discontinued Operations in 2011. Of the $42 million in Operating Income in 2012, $(15) million is unrealized. Of the $17 million in Operating Income in 2011, $9 million is unrealized. Energy Holding's release from its obligations under the non-recourse debt is included in PSEG's Operating Income and is offset by the write-off of the related assets.
(B)
Mainly includes gains/losses on PSE&G’s derivative contracts that are not included in either earnings or OCI, as they are deferred as a Regulatory Asset/Liability and are expected to be recovered from/returned to PSE&G’s customers.
(C)
Includes $66 million in purchases and $(36) million in sales in 2011.
(D)
Represents $(57) million in settlements for derivative contracts in 2012. Includes $(25) million in issuances and $(12) million in settlements for derivative contracts and includes $(50) million of issuances due to initial recognition of lessor notes resulting from rejection of the Dynegy leveraged leases in 2011. See Fair Value Option discussion.
(E)
During the year ended December 31, 2012, there were no transfers among levels. During the year ended December 31, 2011, $8 million of assets in the NDT Fund were transferred from Level 3 to Level 2, due to more observable pricing for the underlying securities and $33 million of net derivative assets were transferred from Level 3 to Level 2 due to more available observable market data. The transfers were recognized as of the beginning of the first quarter and fourth quarter, respectively, (i.e. the quarters in which the transfers occurred), as per PSEG’s policy.
As of December 31, 2012, PSEG carried $1.8 billion of net assets that are measured at fair value on a recurring basis, of which $31 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
As of December 31, 2011, PSEG carried $1.6 billion of net assets that are measured at fair value on a recurring basis, of which $29 million of net liabilities were measured using unobservable inputs and classified as Level 3 within the fair value hierarchy.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Fair Value Option
As of December 31, 2011, the effective date of the Dynegy lease rejections, the leases of the Roseton and Danskammer generation facilities were effectively terminated and no longer qualified for leveraged lease accounting under the guidance for leases. As the owner of the facilities, Energy Holdings was required to recognize the underlying assets and nonrecourse notes payable (Notes Payable) associated with these leases at their respective fair values on the effective date of the rejection. Energy Holdings elected to record the Notes Payable at fair value each reporting period under the fair value option in accordance with guidance for Financial Instruments. The fair value option permits the irrevocable fair value election for selected eligible financial assets or liabilities. Any changes in the fair value of the Notes Payable are included in earnings each period. The $550 million of contractual principal outstanding on the Notes Payable was valued at $50 million as of December 31, 2011. Energy Holdings elected this option to eliminate certain complexities in applying the effective interest method of amortization given the uncertain payment streams between the election date and the expected foreclosure date. There were no other debt instruments of this type eligible for the fair value option as of December 31, 2011. The $50 million fair value of these Notes Payable is included on PSEG’s Consolidated Balance Sheet as of December 31, 2011. The fair values of the Notes Payable include significant internal assumptions based on expected cash flows and the fair values of the underlying collateral. Changes to projected capacity factors, capacity and energy prices, fuel costs and other required cash outflows could significantly impact the fair value of the collateral which would increase or decrease the fair value of the Notes. These Notes Payable are classified as Level 3 in the fair value hierarchy as a result of mainly unobservable inputs. As of the June 5, 2012 effective date of the amended settlement agreement, the Notes Payable and related assets were written off.
The table of fair value of debt is included in Note 14. Schedule of Consolidated Debt.
Non-recurring Fair Value Measurements
During the fourth quarter of 2011, DH filed for protection under Chapter 11 of the U.S. Bankruptcy Code. As a result of the settlement agreement that was reached relating to the lease of electric generation facilities to subsidiaries of DH (See Note 8. Financing Receivables), Energy Holdings ceased leveraged lease accounting for the leased assets and recorded those generation facilities at their respective fair values totaling $50 million, which were carried as nonrecurring fair values as of December 31, 2011. The fair values of those generation facilities were determined based on a third party appraisal using significant assumptions including expectations of cash flows which are considered mainly unobservable inputs (Level 3).
Note 18. Stock Based Compensation
PSEG's 2004 Long-Term Incentive Plan (2004 LTIP) is a broad-based equity compensation program that provides for grants of various long-term incentive compensation awards, such as stock options, stock appreciation rights, performance units, restricted stock, restricted stock units, cash awards or any combination thereof. The types of long-term incentive awards that have been granted and remain outstanding under the 2004 LTIP are non-qualified options to purchase shares of PSEG's common stock, restricted stock awards, restricted stock unit awards and performance unit awards. The type of equity award that is granted and the details of that award may vary from time to time and is subject to the approval of the Organization and Compensation Committee of PSEG's Board of Directors (OCC), the plan's administrative committee.
The 2004 LTIP currently provides for the issuance of equity awards with respect to approximately 26 million shares of common stock. As of December 31, 2012, there were approximately 17 million shares available for future awards under the 2004 LTIP.
Stock Options
Under the 2004 LTIP, non-qualified options to acquire shares of PSEG common stock may be granted to officers and other key employees selected by the OCC. Option awards are granted with an exercise price equal to the market price of PSEG's common stock at the grant date. The options generally vest over four years of continuous service. Vesting schedules may be accelerated upon the occurrence of certain events, such as a change-in-control (unless substituted with an equity award of equal value), retirement, death or disability. Options are exercisable over a period of time designated by the OCC (but not prior to one year or longer than 10 years from the date of grant) and are subject to such other terms and conditions as the OCC determines. Payment by option holders upon exercise of an option may be made in cash or, with the consent of the OCC, by delivering previously acquired shares of PSEG common stock.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Restricted Stock
Under the 2004 LTIP, PSEG has granted restricted stock awards to officers and other key employees. These shares are subject to risk of forfeiture until vested by continued employment. Restricted stock generally vests annually over three or four years, but is considered outstanding at the time of grant, as the recipients are entitled to dividends and voting rights. Vesting may be accelerated upon certain events, such as change-in-control (unless substituted with an equity award of equal value), retirement, death or disability.
Restricted Stock Units
Under the 2004 LTIP, PSEG has granted restricted stock unit awards to officers and other key employees. These awards, which are bookkeeping entries only, are subject to risk of forfeiture until vested by continued employment. Until vested, the units are credited with dividend equivalents proportionate to the dividends paid on PSEG common stock. Distributions are made in shares of common stock. The restricted stock unit grants for 2012 and 2011 generally vest at the end of three years. Vesting may be accelerated upon certain events such as change-in-control or death. Prior to 2011, restricted stock unit grants generally vested over four years.
Performance Units
Under the 2004 LTIP, performance units were granted to officers and other key employees, which provide for payment in shares of PSEG common stock based on achievement of certain financial goals over a three-year performance period. The payout varies from 0% to 200% of the number of performance units granted depending on PSEG's performance with respect to certain financial targets, including targets related to comparative performance against other companies in a peer group of energy companies. The performance units are credited with dividend equivalents in an amount equal to dividends paid on PSEG common stock up until the shares are distributed. Vesting may be pro-rated for the employee's service during the performance period as a result of certain events, such as change-in-control (unless substituted with an equity award of equal value), retirement, death or disability.
Stock-Based Compensation
All outstanding unvested stock options are being expensed based on their grant date fair values, which were determined using the Black-Scholes option-pricing model. Stock option awards are expensed on a tranche-specific basis over the requisite service period of the award. Ultimately, compensation expense for stock options is recognized for awards that vest.
PSEG recognizes compensation expense for restricted stock and restricted stock units over the vesting period based on the grant date fair market value of the shares, which is equal to the market price of PSEG's common stock on the date of the grant.
PSEG recognizes compensation expense for performance units based on the grant date fair values of the award, which were determined using the Monte Carlo model. The accrual of compensation cost was based on the probable achievement of the performance conditions, which result in a payout from 0% to 200% of the initial grant. The accrual during the year of grant is estimated at 100% of the original grant. The accrual may be adjusted for subsequent changes in the estimated or actual outcome.
There was less than $1 million of excess tax benefits for 2012. The was $1 million of excess tax benefits included as financing cash flows on the Consolidated Statements of Cash Flow for each of the years ended December 31, 2011 and 2010, respectively.
PSEG recognizes compensation cost of awards issued over the shorter of the original vesting period or the period beginning on the date of grant and ending on the date an individual is eligible for retirement and the award vests.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock Options
Changes in stock options for 2012 are summarized as follows:
The fair value of each option grant is estimated on the date of grant using the Black-Scholes option-pricing model. There were no option grants in 2012, 2011 and 2010.
Activity for options exercised for the years ended December 31, 2012, 2011 and 2010 is shown below:
Less than one million options vested during each of the years ended December 31, 2012, 2011 and 2010. The total fair value of the stock options vested during the years ended December 31, 2012, 2011 and 2010 was $3 million, $5 million and $7 million, respectively.
As of December 31, 2012, there was approximately $1 million of unrecognized compensation cost related to stock options, which is to be recognized over a weighted average period of 0.5 years.
Restricted Stock
Changes in restricted stock for the year ended December 31, 2012 are summarized as follows:
There were no restricted stock awards granted in 2012, 2011 and 2010.
The total intrinsic value of restricted stock vested during the years ended December 31, 2012, 2011 and 2010 was less than $1 million, $1 million and $3 million, respectively.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Restricted Stock Units
Changes in restricted stock units for the year ended December 31, 2012 are summarized as follows:
The weighted average grant date fair value per share for restricted stock during the years ended December 31, 2012, 2011 and 2010 was $30.95, $32.03 and $31.13 per share, respectively.
The total intrinsic value of restricted stock units vested during the years ended December 31, 2012, 2011 and 2010 was $5 million, $7 million and $6 million, respectively.
As of December 31, 2012, there was approximately $9 million of unrecognized compensation cost related to the restricted stock units, which is expected to be recognized over a weighted average period of 1.0 year. Dividend equivalents units of 40,044 accrued on the restricted stock units during the year.
Performance Share Units
Changes in Performance Share Units for the year ended December 31, 2012 are summarized as follows:
The weighted average grant date fair value per share for performance share units during the years ended December 31, 2012, 2011 and 2010 was $31.25, $35.33 and $34.29 per share, respectively.
The total intrinsic value of performance share units vested during the year ended December 31, 2012, 2011 and 2010 was $4 million, $9 million and $15 million, respectively.
As of December 31, 2012, there was approximately $13 million of unrecognized compensation cost related to the performance share units, which is expected to be recognized over a weighted average period of 1.0 year. Dividend equivalents units of 49,170 accrued on the performance share units during the year.
Outside Directors
Under the Directors Equity Plan, annually, on the first business day of May, each non-employee member of the Board of Directors is awarded stock units based on amount of annual compensation to be paid at the closing price of PSEG common stock on that date. Dividend equivalents are credited quarterly and distributions will commence upon the director leaving the Board.
The fair value of these awards is recorded as compensation expense in the Consolidated Statements of Operations. Compensation expense for the plan for each of the years ended December 31, 2012, 2011 and 2010 was approximately $1 million.
Employee Stock Purchase Plan (ESPP)
PSEG maintains an ESPP for all eligible employees of PSEG and its subsidiaries. Under the ESPP, shares of PSEG common stock may be purchased at 95% of the fair market value through payroll deductions. In any year, employees may purchase shares having a value not exceeding 10% of their base pay. During the years ended December 31, 2012, 2011 and 2010,
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
employees purchased 191,572, 183,338 and 178,684 shares at an average price of $31.32, $30.69 and $30.32 per share, respectively. As of December 31, 2012, 3.6 million shares were available for future issuance under this plan.
Note 19. Other Income and Deductions
(A)
Other primarily consists of activity at PSEG (parent company), Energy Holdings and Services and intercompany eliminations.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 20. Income Taxes
A reconciliation of reported income tax expense for PSEG with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is an analysis of deferred income taxes for PSEG:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation of reported income tax expense for Power with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is an analysis of deferred income taxes for Power:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation of reported income tax expense for PSE&G with the amount computed by multiplying pre-tax income by the statutory federal income tax rate of 35% is as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following is an analysis of deferred income taxes for PSE&G:
As of December 31, 2012, PSE&G had New Jersey State income tax net operating loss (NOL) carryforwards of $1.5 billion, on which a deferred tax asset of $87 million was recorded, which will expire between 2031 and 2033. We believe that it is more-likely-than-not that the benefit from the state NOL carryforwards will be realized.
Each of PSEG, Power and PSE&G 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 or refunded to PSE&G’s customers in the future. These amounts were determined using the enacted federal income tax rate of 35% and state income tax rate of 9%. For additional information, see Note 6. Regulatory Assets and Liabilities.
The Patient Protection and Affordable Care Act and the Health Care and Education Reconciliation Act of 2010 include various health care-related provisions which will go into effect over the next several years. One of the provisions eliminates the tax deductibility of retiree health care costs, to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage. Although this change does not take effect immediately, the accounting impact was required to be recognized when the legislation was signed. As a result, in the first quarter of 2010, PSEG recorded non-cash after tax charges of $9 million for income tax expense to establish the related deferred tax liabilities,
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
primarily related to Power. There was no immediate impact on PSE&G’s income tax expense or effective tax rate since the related amount of $78 million was deferred as a Regulatory Asset to be collected and amortized over future periods.
Two other tax provisions were enacted during 2010 that had a significant impact on PSEG’s cash position. The Small Business Jobs Act of 2010 extended the tax deduction for 50% bonus depreciation through 2010 for qualified property. The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 included a provision making qualified property placed into service after September 8, 2010 and before January 1, 2012, eligible for 100% bonus depreciation for tax purposes. In addition, qualified property placed into service in 2012 is eligible for 50% bonus depreciation for tax purposes. On January 2, 2013, the President signed into law the American Taxpayer Relief Act of 2012 that further extends 50% bonus depreciation for property placed in service before January 1, 2014. These provisions contain rules which afford certain projects which have a long production period, the benefit of bonus depreciation. These provisions will also generate cash for PSEG through tax benefits related to accelerated depreciation, most of which was realized in 2011. These tax benefits would have otherwise been received over an estimated average 20 year period.
With respect to ITC, for financial statement periods including 2010 and 2011, the law provided an option to claim either a grant or the ITC. Accordingly, in those periods, the ITC was accounted for as a reduction of the book basis of the related assets as opposed to being recorded in tax expense. In 2012 the law changed and the grant option is no longer available; as such, the accumulated deferred ITC generated in 2012 was recorded as a noncurrent deferred tax liability, which was included in Deferred Income Taxes and ITC on PSEG's and PSE&G's Consolidated Balance Sheets as of December 31, 2012.
PSEG recorded the following amounts related to its unrecognized tax benefits, which was primarily comprised of amounts recorded for Power, PSE&G and Energy Holdings:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On June 26, 2009, September 15, 2008 and December 17, 2007, PSEG made tax deposits with the IRS in the amount of $140 million, $80 million and $100 million, respectively, to defray potential interest costs associated with disputed tax assessments associated with certain lease investments (see Note 13. Commitments and Contingent Liabilities). The $320 million of deposits were fully refundable and were recorded in Current Accrued Taxes on PSEG’s Consolidated Balance Sheets in the years in which the deposits were made, but are not reflected in the amounts shown above. On January 31, 2012, PSEG signed a specific matter closing agreement with the IRS regarding this matter. Based on this agreement, these deposits have been applied against tax and interest due pursuant to the closing agreement.
PSEG and its subsidiaries include all accrued interest and penalties related to uncertain tax positions required to be recorded, as income tax expense. Interest and penalties on uncertain tax positions were as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
It is reasonably possible that total unrecognized tax benefits will decrease within the next twelve months due to either agreements with various taxing authorities upon audit or the expiration of the Statute of Limitations. These potential decreases are as follows:
As a result of a change in accounting method for the capitalization of indirect costs, PSEG reduced the net amount of its uncertain tax positions (including interest) by $97 million, approximately $43 million of which related to PSE&G. Pursuant to an agreement signed with the IRS on January 31, 2012, this matter is settled and there will be a resulting increase in uncertain tax positions within the next twelve months. These amounts are not included in the table above.
A description of income tax years that remain subject to examination by material jurisdictions, where an examination has not already concluded are:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 21. Earnings Per Share (EPS) and Dividends
EPS
Diluted EPS is 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 or vesting of restricted stock awards granted under our stock compensation plans and upon payment of performance units or restricted stock units. The following table shows the effect of these stock options, performance units and restricted stock units on the weighted average number of shares outstanding used in calculating diluted EPS:
There were approximately 1.8 million, 1.8 million and 1.9 million stock options excluded from the weighted average common shares used for diluted EPS due to their antidilutive effect for the years ended December 31, 2012, 2011 and 2010, respectively. No other stock options had an antidilutive effect for the years ended December 31, 2012, 2011 or 2010.
Dividends
On February 19, 2013, PSEG’s Board of Directors approved a $0.36 per share common stock dividend for the first quarter of 2013.
Note 22. Financial Information by Business Segment
Basis of Organization
PSEG’s operating segments are Power, PSE&G and Energy Holdings. The operating segments were determined by management in accordance with GAAP-Disclosures about Segments of an Enterprise and Related Information. These segments were determined based on how management measures performance based on segment Net Income, as illustrated in the following table, and how it allocates resources to each business.
See Note 1. Organization, Basis of Presentation and Summary of Significant Accounting Policies for additional information.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 energy, capacity and ancillary services into the markets for these products. Power also enters into contracts for energy, capacity, FTRs, 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.
PSE&G
PSE&G earns revenues 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 the 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
Energy Holdings earns revenues from its solar generation projects and its portfolio of passive investments primarily consisting of domestic leveraged leases. Gains and losses on sales of the lease investments are typically recognized in revenues. Energy Holdings also has equity method generation projects. Earnings from these projects are presented below Operating Income.
Other
Other activities include amounts applicable to PSEG (parent corporation), Services 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 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 23. Related-Party Transactions. The net losses primarily relate to financing and certain administrative and general costs.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 23. 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.
Power
The financial statements for Power include transactions with related parties presented as follows:
PSE&G
The financial statements for PSE&G include transactions with related parties presented as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(A)
PSE&G has a full requirements contract with Power to meet the supply requirements of default service gas customers. This long-term contract was for an initial period which extended through March 31, 2012 and continues on a year-to-year basis thereafter, unless terminated by either party with a one year notice. Power has also entered into contracts to supply energy, capacity and ancillary services to PSE&G through the BGS auction process.
(B)
Services provides and bills administrative services to Power and PSE&G at cost. In addition, Power and PSE&G have other payables to Services, including amounts related to certain common costs, such as pension and OPEB costs, which Services pays on behalf of each of the operating companies.
(C)
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.
(D)
Power’s short-term loans with PSEG are for working capital and other short-term needs. Interest Income and Interest Expense relating to these short-term funding activities were immaterial.
(E)
Power and PSE&G have advanced working capital to Services. The amounts are included in Other Noncurrent Assets on Power’s and PSE&G’s Consolidated Balance Sheets.
(F)
In 2008, the BPU issued a decision that certain BGS suppliers will be reimbursed for the cost they incurred above $300 per Solar Renewable Energy Certificate (SREC) during the period June 1, 2008 through May 31, 2010. The BPU order further provided that the excess cost may be passed on to ratepayers. Following an appeal, on March 10, 2011, the New Jersey Supreme Court reversed and remanded the BPU’s 2008 order. On May 1, 2012, the BPU reaffirmed its earlier decision and on December 19, 2012, approved a settlement that defines requirements for review and reimbursement of incremental SREC costs to certain BGS suppliers. PSE&G has estimated and accrued a total liability for the excess SREC cost of $17 million as of December 31, 2012 and 2011, including approximately $7 million for Power’s share which is included in PSE&G’s Accounts Payable-Affiliated Companies as of December 31, 2012 and 2011. Under current guidance, Power is unable to record the related intercompany receivable on its Consolidated Balance Sheet. As a result, PSE&G’s liability to Power is not eliminated in consolidation and is included in Other Current Liabilities on PSEG’s Consolidated Balance Sheet as of December 31, 2012 and 2011.
Note 24. Selected Quarterly Data (Unaudited)
The information shown in the following tables, in the opinion of PSEG, Power and PSE&G includes all adjustments, consisting only of normal recurring accruals, necessary to fairly present such amounts.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 25. Guarantees of Debt
Power’s Senior Notes are fully and unconditionally and jointly and severally guaranteed by its subsidiaries, PSEG Fossil LLC, PSEG Nuclear LLC and PSEG Energy Resources & Trade LLC. The following table presents financial information for the guarantor subsidiaries as well as Power’s non-guarantor subsidiaries as of December 31, 2012 and 2011 and for the years ended December 31, 2012, 2011 and 2010.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
ITEM 9A. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
PSEG, Power and PSE&G
We have established and maintain disclosure controls and procedures as defined under Rule 13a-15(e) and 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended (Exchange Act) that are designed to provide reasonable assurance that information required to be disclosed in the reports that are filed or submitted under the Exchange Act is recorded, processed, summarized and reported and is accumulated and communicated to the Chief Executive Officer and Chief Financial Officer of each respective company, as appropriate, by others within the entities to allow timely decisions regarding required disclosure. We have established a disclosure committee which includes several key management employees and which reports directly to the Chief Financial Officer and Chief Executive Officer of each respective company. The committee monitors and evaluates the effectiveness of 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, have concluded that disclosure controls and procedures at each respective company were effective at a reasonable assurance level as of the end of the period covered by the report.
Internal Controls
PSEG, Power and PSE&G
We have conducted assessments of our internal control over financial reporting as of December 31, 2012, as required by Section 404 of the Sarbanes-Oxley Act, using the framework promulgated by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. Management’s reports on PSEG’s, Power’s and PSE&G’s internal control over financial reporting are included on pages 173, 174 and 175, respectively. The Independent Registered Public Accounting Firm’s report with respect to the effectiveness of PSEG’s internal control over financial reporting is included on page 176. Management has concluded that internal control over financial reporting is effective as of December 31, 2012.
We continually review our disclosure controls and procedures and make changes, as necessary, to ensure the quality of their financial reporting. There have been no changes in internal control over financial reporting that occurred during the fourth quarter of 2012 that have materially affected, or are reasonably likely to materially affect, each registrant’s internal control over financial reporting.
ITEM 9B.
ITEM 9B. OTHER INFORMATION
None.
MANAGEMENT REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING-PSEG
Management of Public Service Enterprise Group (PSEG) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).
PSEG’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSEG’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSEG are being made only in accordance with authorizations of PSEG’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSEG’s assets that could have a material effect on the financial statements.
In connection with the preparation of PSEG’s annual financial statements, management of PSEG has undertaken an assessment, which includes the design and operational effectiveness of PSEG’s internal control over financial reporting using the framework promulgated by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on the assessment performed, management has concluded that PSEG’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSEG’s financial reporting and the preparation of its financial statements as of December 31, 2012 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2012.
PSEG’s external auditors, Deloitte & Touche LLP, have audited PSEG’s financial statements for the year ended December 31, 2012 included in this annual report on Form 10-K and, as part of that audit, have issued a report on the effectiveness of PSEG’s internal control over financial reporting, a copy of which is included in this annual report on Form 10-K.
MANAGEMENT REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING-Power
Management of PSEG Power LLC (Power) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors of its parent, Public Service Enterprise Group Incorporated, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).
Power’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of Power’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of Power are being made only in accordance with authorizations of Power’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Power’s assets that could have a material effect on the financial statements.
In connection with the preparation of Power’s annual financial statements, management of Power has undertaken an assessment, which includes the design and operational effectiveness of Power’s internal control over financial reporting using the framework promulgated by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on the assessment performed, management has concluded that Power’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of Power’s financial reporting and the preparation of its financial statements as of December 31, 2012 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2012.
MANAGEMENT REPORT ON INTERNAL CONTROL OVER
FINANCIAL REPORTING-PSE&G
Management of Public Service Electric and Gas Company (PSE&G) is responsible for establishing and maintaining effective internal control over financial reporting and for the assessment of the effectiveness of internal control over financial reporting. As defined by the SEC in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and implemented by the company’s management and other personnel, with oversight by the Audit Committee of the Board of Directors of its parent, Public Service Enterprise Group Incorporated, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America (generally accepted accounting principles).
PSE&G’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of PSE&G’s assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of PSE&G are being made only in accordance with authorizations of PSE&G’s management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of PSE&G’s assets that could have a material effect on the financial statements.
In connection with the preparation of PSE&G’s annual financial statements, management of PSE&G has undertaken an assessment, which includes the design and operational effectiveness of PSE&G’s internal control over financial reporting using the framework promulgated by the Committee of Sponsoring Organizations of the Treadway Commission, commonly referred to as “COSO”. The COSO framework is based upon five integrated components of control: control environment, risk assessment, control activities, information and communications and ongoing monitoring.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projection of any evaluation of effectiveness to future periods is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Based on the assessment performed, management has concluded that PSE&G’s internal control over financial reporting is effective and provides reasonable assurance regarding the reliability of PSE&G’s financial reporting and the preparation of its financial statements as of December 31, 2012 in accordance with generally accepted accounting principles. Further, management has not identified any material weaknesses in internal control over financial reporting as of December 31, 2012.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and Board of Directors of
Public Service Enterprise Group Incorporated:
We have audited the internal control over financial reporting of Public Service Enterprise Group Incorporated and subsidiaries (the “Company”) as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management Report on Internal Control Over Financial Reporting-PSEG. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and consolidated financial statement schedule listed in the Index at Item 15(B)(a) as of and for the year ended December 31, 2012 of the Company and our report dated February 25, 2013 expressed an unqualified opinion on those consolidated financial statements and consolidated financial statement schedule.
/s/ DELOITTE & TOUCHE LLP
Parsippany, New Jersey
February 25, 2013
PART III
ITEM 10.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE
GOVERNANCE
Executive Officers
PSEG
Power and PSE&G
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
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 2013 Annual Meeting of Stockholders, and (ii) compliance with 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 8, 2013 and which information set forth under said heading is incorporated herein by this reference thereto.
Power and PSE&G
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
Code of Ethics
Our Standards of Integrity (Standards) is a code of ethics applicable to us and our subsidiaries. The Standards are an integral part of our business conduct compliance program and embody our commitment to conduct operations in accordance with the highest legal and ethical standards. The Standards apply to all of our directors and employees (including Power’s, PSE&G’s,
Energy Holdings’ and Services’ respective principal executive officer, principal financial officer, principal accounting officer or Controller and persons performing similar functions). Each such person is responsible for understanding and complying with the Standards. The Standards are posted on our website, www.pseg.com/info/investors/governance/document.jsp. We will send you a copy on request.
The Standards establish a set of common expectations for behavior to which each employee must adhere in dealings with investors, customers, fellow employees, competitors, vendors, government officials, the media and all others who may associate their words and actions with us. The Standards have been developed to provide reasonable assurance that, in conducting our 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.
We will post on our website, www.pseg.com/info/investors/governance/document.jsp:
•
Any amendment (other than one that is technical, administrative or non-substantive) that we adopt to our Standards; and
•
Any grant by us of a waiver from the Standards that applies to any director, principal executive officer, principal financial officer, principal accounting officer or Controller, or persons performing similar functions, for us or our direct subsidiaries noted above, and that relates to any element enumerated by the SEC.
In 2012, we did not grant any waivers to the Standards.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
PSEG
The information required by Item 11 of Form 10-K is set forth in PSEG’s definitive Proxy Statement for the 2013 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 8, 2013 and such information set forth under such heading is incorporated herein by this reference thereto.
Section 16 Beneficial Ownership Reporting Compliance
During 2012, none of our directors or executive officers was late in filing a Form 3, 4 or 5 in accordance with the requirements of Section 16(a) of the Securities Exchange Act of 1934, as amended, with regard to transactions involving our Common Stock, with the exception of Susan Tomasky, one of our Directors. Ms. Tomasky filed one late report on Form 3 to report any ownership by her of our Common Stock at the time of her election to the Board. At that time, Ms. Tomasky did not own any of our Common Stock.
Power and PSE&G
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDERS MATTERS
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 2013 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 8, 2013, and such information set forth under such heading is incorporated herein by this reference thereto.
For information relating to securities authorized for issuance under equity compensation plans, see Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Power and PSE&G
Omitted pursuant to conditions set forth in General Instruction I of Form 10-K.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND
DIRECTOR INDEPENDENCE
PSEG
The information required by Item 13 of Form 10-K is set forth under the heading “Transactions with Related Persons” in PSEG’s definitive Proxy Statement for the 2013 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 8, 2013 and such information set forth under such heading is incorporated herein by this reference thereto.
Power and PSE&G
Omitted pursuant to conditions set forth in General Instruction I of Form 10K.
ITEM 14.
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 2012 and 2011” in PSEG’s definitive Proxy Statement for the 2013 Annual Meeting of Stockholders which definitive Proxy Statement is expected to be filed with the SEC on or about March 8, 2013. Such information set forth under such heading is incorporated herein by this reference hereto.
PART IV
ITEM 15.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(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, 2012 and 2011 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Stockholders’ Equity for the three years ended December 31, 2012 on pages 74 through 79.
b.
PSEG Power LLC’s Consolidated Balance Sheets as of December 31, 2012 and 2011 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Capitalization and Member’s Equity for the three years ended December 31, 2012 on pages 80 through 85.
c.
Public Service Electric and Gas Company’s Consolidated Balance Sheets as of December 31, 2012 and 2011 and the related Consolidated Statements of Operations, Comprehensive Income, Cash Flows and Common Stockholders’ Equity for the three years ended December 31, 2012 on pages 86 through 91.
(B) The following documents are filed as a part of this report:
a.
PSEG's Financial Statement Schedules:
Schedule II-Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2012 (page 189).
b.
Power's Financial Statement Schedules:
Schedule II-Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2012 (page 189).
c.
PSE&G's Financial Statement Schedules:
Schedule II-Valuation and Qualifying Accounts for each of the three years in the period ended December 31, 2012 (page 190).
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:
(1)
Filed as Exhibit 3.1a with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120 on May 4, 2007 and incorporated herein by this reference.
(2)
Filed as Exhibit 3.1 with Current Report on Form 8-K, File No. 001-09120 on November 18, 2009 and incorporated herein by this reference.
(3)
Filed as Exhibit 3.1b with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120 on May 4, 2007 and incorporated herein by this reference.
(4)
Filed as Exhibit 3.1c with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-09120 on May 4, 2007 and incorporated herein by this reference.
(5)
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.
(6)
Filed as Exhibit 10.1 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, File No. 001-09120 on November 1, 2011 and incorporated herein by this reference.
(7)
Filed as Exhibit 10.2 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, File No. 001-09120 on November 1, 2011 and incorporated herein by this reference.
(8)
Filed as Exhibit 10a(4) with Annual Report on Form 10-K for the year ended December 31, 2007, File Nos. 001-09120 on February 28, 2008 and 000-49614, and incorporated herein by reference.
(9)
Filed as Exhibit 10.5 with Quarterly Report on Form 10-Q for the quarter ended September 20, 2011, File No. 001-09120 on November 1, 2011 and incorporated herein by this reference.
(10)
Filed with Registration Statement on Form S-8, File No. 333-106330 filed on June 20, 2003 and incorporated herein by this reference.
(11)
Filed as Exhibit 10.6 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, File No. 001-09120 on November 1, 2011 and incorporated herein by this reference.
(12)
Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2011, File No. 001-09120 on November 1, 2011 and incorporated herein by this reference.
(13)
Filed as Exhibit 10 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2002, File No. 001-09120, on November 4, 2002 and incorporated herein by this reference.
(14)
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.
(15)
Filed as Exhibit 10a(11) with Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-09120, on February 26, 2009 and incorporated herein by this reference.
(16)
Filed as Exhibit 99 with Current Report on Form 8-K, File Nos. 001-09120, 000-49614 and 001-00973 on December 22, 2008 and incorporated herein by this reference.
(17)
Filed as Exhibit 10a(14) with Annual Report on Form 10-K, for the year ended December 31, 2009, File No. 001-09120 on February 25, 2010 and incorporated herein by reference.
(18)
Filed as Exhibit 10 with Quarterly Report on Form 10-Q, File No. 001-00973 on May 6, 2009 and incorporated herein by reference.
(19)
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.
(20)
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.
(21)
Filed as Exhibit 10.1 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, File No. 001-09120 on May 5, 2011 and incorporated herein by this reference.
(22)
Filed as Exhibit 10.1 with Current Report on Form 8-K, File No. 001-09120 on February 19, 2009 and incorporated herein by reference.
(23)
Filed as Exhibit 3.1 to Registration Statement on Form S-4, No. 333-69228 filed on September 10, 2001 and incorporated herein by this reference.
(24)
Filed as Exhibit 3.2 to Registration Statement on Form S-4, No. 333-69228 filed on September 10, 2001 and incorporated herein by this reference.
(25)
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.
(26)
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.
(27)
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.
(28)
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.
(29)
Filed as Exhibit 3.10 to Registration Statement on Form S-3, No. 333-105704 filed on May 30, 2003 and incorporated herein by this reference.
(30)
Filed as Exhibit 4.1 to Registration Statement on Form S-4, No. 333-69228 filed on September 10, 2001 and incorporated herein by this reference.
(31)
Filed as Exhibit 4.7 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 000-49614, on May 15, 2002 and incorporated herein by this reference.
(32)
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.
(33)
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.
(34)
Filed as Exhibit 3a(3) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(35)
Filed as Exhibit 3a(4) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(36)
Filed as Exhibit 3a(5) on Form 8-A, File No. 001-00973, on February 4, 1994 and incorporated herein by this reference.
(37)
Filed as Exhibit 3.3 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2007, File No. 001-00973 on May 4, 2007 and incorporated herein by this reference.
(38)
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.
(39)
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.
(40)
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.
(41)
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.
(42)
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.
(43)
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.
(44)
Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on June 1, 1991 and incorporated herein by this reference.
(45)
Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on December 1, 1993 and incorporated herein by this reference.
(46)
Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on December 1, 1993 and incorporated herein by this reference.
(47)
Filed as Exhibit 4(i) on Form 8-A, File No. 001-00973 on February 4, 1994 and incorporated herein by this reference.
(48)
Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on March 15, 1994 and incorporated herein by this reference.
(49)
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.
(50)
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.
(51)
Filed as Exhibit 4a(2) on Form 8-A, File No. 001-00973 on January 26, 1996 and incorporated herein by this reference.
(52)
Filed as Exhibit 4a(3) on Form 8-A, File No. 001-00973 on January 26, 1996 and incorporated herein by this reference.
(53)
Filed as Exhibit 4 on Form 8-A, File No. 001-00973 on May 15, 1998 and incorporated herein by this reference.
(54)
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.
(55)
Filed as Exhibit 4a(98) with Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-00973 on February 25, 2004 and incorporated herein by this reference.
(56)
Filed as Exhibit 4a(99) with Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-00973 on February 25, 2004 and incorporated herein by this reference.
(57)
Filed as Exhibit 4a(100) with Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-00973 on February 25, 2004 and incorporated herein by this reference.
(58)
Filed as Exhibit 4a(101) with Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-00973 on February 25, 2004 and incorporated herein by this reference.
(59)
Filed as Exhibit 4a(102) with Annual Report on Form 10-K for the year ended December 31, 2003, File No. 001-00973 on February 25, 2004 and incorporated herein by this reference.
(60)
Filed as Exhibit 4 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2004, File No. 001-00973 on August 3, 2004 and incorporated herein by this reference.
(61)
Filed as Exhibit 4a(25) with Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-00973 on March 1, 2005 and incorporated herein by this reference.
(62)
Filed as Exhibit 4a(26) with Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-00973 on March 1, 2005 and incorporated herein by this reference.
(63)
Filed as Exhibit 4a(27) with Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-00973 on March 1, 2005 and incorporated herein by this reference.
(64)
Filed as Exhibit 4a(28) with Annual Report on Form 10-K for the year ended December 31, 2004, File No. 001-00973 on March 1, 2005 and incorporated herein by this reference.
(65)
Filed as Exhibit 4a(28) with Annual Report on Form 10-K for the year ended December 31, 2007, File No. 001-00973, on February 28, 2008 and incorporated herein by this reference.
(66)
Filed as Exhibit 4a(29) with Annual Report on Form 10-K, for the year ended December 31, 2009, File No. 001-00973 on February 25, 2010 and incorporated herein by reference.
(67)
Filed as Exhibit 4a(30) with Annual Report on Form 10-K, for the year ended December 31, 2009, File No. 001-00973 on February 25, 2010 and incorporated herein by reference.
(68)
Filed as Exhibit 4 with Quarterly Report on Form 10-Q for the quarter ended September 30, 2010, File No. 001-00973 on October 29, 2010 and incorporated herein by reference.
(69)
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.
(70)
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.
(71)
Filed as Exhibit 10.2 with Current Report on Form 8-K, File No. 001-00973 on February 19, 2009 and incorporated herein by reference.
(72)
Filed as Exhibit 10.2 with Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, File No. 001-09120 on May 5, 2011 and incorporated herein by this reference.
(73)
Filed as Exhibit 10.1 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, File No. 001-09120 on August 3, 2011 and incorporated herein by this reference.
(74)
Filed as Exhibit 10.2 with Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, File No. 001-09120 on August 3, 2011 and incorporated herein by this reference.
(75)
Filed as Exhibit 10a(7) with Annual Report on Form 10-K for the year ended December 31, 2011, File No. 001-09120 on February 27, 2012.
(76)
Filed as Exhibit 10a(19) with Annual Report on Form 10-K for the year ended December 31, 2011, File No. 001-09120 on February 27, 2012.
(77)
Filed as Exhibit 10a(20) with Annual Report on Form 10-K for the year ended December 31, 2011, File No. 001-09120 on February 27, 2012.
(78)
Filed as Exhibit 10 with Current Report on Form 8-K, File No. 001-09120 on November 26, 2012 and incorporated herein by reference.
PUBLIC SERVICE ENTERPRISE GROUP INCORPORATED
Schedule II-Valuation and Qualifying Accounts Years Ended December 31, 2012-December 31, 2010
(A)
Accounts Receivable written off.
(B)
Reduced reserve to appropriate level and to remove obsolete inventory.
(C)
Valuation Allowance written off.
PSEG POWER LLC
Schedule II-Valuation and Qualifying Accounts Years Ended December 31, 2012-December 31, 2010
(A)
Reduced reserve to appropriate level and to remove obsolete inventory.
PUBLIC SERVICE ELECTRIC AND GAS COMPANY
Schedule II-Valuation and Qualifying Accounts Years Ended December 31, 2012-December 31, 2010
(A)
Accounts Receivable written off.
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below:
Term Phrase/Description
Base load
Minimum amount of electric power delivered or required over a given period of time at a constant rate, this is the level of demand that is seen as a minimum during a 24-hour day
BGS
Basic Generation Service
PSE&G is required to provide BGS for all customers in New Jersey who are not supplied by a TPS.
BGS-Fixed Price
Basic Generation Service-Fixed Price
Seasonally adjusted fixed prices charged for a three-year term for electric supply service to smaller industrial and commercial customers and residential customers who are not supplied by a TPS
BGSS
Basic Gas Supply Service
Mechanism approved by the BPU for NJ utilities to recover all commodity costs related to supplying gas to residential customers
BPU
New Jersey Board of Public Utilities
Agency responsible for regulating public utilities doing business in New Jersey
Capacity
Amount of electricity that can be produced by a specific generating facility
CAA
Clean Air Act
Combined Cycle
A method of generation whereby electricity and process steam are produced from otherwise lost waste heat exiting from one or more combustion turbines. The exiting heat is routed to a conventional boiler or to a heat recovery steam generator for use by a steam turbine in the production of electricity
Competition Act
Electric Discount and Energy Competition Act
New Jersey’s 1999 Electric Utility Restructuring Legislation
Congestion
Condition when the available capacity of a transmission line is being closely approached (or exceeded) by the electric power trying to go through it; at such times, alternative power line pathways (or local generators near the load) must be used instead
Distribution
The delivery of electricity to the retail customer’s home, business or industrial facility through low voltage distribution lines
EDC
Electric Distribution Company
A company that owns the power lines and equipment necessary to deliver purchased electricity to the end user.
Energy Holdings
PSEG Energy Holdings L.L.C.
EPA
U.S. Environmental Protection Agency
FASB
Financial Accounting Standards Board
A private, not-for-profit organization whose primary purpose, as designated by the SEC, is to develop accounting standards for public companies in the U.S.
FERC
U.S. Federal Energy Regulatory Commission
Forward contracts
A customized, non-exchange traded contract in which the buyer is obligated to deliver a specified amount of a commodity with a predetermined price formula on a specified future date, at which time payment is due in full
GAAP
Generally Accepted Accounting Principles
Standard framework of guidelines issued by the FASB for financial accounting used in the U.S.
GHG
Greenhouse gas emissions (including carbon dioxide, methane, nitrous oxide, ozone, and chlorofluorocarbon) that trap the heat of the sun in the earth’s atmosphere, increasing the mean global surface temperature of the earth
Term Phrase/Description
Grid
A system of interconnected power lines and generators that is managed so that the generators are dispatched as needed to meet the electricity requirements of the customers connected to the grid at various points
Hedging
Entering into a contract or transaction designed to reduce exposure to various risks, such as changes in market prices
Hope Creek
Hope Creek Nuclear Generating Station
ISO
Independent System Operator
An independent, regulated entity established to manage a regional electric transmission system in a non-discriminatory manner and to help ensure the safety and reliability of the bulk of the power system
ITC
Investment Tax Credit
A credit against income taxes, usually computed as a percent of the cost of investment in certain types of assets
LCAPP
Long-Term Capacity Agreement Pilot Program
A program established in January 2011 which provides for up to 2,000 MW of subsidized base load or mid-merit electric power generation in New Jersey.
Lifeline Program
A New Jersey social program for utility assistance that offers $225 per year to persons who meet the eligibility requirements
Load
Amount of electric power delivered or required at any specific point or points on a system. The requirement originates at the energy-consuming equipment of consumers.
MBR
Market Based Rates
Electric service prices determined in an open market system of supply and demand under which the price is set solely by agreement as to what a buyer will pay and a seller will accept
MGP
Manufactured Gas Plant
NDT
Nuclear Decommissioning Trust
ISO-NE
New England Power Pool
An ISO comprised of an alliance of approximately 100 utility companies who manage and direct all major energy production and transmission in the New England states
NJDEP
New Jersey Department of Environmental Protection
NRC
U.S. Nuclear Regulatory Commission
NUG
Non-Utility Generation
Power produced by independent power producers, exempt wholesale generators and other companies that have been exempted from traditional utility regulation
OPEB
Other Postretirement Benefits
Benefits other than pensions payable to former employees
Outage
The period during which a generating unit, transmission line, or other facility is out of service due to scheduled (planned) or unscheduled maintenance
Peach Bottom
Peach Bottom Atomic Power Station
Term Phrase/Description
PJM
PJM Interconnection, L.L.C.
A regional transmission organization that coordinates the movement of wholesale electricity in all or parts of 13 northeastern states and the District of Columbia
Power
PSEG Power LLC
Power Pool
An association of two or more interconnected electric systems having an agreement to coordinate operations and planning for improved reliability and efficiencies
PRP
Potentially Responsible Parties
PSE&G
Public Service Electric and Gas Company
PSEG
Public Service Enterprise Group Incorporated
Renewable Energy
Energy derived from resources that are regenerative or that cannot be depleted (i.e. moving water (hydro, tidal and wave power), thermal gradients in ocean water, biomass, geothermal energy, solar energy, and wind energy)
Regulatory Asset
Costs deferred by a regulated utility company in accordance with SFAS 71
Regulatory Liability
Costs recognized by a regulated utility company in accordance with SFAS 71
RGGI
Regional Greenhouse Gas Initiative
The first mandatory, market-based effort in the U. S. to reduce greenhouse gas emissions; states will sell emission allowances through auctions and invest proceeds in consumer benefits: energy efficiency, renewable energy, and other clean energy technologies
RMR
Reliability-Must-Run
Designation of a power plant whose output is needed to maintain local reliability regardless of its operating cost or market price
RPM
Reliability Pricing Model
A process for pricing generation capacity based on overall system reliability requirements; using multi-year forward auctions, participants could bid capacity in the form of generation, demand response, or transmission to meet reliability needs by location and/or an ISO market
Salem
Salem Nuclear Generating Station
SBC
Societal Benefits Charge
SEC
U.S. Securities and Exchange Commission
Services
PSEG Services Corporation
Spill Act
New Jersey Spill Compensation and Control Act
TPS
Third Party Supplier
Transmission
The high-voltage wires and networks that move electricity through states and regions in large quantities -- from power plants where it is produced, to the distribution networks that deliver it to homes and businesses.
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/ RALPH IZZO
Ralph Izzo
Chairman of the Board, President and
Chief Executive Officer
Date: February 25, 2013
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.
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/ WILLIAM LEVIS
William Levis
President and
Chief Operating Officer
Date: February 25, 2013
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.
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 ELECTRIC AND GAS COMPANY
By:
/s/ RALPH LAROSSA
Ralph LaRossa
President and Chief Operating Officer
Date: February 25, 2013
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.
EXHIBIT INDEX
The following documents are filed as a part of this report: