CHAPTER EIGHT: COST/BENEFIT CONSIDERATIONS

8.0 Introduction

This chapter examines issues related to the existing costs and benefits of the current structure of Nebraska' s electric industry, and the potential costs and benefits for restructuring of the industry to establish retail competition. Current costs and benefits are known, quantifiable, and reflected in existing operations and consumer bills. Estimated costs and benefits of a transition to a system of retail competition need to be based on examination of costs and recent experiences of other states and specific transition needs in Nebraska. While a precise comparison of costs and benefits is beyond the scope of this study, it is possible to illustrate the types and the relative magnitude of comparative costs and benefits to provide perspective for policy determinations.

The chapter begins with an examination of wholesale power costs and an illustration of the comparative costs and benefits of Nebraska's current utility system. It then provides an extensive examination of transition costs. It is significant to note that while there is a potential for stranded cost on two generating plants, on a statewide basis Nebraska has no net stranded cost; a measure of the efficiency of the state's consumer-owned systems. The chapter also includes discussion of tax revenues and methods of collection in a system of retail competition. It concludes with a summary of recommendations.

Baseline Costs and Benefits of Nebraska's Present Electric Utility Industry

Just as Nebraska's framework for law, governance, regulation and taxation support a monopoly structure of consumer-owned systems, the economic underpinning of the Nebraska systems is aimed at non-profit delivery of electricity. While a range of benefits that include local control, consumer equity, stability in pricing and costs, and integration with local planning may be considered among the benefits of consumer-owned systems, the bottom line is the price of service delivery.

Table 8-1

Nebraska's electric systems currently provide among the lowest electric rates in the nation. As discussed in Chapter 3, the state's comparative position in terms of electric prices remained the same from 1995 though 1997. The average retail price for Nebraska's commercial consumers was the 6th lowest in the nation (5.46 cents/kilowatt hour); industrial consumers were the 7th lowest (3.61 cents/kilowatt hour); residential consumers were the 9th lowest (6.38 cents per kilowatt hour).

Proponents of competitive retail markets reason that competition can bring about cost reductions and innovation in technology and services. While this reasoning may apply effectively to high-cost states, it does not address Nebraska's current low-cost situation. And innovation in technology and services would need to provide improved efficiencies and benefits, and not merely additional marketing opportunities with added costs.

A transition to retail competition would need to provide assured savings for all consumers. In high-cost states that have established retail competition, a guarantee of savings for all consumers has been achieved by a mandatory reduction of state regulated rates. In Nebraska, however, low non-profit, cost-of-service rates do not provide a margin for mandatory reductions. Any reduction in rates related to competition would have to come from the cost of power supply.

Anticipated Wholesale Power Costs In Nebraska and the MAPP Region

As discussed in Chapter 5, estimates of the change in retail price of electricity in Nebraska as result of retail competition vary widely. The Clinton Administration's 1999 Comprehensive Electricity Competition Act calculates that Nebraska's average retail price would decline by 0.5 to 1.0 cents/kWh by the year 2010. The Natural Gas Supply Association study conducted by Science Applications International Corporation (SAIC) in 1998 estimated that the retail price of electricity in Nebraska would increase from 5.2 cents per kilowatt hour in 1996 to 5.5 cents in 2015 as result of retail competition. Applying the Administration's and the SAIC estimates to the Nebraska retail energy sales in 1995 produces the following dollar estimates of changes of electricity prices in Nebraska as a result of retail competition:

Table 8-2

The Administration's estimate indicates a decrease of a 9.1 percent to 18.2 percent in total 1995 retail electric revenues of $1,101,549,000; the SAIC study indicates an increase of 5.4 percent.

These estimates do not account for particular groups of consumers that may be winners or losers in a competitive retail environment, a concern for small business and residential and rural consumers. A third study undertaken by USDA indicated losses for these consumers and the need for a "safety net."

As discussed in Chapter 5, a study of Nebraska's current and projected wholesale power costs was undertaken to develop a more detailed assessment of the possibility of losses or gains due to retail competition.

Chart 5-1 (repeated below) shows the projected paths of wholesale power costs in Nebraska and the MAPP region. It indicates lower wholesale costs for Nebraska in scenarios with high cost assumptions, and low-cost assumptions applied to Nebraska and the region. As noted in Chapter 5, Nebraska's lower wholesale power supply costs result from lower cost purchased power and lower cost power generated in the state. It includes factors such as: proximity to low-sulfur coal mines in Wyoming, preference power from WAPA, use of tax-exempt bonds to finance consumer-owned generating plants, and lower operating costs for generating plants.

Chart 5-1

The estimated prices begin at 2.77 cents per kilowatt hour for Nebraska and 3.11 cents for the region in 1999 and extend to a range of 2.62 (low cost assumptions) to 3.83 cents (high cost assumptions) for Nebraska in 2010; and 2.94 (low cost assumptions) to 4.30 cents (high cost assumptions) for the region in 2010. It is generally assumed that the same low and high cost assumptions can be applied to the state and the region.

Cost/Benefit Illustration

Although a full analysis would be needed for each individual system to determine the threshold for benefits from a competitive retail market, an illustration of the relative differences between costs of the current system and a competitive retail market on a statewide average is useful for state policy-makers, particularly in view of the fact that wholesale power costs are relatively the same for all Nebraska systems.

As noted above, Nebraska's wholesale power costs are currently below those of the region, and are anticipated to remain so for the next decade. The analysis assumes a difference in 1999 of 3.4 mills per kilowatt hour (Nebraska approximately 11 percent lower). It also assumes that the regional wholesale price represents the market price.

In order for savings to be achieved from the Limited or Open Access forms of retail competition, Nebraska's wholesale power costs would need to be higher than those of the region by an amount in which the cost differential would be sufficient to offset the added costs of a transition, plus the added costs of individual consumer transactions, plus a minimal margin of savings margin for consumers. If state policy is to assure savings for all consumers who would share the transition costs, then savings would need to be present for small as well as large customers.

Using small consumers as part of the threshold measure provides a sense of the magnitude by which wholesale power costs would need to change. The example is as follows:

More than 690,000 of Nebraska's 840,000 consumers used an average of less than 1,000 kilowatt hours per month in 1995. ( Residential consumer averaged 917 kilowatt hours.) If a consumer wanted a minimum of 5 percent savings on their total bill in order to switch to a new supplier as indicated by the survey discussed in Chapter 3, it would require a reduction of $3.22 per month for the 1000 kilowatt per hour consumer, equivalent to 3.22 mills per kilowatt hour. (For a total bill of $64.00 based on 1995 data.)

Transaction costs include marketing and billing for consumers. Marketing costs can vary widely, but even without marketing charges, costs to consumers for new billing is estimated by competitive power suppliers to range from $1 to $2 per month. This would be equivalent a minimum of 1 mill per kilowatt hour for the 1,000 kilowatt hour consumer.

Transition costs which are described at length in this chapter include stranded costs, start-up costs, and on-going costs of a new market system. The amount of total transaction costs assessed to a consumer may vary depending upon the timing and scope of the market established. A full estimate of transition costs is not possible without a number of policy determinations, but a partial assessment and conservative estimate could assume consumer education and support for a state regulatory structure alone would amount to a minimum of $1.60 per consumer, or $1.34 million per year. Public benefits discussed in Chapter 6 may also be added. In other states such programs have added one mill or more per kilowatt hour. These two elements would add a minimum charge of 1.1 mills per kilowatt hour.

Additional "access charges" that that may be necessary to allow the system to function reliably and to provide equitable compensation to distribution systems and control area operators; "safety net" charges, costs for possible stranded assets and a range of "start-up" costs would need to be estimated and added to the incremental costs of the competitive retail market.

Assuming only the 3.22 mills for consumer savings, 1 mill for transaction costs, and 1.1 mills for partial transition costs, retail competition would add approximately 5.3 mills to a consumer bill.

Thus, for the 1,000 kilowatt hour consumer, Nebraska would need to lose its 3.4 mill wholesale power supply advantage and have wholesale prices more than 15 percent above regional wholesale power supply costs in order to gain the necessary offset of 8.7 mills per kilowatt hour to produce a 5 percent savings on the total bill. Adding in full transition and transaction costs including possible "safety net" and other charges would drive the necessary offset higher.

The policy conclusion that may be drawn from this illustration is that retail competition cannot assure savings for the majority of Nebraska consumers until a substantial and decisive shift has occurred in the relative wholesale power costs of Nebraska and the region.

As recommended in Chapter 5, efforts should be undertaken by the Nebraska systems to maintain low wholesale power costs. Current and anticipated wholesale power costs compared to those of the region should be monitored on a regular basis. If efforts to maintain low wholesale power costs fail and cost differentials are evident for an extended period of time, resulting in necessary offsets and potential benefits from retail competition, implementation of retail competition might be undertaken.

If retail competition is to be implemented, detailed cost/benefit analyses weighing both economic and non-economic criteria would need to be assessed to allow a local system determination of whether or not to participate.

The cost/benefit or "threshold" analyses would need to be conducted with an examination of all transition and transaction costs. This requires understanding of the methods of valuation and recovery of transition costs and tax revenues in a manner that would protect Nebraska consumers. The sections below discuss those elements in detail.

Transition Costs Overview

States undertaking efforts to establish retail competition for power supply are faced with the problem of how to offset and pay for the costs of transition. Even the lowest cost states such as Nebraska will face this challenge, if a transition to retail competition is undertaken. Nebraska, with its all consumer-owned electric utility industry, has the opportunity to set certain policy precedents. Any legislation or regulations would require careful crafting to ensure preservation of the low costs and local control aspects of public power, while carrying out the environmental and financial commitments made by Nebraska's public power entities over the last 60 years.

The types of transition costs include existing costs, and new costs incurred for start-up and maintenance of new functions. Table 8-3 provides an overview of the categories of costs.

Table 8-3

Recovery of transition costs has become an accepted part of an industry's movement from regulation to competition. As noted in Table 8-3 transition costs in the electric industry typically include stranded costs, start-up costs and on-going costs. Policy-makers have provided for some recovery of transition costs in the deregulation of the telecommunications, natural gas, airline, railroad and trucking industries, and some of the costs were absorbed by shareholders. Most of these costs are already part of consumers. bills under regulated rates. Policy-makers have taken different approaches to recovery of transition costs in the various industries that have been deregulated, including direct government subsidies for maintenance of unprofitable services, compensation to displaced workers, special consumer charges and liberalized merger standards. The length of the transition cost-recovery period has also varied from industry to industry.

Stranded costs are one of the most challenging issues evolving from the restructuring of the electric utility industry. Stranded costs represent investments made and obligations incurred by a utility in a fully regulated environment that will not be recoverable in a fully competitive environment. Stranded costs include stranded assets, stranded liabilities and stranded benefits. Stranded costs must be addressed by local and state regulators, legislators, and utility executives. The Federal Energy Regulatory Commission ("FERC") in its Order 888 stated "the recovery of legitimate, prudent and verifiable stranded costs should be allowed", and found that this was "critical to the successful transition of the electric industry to be a competitive, open access environment." In the Clinton Administration's 1998 Comprehensive Electricity Competition Plan it states that the Administration "endorses the principle that utilities should be able to recover prudently incurred, legitimate and verifiable retail stranded costs that cannot be reasonably mitigated." Other observers have argued that recovery of stranded costs would inhibit the movement to competition, potentially distort price signals, and reward inefficient producers.

Fueling the debate is the sheer magnitude of the industry's estimated stranded costs which were valued in 1997 to be between $100 billion and $200 billion depending on assumptions related to future generation costs and the market level prices of electricity. With the market value of common equity for the entire electric utility industry at roughly $200 billion, the financial stakes are quite high. In 1995, Moody. s Investors Service analyzed data for 114 utilities representing more than 80 percent of the assets of all U. S. investor-owned electric utilities. They estimated that stranded costs could range from $50 billion to $300 billion, with the most likely value being $135 billion, equivalent to almost 90 percent of shareholder equity for these utilities. Moody's cited eight investor-owned utilities in the MAPP region that had estimated stranded costs of $632 million in their 1995 report. Moody. s did not include estimates for Nebraska utilities.

Among the largest category of potential stranded costs are those incurred in connection with the construction and operation of generating facilities. Research Data International estimated in 1996 that this category of costs would constitute $69 billion of the $200 billion in industry transition costs. Above market costs for heavily financed nuclear generation assets contributed $86 billion which is offset by a negative $17 billion in transition costs for those fossil and hydro assets with a market value higher than the current book value. Above market generation assets could include the net investment of in-service plants, construction work in progress, fuel inventories and fuel handling facilities, and associated materials and supplies. In addition to capital costs, this category could include plant retirement costs at the end of plant life. The costs associated with the decommissioning of nuclear plants and disposal of spent fuel are significant.

Not only is a great deal of money at stake, but that money is distributed unevenly across utilities, states and regions. Certain low-cost regions of the country (such as the Pacific Northwest) have almost no exposure to stranded costs, while other regions (such as California and the Northeast) face substantial problems. These amounts are subjective, dependent upon actions taken to mitigate the stranded costs, and the length of the transition period to competition over which the costs would be amortized.

As of June 1999, nineteen states have enacted legislation that ranges from general guidelines for an orderly transition to a more competitive market, to detailed outlines of market structure, transition processes and implementation procedures. In three other states, the utility commissions have issued orders for retail market restructuring. Most states that have addressed industry restructuring to date have allowed for the recovery of unmitigated, verifiable transition costs within the various categories and have required a difficult negotiation process to define what costs and how much will be included. The utilities in most states have been put at risk for some portion of the transition costs if those costs cannot be recovered during the defined period of transition to competition. The commitments made by utilities that could be potentially stranded in a competitive market include generation, transmission, fuel supply contracts, and other assets and obligations. Table 8-4 provides an overview of how states have acted on key components of transition costs:

Most states that have addressed restructuring have recognized the impact on utility employees, and have designed programs allowing for recovery of these costs through a transition charge. Costs in this category include relocation, retraining, early retirement and severance related expenses.

Stranded benefits include environmental compliance beyond that required by law, renewable energy programs, and special programs for low-income customers, and support for energy research and development. The costs in this category are current, not sunk. That is, these costs could be discontinued if the programs were stopped. However, the regulatory bodies in all states have considered the continuance of these programs to be instrumental to the success of the future market structure, and many states have provided for these costs through a non-bypassable charge on all users of the distribution system.

Table 8-4

The cost of consumer education regarding retail competition has emerged as a substantial transition charge. Most states have adopted provisions to inform electric consumers of the market changes and the options that will be available to them, and provided for recovery of the costs of such programs through a transition charge. In California, an $89 million statewide education program targeted all customers, with special emphasis on residential and small business consumers who may be the least knowledgeable about changes that are occurring within the industry.

Administrative and other costs will be incurred in the administration of retail competition. These include the cost to develop and implement the independent system operator (ISO) and power exchange (PX) organizations, programs for energy service providers to implement direct access and metering services, costs to develop and implement new unbundled billing systems, and power station monitoring systems for sales to the PX. In California, utilities were allowed to recover these types of costs over the four-year transition period. The three large IOU utilities have seen these costs escalate rapidly as delays and other unanticipated events occurred. They now anticipate that the costs in this category will be about $1 billion over a five-year period, with about half of the costs attributed to the ISO and PX.

For Nebraska, there are many lessons to be learned from the efforts to establish retail competition in other states. The pioneering states in this process have established trends that may or may not be appropriate for all states. Investor-owned utilities have fared well in the states where deregulation has occurred. Generous stranded cost provisions and securitization arranged to avoid litigation from stockholders and facilitate a transition have resulted in windfalls in some cases. High stranded costs and resultant low "standard offer prices" for continued service from utilities and have dampened the efforts of competitors to bid for power supply service to consumers. In such cases, residential and small commercial customers have yet to be offered a full opportunity to gain the benefits of retail competition. In Nebraska with its consumer-owned utility structure, retail competition would need to assure recovery of all costs from new suppliers, and continuing low-cost power supply.

In Nebraska, the customers are also the owners of the public power, municipal and rural cooperative systems, and would bear the full transition costs, just as they would pay these costs over the economic life of these assets in the current cost-based environment. However, the recapture of costs incurred in a cost-based environment should reflect equity among all customer-owners. The customers who caused the costs to be incurred in a cost-based environment should be the ones who pay those costs after transition to a market-based competitive system.

Recommendation: The primary policy principle for Nebraska would need to be assured, equitable gains for all consumers, and revenue-neutral or net-neutral impacts from the costs of a transition. This principle would need to be applied to the range of potential impacts that may include wholesale power costs, impact on Nebraska utility revenue, tax impacts on local and state government and other related areas.

The following text examines the elements of transition costs and tax implications in detail and outlines methods and recommendations for quantification and recovery.

8.5 Stranded Costs

It is significant to note that while Nebraska has potential stranded costs associated with its two nuclear plants, current low wholesale pricing indicates no net stranded cost on a statewide basis. Nevertheless, the amount of stranded cost depends on a variety of variable conditions such as market price for wholesale power and value of the potentially stranded asset. Timing of the establishment of a competitive retail market can also affect the level of stranded costs. Generally extension of a market open date allows for greater amortization of the potentially stranded asset and reduction of stranded cost. Recovery would take place by the systems that include the costs of the stranded asset in their rate base. Despite the relatively positive condition of Nebraska on a statewide basis, full policy for stranded cost quantification and recovery is essential to policy development for a transition to retail competition. Discussion of these elements and recommendations are provided below.

8.5.1 Stranded Assets

Stranded assets are primarily items that are included in rate base such as generating, transmission and related assets, as well as other items such as conservation program investments, or deferred production costs not recovered at the time of transition to competition. The stranded costs result from the difference between the investment cost and the market value of that asset presently or in the future. The investment cost is the net book value, while the market value is the expected present value of the net revenues the asset is expected to generate over its remaining life. While the net book value is exact, as noted above, the market value can be impacted by a number of factors including: volatility of future market prices; supply and demand; future revenues generated by the asset; and, future operating performance, expected costs and expected life of the asset. Because these factors will change over time, the market value of the asset will be higher or lower in the future.

Generation Assets: Generation assets represent a significant investment. As reported in the L. R. 455 Phase I report the Nebraska electric utilities had a depreciated generation investment of $1.64 billion at the end of 1995 comprised of fossil, nuclear and hydro facilities.

Each type of generation carries a different level of risk in a competitive environment. Utilities with high cost generation, especially nuclear plants, are particularly vulnerable. Nebraska has two nuclear plants . Cooper and Fort Calhoun with potential stranded costs.

Table 8-5

State regulatory bodies have handled recovery of above-market utility generation assets in differing ways. In order to recover full stranded asset costs, some states have required divestiture of a portion, or in certain cases, 100 percent of non-nuclear generating assets held within the utility's service area. California required its investor-owned utilities to divest 50 percent of non-nuclear generating assets; Rhode Island only required the sale of 15 percent, while Vermont, Massachusetts and New Hampshire have required full divestiture. As of May 30, 1998, over 20,000 MW of capacity had been sold, mostly in California and New England. Other states, notably Illinois, Michigan, Montana and Maryland have not required divestiture of generating assets.

In Connecticut, regulators will allow utilities to recover stranded costs for nuclear facilities only if the utilities offer the facilities for sale at auction. The auctions need not be successful, but they are expected to provide regulators with some guidance in setting the market value of such facilities, which is needed to determine the amount of recoverable stranded costs. To date, no state has required the divestiture of nuclear assets, although several states still have this as an open issue.

Several large utilities have indicated interest in further utilizing their nuclear expertise through acquisition of existing nuclear facilities, or by entering into contracts to operate and manage nuclear facilities for others.

AmerGen Energy Company is a joint venture between PECO Energy and British Energy Company, formed to purchase and operate nuclear plants in the United States. In mid-1998, AmerGen reached agreement in principle with General Public Utilities (GPU) to acquire the Three Mile Island (TMI) Unit No. 1 Nuclear Generating facility near Harrisburg, Pennsylvania. The agreement sets the initial sale price at $100 million, which included $23 million for the plant and $77 million for the plant's nuclear fuel. The ultimate sale price will be determined by possible additional payments depending on the actual energy market clearing prices through 2010. Two other nuclear facilities owned by GPU, Oyster Creek and TMI Unit 2 were not sold. Agencies which must approve the sale of TMI Unit No. 1 are the Nuclear Regulatory Commission, Federal Energy Regulatory Commission, Securities and Exchange Commission, Pennsylvania Public Utility Commission and the New Jersey Board of Public Utilities. Under the agreement, AmerGen will assume full responsibility for the decommissioning of TMI Unit No. 1, which will be prefunded by GPU at the time of financial closing.

PECO Nuclear currently has a management contract on Northeast Utilities Millstone 1 unit in Connecticut and also is assisting in the return to service of Millstone Unit 3. In addition, PECO Nuclear has a management contract to operate the Clinton Power Station in Clinton, Illinois, which is owned by Illinois Power Company.

Entergy Nuclear and Duke Engineering & Services have formed a joint venture to offer management and engineering services to the nuclear industry. This agreement would allow the companies to make joint proposals to manage and operate nuclear plants owned by other utilities.

Entergy Nuclear alone has entered into a long-term agreement with Maine Yankee Atomic Power Co. to provide management services to the Maine Yankee Nuclear Station through the end of plant decommissioning. Boston Edison Company (BEC) has sold its Pilgrim nuclear plant to Entergy Corporation in a deal valued at $121 million. In addition, Boston Edison will transfer the decommissioning trust fund of approximately $466 million to Entergy reducing decommissioning payments by customers by an estimated $154 million. Entergy will assume full liability and responsibility for decommissioning the Pilgrim site. The sale coupled with the reduction in decommissioning costs creates economic benefits for customers of about $275 million. Book value for Pilgrim is about $650 million.

Although some states are allowing recovery of nuclear decommissioning and fuel disposal costs only during a short defined transition period, Maine, New York and Illinois are allowing recovery of these costs through the end of the plant's current operating license by including these costs in the unbundled rates for transmission and distribution services.

Recommendation: In order to protect the assets of Nebraska's consumer-owned electric utilities, the Task Force recommends any stranded costs on nuclear facilities should be recovered through the end of the plant's current operating license. Divestiture of generation in Nebraska may not be in the best interests of Nebraska's electric consumers, and as discussed in Chapter 5, needs to be carefully assessed on a case-by case basis for potential rate impacts.

Transmission Assets: Transmission assets could also be potentially stranded. An example would be generation outlet transmission. If the generator was stranded, the generation outlet transmission would probably also be stranded.

Recommendation: Transmission assets associated with stranded generation assets should have stranded cost recovery to the extent those assets cannot be re-utilized elsewhere in the transmission and delivery network.

8.5.2 Stranded Liabilities

Stranded liabilities are primarily purchased power contracts but could also include contracts with fuel suppliers and contingent liabilities such as environmental costs that the utility cannot recover in a competitive environment because it pushes the utility's costs above the market price.

Purchased Power Contracts: Purchased power contracts could be a problem for distribution only utilities, and for their wholesale suppliers. Most distribution only utilities have long-term contracts for supply with large generating utilities, the cost of which may be higher or lower than the market. The contract terms vary, from minimum purchase requirements, take or pay, to full requirements. If the distribution utility loses load due to customer choice, the stranded cost impact will depend on the terms of the contract. If it is a minimum purchase requirement contract, the impact may be zero. If a take or pay contract, the distribution only utility will have excess supply, and therefore, potentially stranded costs. If it is a full requirements contract and the distribution only utility loses load due to customer choice, then their full requirements decrease under contract to the wholesaler, and the wholesaler is left with excess supply which they can try to re-market. If unable to re-market, the wholesaler faces the potential for stranded costs.

State regulatory bodies have without exception allowed the recovery of stranded costs related to above market purchased power contracts. They have mostly limited the recovery of costs to the transition period, after which time the utility would be exposed for any remaining above market costs. This was done to motivate the utilities to buy out the contract or sell it at market price to establish the extent of stranded costs. Many of these contracts were for output from Qualified Facilities under PURPA. Nebraska did not have such contracts. Two states are allowing recovery through the contract life and not tying it to the transition period.

Recommendation: Purchase power contracts existing at the effective date of retail choice legislation in Nebraska should be honored during the life of the contract

Fuel Contracts: Fuel contracts, whether for coal, nuclear, oil or gas, frequently have minimum purchase requirements or take or pay provisions. If a utility's cost of power cannot meet the market clearing price, the utility is likely to use less fuel, but still have to abide by the fuel contract terms which could result in stranded costs. Most states have allowed obligations having above market prices to be included in stranded costs.

Recommendation: In Nebraska, the cost of any stranded fuel contract should be handled in the same manner as the costs of the associated generation are handled.

Fuel Transportation Contracts: Transportation contracts to deliver coal to generating stations could result in stranded costs under the same conditions outlined for fuel contracts . Stranded cost recovery should follow the method used for the fuel contract.

Plant Removal/Decommissioning Costs: In addition to the plant values, the owners of nuclear facilities also have to consider decommissioning costs. The following data on Nebraska's two nuclear plants indicates the status of decommissioning plans at December 31, 1995.

Table 8-6

These estimates and funding only cover the radiated portions of the plants. The non-radiated or conventional costs of these facilities can be recovered through decommissioning or depreciation. Fossil-fired facilities such as Nebraska City and the Gentleman Stations have similar "back end" removal costs that would be incurred for site restoration. The normal practice is to recover fossil plant removal costs through depreciation. Nuclear decommissioning costs will be incurred regardless of whether or not these facilities become non-economic because of competition. However, they are different from plant costs, which are a known value, whereas decommissioning costs are estimates of future liabilities. In addition, human resources, stores material and fuel inventory costs have to be considered. For the purpose of estimating stranded costs, all of these costs should be included in the calculation.

8.5.3 Stranded Benefits

The types of benefits that could be stranded in Nebraska if retail competition was established include:

• Operational Benefits: Mutual aid, joint planning, demand-side management, conservation, information sharing, EPRI R&D and economic development services.
• Public Benefits: Low income assistance, irrigation, ground water recharge, conservation, environmental, recreation, flood control, and economic development services.

8.5.4 Start-up Costs

Startup costs include costs that would be incurred during the transition period from a fully regulated environment to a competitive environment. Such costs would include:

• Employee transition costs (relocation, retraining, early retirement and severance related expenses, to the extent not included in stranded costs).
• Information systems.
• Consumer education and consumer protection.
• Power exchange (PX) costs and Independent System Operator (ISO) costs.
• State and individual system additional regulatory costs.

8.5.5 On-Going Costs

Electric utilities will experience incremental, on-going costs as a result of the transition from a fully regulated environment to a competitive environment. These costs include:

• Certain costs that originated in the start up period.
• Public good costs that were voluntarily incurred in a regulated environment and are mandated in a competitive environment.
• State and individual system additional regulatory costs.
• Consumer protection and consumer education.
• Public benefits.
• Power exchange (PX) costs and Independent System Operator (ISO) costs.

Table 8-7

A further breakdown of the elements of stranded costs and considerations of the character of these costs is shown below in Table 8-8.

Table 8-8

8.5.6 Quantifying Transition Costs

Utilities with power production costs higher than those likely to prevail in the competitive market may be unable to fully recover the fixed costs of generating facilities that they own and operate. Accordingly, the initial composition of stranded costs will be dominated by assets related to a utility's generating capacity.10 Utilities and regulators can use a variety of approaches to calculate stranded costs. All approaches compare the regulated-market values of utility assets and liabilities with their competitive market values. There are two primary approaches, one is an "administrative valuation" and the other is a "market-based valuation." Administrative approaches use forecasting, modeling or other analytical techniques to estimate asset value and transition costs. Market valuation relies on the sale price of particular assets to determine their market value. These valuations may be undertaken either before (ex ante) or after (ex post) restructuring of the electricity industry is completed. A third dimension concerns the level of detail involved in the valuation. A "bottom-up" approach computes the amount of each asset or investment (including contracts, regulatory assets, social programs, and other stranded liabilities). A "top-down" approach looks at revenue needs of the utility and calcu