|CHAPTER EIGHT: COST/BENEFIT CONSIDERATIONS
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.
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.
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.
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:
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
Chart 5-1 WHOLESALE POWER PRICE PROJECTIONS FOR
NEBRASKA AND REGION 1999-2010
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.
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.
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 transition 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.
Even if we assume only 1 mill for transaction costs and only 1.1 mills for partial transition costs, in order for a small Nebraska consumer using about 1,000 kilowatt hours per month to reach a minimum threshold level of 5 percent savings (3.22 mills) there would have to be a substantial shift in wholesale power costs. Nebraska would need to lose its current 3.4 mills wholesale power supply cost advantage, and have wholesale prices rise more than 15 percent above regional wholesale power supply prices to provide the necessary offset of 8.7 mills. Adding in full transaction and transition costs including possible "safety net" and other charges would drive the necessary wholesale cost shift even 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.
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. 8-3 provides an overview of the categories of costs.
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 October 1999, 21 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.
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 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.
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 assets. It cannot be over emphasized that the timing of a transition to a competitive retail market is a substantial factor in whether stranded costs will exist 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. 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 represent a significant investment. As reported in the L. R. 455 Phase I report and shown in Table 8-5, 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.
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.
Nuclear Generating Plants: 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.
Other Generation: Utilities that utilize internal combustion engine power plants or smaller, old, fossil fueled boiler units singularly for their generation or in combination with a program of non-firm energy purchases or for emergency purposes, may also be in jeopardy of experiencing stranded costs in a competitive retail environment because of outstanding debt and undepreciated production facilities. In addition to outstanding debt and depreciation, these units tend to have higher operating costs which would add to their uncompetitiveness and potential stranding. Another area of concern are the hydro units in Nebraska, especially the hydro facilities operated by Central and NPPD as discussed in Chapter 6. Because of the significant environmental and other public benefit burdens borne by these projects, they are considered marginally competitive today. Over time in a deregulated marketplace, the value of the power generated by these projects may no longer be sufficient to cover the total costs of providing the environmental and other public benefits. If the public benefits and other non-electric uses of these projects are not recovered on a fee basis from the beneficiaries, and production costs for competitive power plants decline, there is a possibility that these assets could become be non-competitive.
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. Although nuclear might represent the largest potentially stranded generation cost, the impact on smaller fossil-fueled and hydro facilities may also be considered. Since many of these units are owned and operated by smaller utilities, the negative impact of a competitive marketplace on these utilities could be substantial. 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. A full examination of stranded costs is needed.
184.108.40.206 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.
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:
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:
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:
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 calculates the difference in revenue needs under the existing and new market system and apportions costs to produce the needed revenues.
Part of the market approach includes a utility putting its generating assets up for sale and secure a price offered by the highest bidder. Stranded costs in this approach are immediately determined as the difference between the embedded price and the realized sale price. Its main disadvantage is that large blocks of assets cannot be sold easily and may tend to depress prices. Its applicability is also limited to marketable assets. Many generation assets are being sold at a substantial premium over book. Book value is not necessarily a good indicator of a generation assets real value. Payment of more than book can indicate the desire of the buyer to enter a particular market in order to obtain a plant for retrofitting, or simply to obtain the plant site.
220.127.116.11 Comparison of Methods
Regulators might prefer top-down methods because of their administrative simplicity and reliance on readily available data and computer models. Such methods are well suited for problem identification and assessment (i.e., developing initial estimates of the magnitude of the transition-cost problem for a particular utility or state). However, in regulatory authorization for utility recovery of stranded costs (i.e., determining the actual dollar amounts to be recovered), commissions might prefer the greater detail of bottom-up methods. This detail is especially important if commissions decide to authorize recovery of utility shareholder investment in certain assets but not necessarily recovery on these investments (i.e., return on equity), or if regulators want to allow utilities to recover different fractions of stranded costs for different types of assets and liabilities.
Regardless of the method used to estimate the amount of stranded costs, one must make certain assumptions. Although many factors affect the calculation of stranded costs, only a few factors make a big difference. The most important factors affecting the magnitude of stranded costs include the future market price of electricity, when retail wheeling begins, extent of retail wheeling, amount of utility regulatory assets and utility fixed production costs. On the other hand, certain factors are likely to have very little effect on estimates of stranded cost amounts, including public policy program costs, inflation rate, load growth, customer load factors, and transmission and distribution system loss factors.
Of the critical factors that affect stranded costs, some can be influenced by the utility and some by the regulator, and some are essentially beyond the control of either party. As examples, the regulator can affect the start date and the extent of retail competition, although market forces may overwhelm regulation where large regional price disparities exist; and utilities can seek to cut their fixed and variable production costs. But wholesale prices, by far the most important factor, are largely independent of utility or regulator actions.
Because so many assumptions are required to develop estimates of the dollar amounts at stake, regulatory commissions may want to apply periodic adjustments (true-ups) to their initial estimates. Such true-ups would reduce the risk that any group would pay too much or enjoy windfall profits. On the other hand, the regulatory proceedings associated with such true-upscan be complicated, time consuming and litigious, and, unless properly designed, such mechanisms can reduce a utility's incentive to perform efficiently.
18.104.22.168 Application to Nebraska
For a cost-based, consumer-owned system, divestiture of assets is not required to quantify stranded costs. A bottom-up, ex ante (before the fact), administrative approach could be used to initially quantify and collect stranded costs in Nebraska. Actual stranded cost recovery could be based on the bottom-up, ex post (after the fact) administrative approach using actual competitive market conditions and utilizing a true-up mechanism (used to adjust initial estimates to actual recovery) to reconcile the amounts previously collected under the ex ante estimate.
Issues that must be considered in using this methodology include the following:
The key assumptions needed to calculate stranded costs, and the problems associated with formulation of these assumptions follow:
The major problems include:
The nuclear generating facilities in Nebraska could potentially be stranded in a competitive environment, however, if stranded costs are calculated on a system-basis rather than by individual generating unit, the potentially stranded nuclear facilities might be netted by lower cost generating units. It might be advisable to calculate stranded costs on a unit-by-unit basis if neighboring states are following that methodology. This would ensure that Nebraska's generation would not be put at a competitive disadvantage.
Start-up and on-going costs are incremental costs caused by the transition to a competitive market that must be accounted for and collected separately from any stranded costs.
A comprehensive study of all potential transition costs in Nebraska should be completed prior to the development of deregulation legislation.
In a Limited Access or Open Access competitive market scenario, there are a number of issues and impacts that must be considered in quantifying transition costs. These are summarized in Table 8-9.
Recommendation: Stranded costs should be analyzed on a system-by-system basis and considered for unit-by-unit analysis if other states are implementing such cost recovery. This would involve a quantitative study, which would include estimates of market price of energy, the date when retail competition would begin, discount rates and numerous other factors. The Task Force recommends that such a quantitative study be conducted under the auspices of the Nebraska Legislature and Nebraska Power Review Board as part follow-on studies.
8.5.7 Mitigation of Transition Costs
22.214.171.124 Assets and Liabilities
Strictly speaking, stranded costs, because they reflect sunk costs and future obligations, cannot be mitigated. However, regulators can allocate these costs among different groups, such as utility investors, retail customers, wheeling customers, taxpayers and wholesale producers. In some cases, regulators and utilities can find ways to cut operating costs and can then use these savings to offset what would otherwise be stranded costs.
In other cases, regulators can only affect who bears the costs. Delaying retail competition protects utility shareholders at the expense of those retail customers who lack market power. On the other hand, rapid and comprehensive implementation of retail competition could bankrupt some utilities, unless the regulatory commission imposes what is often called a Competitive Transition Charge ("CTC"). The CTC is collected from all users of the distribution system and is paid to utility shareholders.
Other strategies, such as changing the depreciation schedules for generation and transmission assets, affect the timing of these costs rather than their amounts. For example, accelerating depreciation of a nuclear unit would increase rates for today's customers and lower rates for future customers. Renegotiating purchase power contracts can shift costs from ratepayers and utility investors to independent power producers and other wholesale suppliers.
Finally, utilities can identify and implement ways to cut their costs to produce, transmit and deliver electricity, as well as their customer service and administrative costs.
126.96.36.199 Nuclear-Specific Considerations
To prepare for the onset of competition, utilities will be expected to mitigate stranded cost exposure to the extent possible through various techniques. As noted earlier, there is potential for a large amount of nuclear stranded costs around the country. Depending on a number of factors, Nebraska could also face exposure to stranded costs on the two nuclear units in the state. Nuclear stranded costs could be significantly mitigated if the time that retail competition begins is extended. This delay would allow for more of the licensed life of the nuclear facilities to pass, thereby allowing more of the costs to be recaptured in a regulated environment. Because of the heavy reliance of the nation on nuclear generation (currently about 14 percent of installed capacity and 20 percent of energy production), the shutdown of nuclear facilities for strictly economic reasons could severely impact the nation's electrical energy supply and national security.
A potential solution to this prospect would be federal action that would designate nuclear facilities as "must run" facilities, thereby creating competition only for those loads above the nuclear capability in the country. Clean air initiatives and a possible carbon tax may also support the continued operation of nuclear facilities. In their efforts to address stranded nuclear costs, the United Kingdom provided for a fossil fuel tax to subsidize nuclear operations. In addition to a later start for competition and previously mentioned strategies, the following can also be effective in mitigating nuclear stranded costs.
Mitigation strategies should be carefully selected and implemented to ensure nuclear safety is not compromised.
188.8.131.52 Stranded Benefits
Certain operational and public benefits could be lost in the transition from a regulated to a competitive environment. The following observations indicate how these benefits could be impacted and mitigated.
Specific local services and other situations in Nebraska also need to be assessed for the stranded benefits that might be created. One major issue concerns the Cooperative Agreement concerning Platte River issues.
As noted in Chapter 6, the Federal Energy Regulatory Commission recently issued new forty-year licenses for the Platte River hydroelectric projects operated by the Central Nebraska Public Power and Irrigation District (Central) and the Nebraska Public Power District (NPPD). These projects consist of five hydroelectric plants and related structures and reservoirs, including Lake McConaughy, Lake Maloney and Johnson Lake.
Relicensing is closely tied to the Cooperative Agreement signed last year by the Governors of Nebraska, Wyoming and Colorado, and the Secretary of the Interior to address endangered species issues in the Platte River. Central and NPPD received their new licenses because they agreed to effectively provide most of Nebraska's contribution to the Cooperative Agreement for the first 13 to 16 years. The Cooperative Agreement provides $75 million in environmental benefits in the Central Platte River region with the federal share equal to $37.5 million. The State of Nebraska's share is $15 million with Central and NPPD providing the majority through water and land contributions. The water contribution held in Lake McConaughy could significantly reduce revenues from power generation. These impacts are not included in the cost estimates. These Platte River projects also continue to provide additional public benefits: recreation, flood control, groundwater recharge and irrigation service. License conditions require that they also make new contributions toward wildlife habitat, improving recreational facilities and preserving cultural resources.
As noted in Chapter 6, collectively the environmental and other public benefits required under the new licenses increase the costs of these projects substantially, and reduce the value of the energy and capacity benefits of operating the project. FERC estimated net increases in cost at $309,000 annually for NPPD and $1,049,000 annually for Central. These additional costs make these hydroelectric projects at best marginally competitive today.
Over time in a deregulated marketplace, the value of the power generated may no longer be sufficient to cover the total costs of providing environmental and other benefits to the public. One solution would be to increase revenues derived from other public benefit services by increasing existing fees or establishing new fees. Central and NPPD could not continue to operate uneconomically indefinitely, putting public benefits they provide at risk.
The Agreement should be viewed as a stranded benefit and the assessment for the cost should be expanded outside the electric utility industry. The costs of non-power related benefits associated with Nebraska's hydro production (irrigation, flood control, recreation, etc.) should be recovered through user fees, rather than be subsidized by power production.
184.108.40.206 Summary of Transition Cost Mitigation
Transition costs should be mitigated to the fullest extent possible. Table 8-10 summarizes strategies that could help to mitigate transition costs in a Limited Access or Open Access competitive market.
8.5.8 Who Should Pay Transition Costs
The question of who should pay for stranded costs has been hotly debated in the states that have considered deregulation of the electric utility industry. The focus in these states has been primarily on the stranded costs of investor-owned utilities. In these states, legislators and regulators are requiring, for the most part, that customers pay for stranded costs in a deregulated environment, just as they would pay for these costs over the economic life of the assets in a regulated environment. The payment of stranded costs has been tempered to some degree by mandated rate reductions, price freezes, or price caps in some states.
220.127.116.11 Nebraska's Unique Structure
Because of Nebraska's unique structure of all consumer-owned electric utilities, the question of who should pay for stranded costs in Nebraska if deregulation occurs involves a mixture of public policy and legal questions.
18.104.22.168 Capitalization of Electric Utilities
The traditional sources of capital for electric utilities are stock (common and preferred), borrowed funds (debt) and revenues. All of these capital sources are available to investor-owned utilities. Such is not the case with Nebraska's consumer-owned utilities. Nebraska's consumer-owned electric utilities only have two sources of capital available, revenues and debt. They cannot use stock as a source of capital.
Stockholders: In states that have investor-owned utilities, the stockholders are the "owners" of the utility. The stockholders receive dividends and experience changes in the value of their stock, which are driven by the profitability of the utility and demand for the stock in the marketplace. Common stockholders receive dividends only if there are monies available for this purpose after paying the costs of operating and maintaining the electric system, principal and interest payments on outstanding debt, and preferred stock dividends. If an investor-owned utility goes bankrupt, the common stockholders run the risk of losing all of their investment in the utility because they are in fact the owners.
In Nebraska, the electric utilities are in effect owned by the citizens of the areas they serve . they are the customer-owners of the utility. Although these customer-owners do not get a dividend check, they receive a "dividend" in the form of lower electric rates because of the avoidance of common stock dividends.
Bondholders (lenders): Both investor-owned and consumer-owned utilities issue debt to provide capital for their operations. Investor-owned utilities issue mortgage bonds and also utilize other forms of debt such as notes and commercial paper. These utilities do not rely on debt to the same extent that consumer-owned utilities do because they have access to the equity (stock) markets.
When a consumer-owned electric utility is formed, the only ways to fund the creation of the utility are to have the customer-owners provide all of the required funds on the front end, or for the utility system to issue debt for the creation and amortize this debt over the expected useful life of the facilities financed. Because of the capital-intensive nature of the electric utility industry and the long life expectancy of the facilities, borrowing funds to finance a consumer-owned utility is necessary to balance the costs and benefits of the utility system operation.
Nebraska's consumer-owned electric utilities primarily issue debt in the form of revenue bonds, notes and commercial paper in the national debt markets. In addition, Nebraska's rural electric systems acquire capital through the Rural Utilities Service and National Rural UtilitiesCooperative Finance Corporation substantially in the form of a mortgage. At the end of 1995, Nebraska's consumer-owned electric utilities had outstanding debt of $3.18 billion.
In the case of mortgage bonds issued by an investor-owned utility, if the utility goes bankrupt, the bondholders have recourse in the fact that they hold a mortgage and can liquidate the properties to recapture all or part of the borrowed funds.
In the case of revenue bonds issued by a consumer-owned utility, the bond indenture provides that the bondholders have certain rights in the event principal and interest payments are not made as provided for in the indenture, or if defaults occur on other parts of the indenture. The most serious consequence of default would be that the utility would go into the hands of a trustee (receiver) to cure the default, for reorganization or for dissolution. The bondholder does not have an ownership interest . they only have a lender interest.
Reinvested Earnings: Once a consumer-owned electric utility is up and operating, customer equity starts to accrue and can be reinvested in the system. Customer equity is created to the extent the utility has funds from revenues remaining after paying the costs of operation and maintenance, taxes, debt service and other costs of the system. This equity is then reinvested in the system in the form of new facilities or reconstruction of electric facilities to serve the customer-owners. This contrasts with the "paid in" equity of an investor-owned utility that is created when common stock is sold. Over time, the reinvested earnings grow, and a capitalization mix of debt and customer equity develops. As reinvested earnings accumulate over time, they provide a part of the capitalization and less reliance is put on debt issuance resulting in a lower overall cost for the consumer-owned electric utility. Reinvested earnings are also very important from a credit standpoint. Just as any lender expects a borrower to have some of their own money at risk in a personal or business venture, buyers of consumer-owned electric utility debt in the national debt markets expect the utility to have some "equity." The accumulation of reinvested earnings is a good indicator that electric rates are adequate for a successful operation. At the end of 1995, Nebraska's consumer-owned electric utilities had consumer equity of $2.17 billion.
Stockholders vs. Bondholders vs. Customers: Customers of a consumer-owned electric utility have dual status . they are a customer and they are also an owner. In an investor-owned electric utility, the customers and owners (stockholders) are distinct and separate. This places the customer of a consumer-owned utility in a very unique situation. In states where the determination of who should pay for stranded costs has been made, the customers are going to pay for the bulk of stranded costs through various mechanisms with a small portion being picked up by the owners (stockholders). With their dual status, one must assume that the customers of Nebraska's owned electric utilities would bear all of the stranded costs if the national trend on recovery of stranded costs prevails.
The bondholder is insulated from stranded cost exposure as a lender. As indicated earlier, the bondholder has recourse in the event of default. If the default is not cured, the bondholder can take control of the properties. The lender is only interested in the repayment of the loan and has various mechanisms available to accomplish that end. In the event of reorganization or dissolution, the bondholder (lender) has a very good chance of recovering the full amount of the loan since they have access to the full value of the utility system (both the debt financed and the equity or reinvested earnings financed portions). The bondholder is not at risk for stranded costs, and has no incentive to bear any portion of stranded costs.
Start-up and on-going costs are borne by electric consumers in other states that have deregulated, and it is expected that this would also occur in Nebraska
22.214.171.124 Summary of Who Should Pay Transition Costs
The dual status of customers of Nebraska's consumer-owned electric utilities indicate that they will bear the transition costs if the electric industry is deregulated in Nebraska. However, the recapture of costs incurred in a regulated environment and the incremental costs associated with deregulation should be shared equitably by all market participants in a deregulated environment. If the issue of transition costs in Nebraska is not dealt with effectively at the onset of the deregulation process, various forms of cost shifting could occur.
Recommendation: Nebraska should identify and quantify transition costs early in the deregulation process, and set up mechanisms to ensure equitable recovery of transition costs from all Nebraska competitive market participants until these costs are fully amortized.
8.5.9 Collection of Transition Costs
In facilitating the transition from a regulated to a competitive electric utility market, legislators and regulators in other states have evaluated and implemented various mechanisms to recover transition costs. Stranded costs, start-up costs and on-going costs are all covered by the following discussion. Table 8-11 indicates generally, who may be assumed to pay the particular costs discussed following the table.
126.96.36.199 Access Fee
Under this methodology, certain transition costs and a fixed recovery period are identified. The utility is allowed to collect these costs by imposing an access charge on all customers who utilize the utility's electric system, regardless of whether the customer purchases power from the incumbent supplier or an alternate supplier. As long as the customer uses the utility system's facilities, they must pay the access fee, and, therefore, the fee is non-bypassable. This can be a flat fee or a fee based on kWh usage. With this methodology, all suppliers, incumbent or alternate are on an equal footing.
The access fee is usually set out as a separate line item on the billing, but could be incorporated into the transmission or distribution line item (wires charge) on the billing. If the latter approach is used, the customer is not getting full disclosure on stranded costs. In addition, since the recovery period for stranded costs under this methodology is finite, it is better to set the access fee out as a separate line item so the customer will see when this access fee is removed from their billing. A true-up mechanism can be employed with this methodology. The access fee is sometimes referred to as a competition transition charge or "CTC". The fixed recovery period varies. See section 5.7.2 of this report for additional discussion of access fees.
188.8.131.52 Exit Fee
When a customer decides to discontinue the use of the utility system's facilities during the period the incumbent utility is allowed to collect the access fee, the costs normally collected as an access fee are collected as an exit fee (also referred to as a "severance fee"). When this occurs, the alternate supplier must notify the customer of the obligation to pay the incumbent utility costs stranded as a result of their action, and get the customer to commit to paying the transition costs before the alternate supplier can serve the customer. The exit fee can be lump sum or made in installments. The use of an exit fee is a substantial burden on the customer and can be viewed as anti-competitive.
184.108.40.206 Statewide Fee
An alternative to a specific utility's transition costs being collected from their customers only in the form of an access or exit fee, is to aggregate the transition costs for the entire state and charge all customers in the state on the same basis regardless of whether their incumbent utility had any transition costs. This method shifts costs from customers for whom they were incurred to all customers in the state. Some costs should probably be collected on a utility-specific basis while others (e.g., consumer education) might be better done on a statewide basis.
220.127.116.11 Securitization/Rate Reduction
Some states have adopted a process that links a rate reduction to certain customers with securitization of certain transition costs. Securitization is a common financing tool used in many industries whereby a company wishing to accelerate cashflows "sells" accounts receivables or other cashflow producing assets to a special purpose entity such as a trust.14 The entity then issues securities that are backed by the assets in question, or in this case the transition assets. It allows utilities to capitalize a future flow of funds providing present value in an up front cash payment. The charges designed to repay the bondholders are irrevocable over the life of the asset, reducing the default risk, and thus allowing for a lower rate of interest.
In California, a 10 percent rate reduction was ordered for residential and small commercial customers. In conjunction with that order, utilities were allowed to request securitization for certain transition costs, including the 10 percent rate reduction. The securitization takes the form of Rate Reduction Bonds (the "Bonds"). Securitization occurs when a state agency (trust) sells bonds (an asset backed security). The bond proceeds flow to the utility that had requested the securitization of the transition costs. In return, the utility bills a Fixed Transition Amount ("FTA") to all residential and small commercial customers each month, and transmits the FTAcollected to the trust. The trust uses the stream of funds generated by the FTA collections to pay debt service (principal and interest) on the Rate Reduction Bonds.15
The asset backing the bonds is the non-bypassable FTA billed to the residential and small commercial customers over the life of the bonds, which is generally a 10 to 12 year period. The FTA can be a flat charge or based on kWh usage. Because the FTA provides a guaranteed revenue stream to pay the debt service on the bonds, the bonds normally obtain a high credit rating, which results in a lower interest cost. A true-up mechanism is employed to ensure FTA collections are adequate to provide for all debt service on the bonds.
Utilities that receive the bond proceeds have flexibility on how the proceeds are spent. The intent is that the proceeds would be utilized to mitigate transition costs that were not included in an access or exit fee.
Several states have taken the same approach as California on securitization. However, Illinois chose a different approach. Because the transition charge in Illinois was based on an exit fee and not a non-bypassable charge, the Illinois legislature had to address securitization differently. They have allowed, but not required, utilities to unbundle a portion of their base rates including transition charges. After Illinois Commerce Commission approval, securities can be issued that are backed by those unbundled charges. The actual transition costs of the utility industry in Illinois will not be established so the bond offerings will be limited to a percentage of the utility's total capitalization. The utilities must also use the securitization proceeds to reduce capital costs through refinancing or re-capitalization, to retire previously incurred obligations such as power purchase contracts, or to pay specific transition costs such as those relating to functional separation, T&D reliability, or employee severance costs.
18.104.22.168 Impact on Consumers
Until the term of an Access Fee, Exit Fee, Rate Reduction/Securitization or other mechanism to collect transition costs has run out, electric consumers will not realize the full benefit of a competitive market. In fact, consumers could be worse off during the transition from a regulated to an unregulated market because costs that would normally be recovered over the economic life of facilities in a regulated environment are recovered over a shorter period of time in a competitive market. Table 8-12 summarizes various forms by which transition costs can be collected.
Recommendation: In Nebraska, transition cost recovery should be made with non-bypassable access or user fees as appropriate
Tax revenues must be addressed as an important part of a transition to retail competition. As discussed in Chapter 7, competition in the electricity industry is likely to have a significant impact on federal, state and local tax systems.
Taxes are one of the many costs that utilities pass through to consumers in electric rates. State and local taxes imposed on electric utilities include: in-lieu-of-tax payments, gross receipts taxes, net income taxes, and property taxes that may be different from those imposed on other businesses. Taxes imposed on utility customers but collected and remitted by the utility include sales and use taxes and utility user taxes.
Tax policy problems are especially difficult for local governments, which have relied heavily on tax revenues from electric utilities located within their jurisdictions, because these governments have only limited sources of other revenue available to them. It is possible that targeted state aid may be the only effective means of assisting certain local governments with especially severe exposure to tax revenue losses.
As noted in Chapter 7, there are two basic tax issues. First, unless existing tax laws are changed, competition is likely to cause revenues to decline in many jurisdictions. This could result from lower electricity prices, a shift in market share from more to less heavily taxed providers, and declining values of property owned by utilities.
Second, to the extent that various providers of electricity are taxed differently under existing law, these differentials will have a very different economic impact in a more competitive environment than they have had under cost of service regulation. Essentially, taxes that have been passed through to customers as higher electricity rates will be borne to an increasing extent by the utilities themselves and will affect who provides power and where it is generated.
Nebraska's consumer-owned electric utilities contributed $51.257 million, exclusive of sales and use tax payments, primarily to local governments in 1995 as follows:
Total retail electric energy revenues in Nebraska for 1995 were $1.102 billion. Comparing these revenues to the total transfer payments in 1995 totaling $51.3 million produces a tax equivalent rate of 4.7 percent. Because most the revenues of the REA/RUS systems come from rural areas, the gross revenue tax (calculated as 5 percent of the gross revenue derived from retail sales of electricity within incorporated cities and villages) produce a very small amount of tax replacement revenue for local governments. Comparative median rates are indicated in Chart 8-1 below.
Excluding the REA/RUS systems, the tax equivalent rate is 5.7 percent. This compares to the American Public Power Association (APPA) median rate for all consumer-owned utilities of 5.8 percent, and the APPA median rate for the West North Central Region (which includes Nebraska) of 5.3 percent. The comparable median rate for private investor-owned utilities is 5.9 percent for 1994.
There has been speculation that the relatively low electric rates enjoyed by Nebraska consumers is primarily the result of a lower average tax equivalent paid by the Nebraska systems. However, if all Nebraska systems made transfer payments in 1995 equal in percent to the tax paid by private investor-owned utilities as shown above (e.g. 5.9 percent), the average impact on the cost of electricity in Nebraska would be minimal. The difference between the investor-owned utility rate of 5.9 percent and the Nebraska average rate of 4.7 percent when applied to the Nebraska retail electric energy revenues in 1995 ($1.102 billion) is $13.761 million or 1.25 percent.
Some of the policy options that have been discussed to address these issues include replacement of existing taxes with broad-based energy taxes or electricity consumption taxes, repeal of existing sales and use tax exemptions for electricity imported from other states, property tax reform to reduce the differences between utility and non-utility owners of property, and replacement of gross receipts taxes with net income taxes.
Nebraska tax policy will need to assure revenue neutral impacts, equitable treatment by all systems for all consumers for:
The general consensus is that state laws would need to be revised to preserve existing tax revenues while not giving any competitive advantage to any group of electric energy providers.
Table 8-14 summarizes the variant types of service under the three models and federal requirements to be considered in formulation of Nebraska tax policies.