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Stranded Cost Valuation
[Papers & Pubs] [Stranded Value]

A Guide to Stranded Cost Valuation
and Calculation Methods

Prepared by
William B. Marcus
 JBS Energy, Inc.
 311 D Street
 West Sacramento, CA 95605
 E:Mail: bill@jbsenergy.com

 Jan Hamrin
 HMW International, Inc.
Presidio, Bldg. 49
 P.O. Box 29512
 San Francisco, CA 94129

February, 1997

Table of Contents

Chapter 1: Summary
Chapter 2: Definitions: Stranded Costs, Transition Costs, and Operating Subsidies
 Chapter 3: Pennsylvania Legislation
 Chapter 4: Determination of Stranded Cost
 Chapter 5: Determining Utility Plant Book Value
 Chapter 6: Long-Run Determination of Market Value for Utility Plant
 Chapter 7: Methods of Determining the Short-Run Market Value
 Chapter 8: Sharing of Stranded Costs Between Shareholders and Ratepayers
 Chapter 9: Ratemaking Principles for Stranded Cost Recovery Beyond Sharing of Costs
 Chapter 10: Design of Transition Cost Recovery Programs
 Chapter 11: Overall Policy Recommendations 60
APPENDIX A: Stephen Teichler, "Generation, Deregulation, and Market Power: Will
 Antitrust Laws Fill the Void," Public Utilities Fortnightly, October 15, 1996, pp. 34-41.
(not included in version posted on website)


The evaluation of a utility’s stranded costs is likely to be larger than any other rate case ever held for this utility, either past or future. Getting stranded costs right, conceptually and quantitatively is extremely important in determining whether ratepayers will benefit from a restructured future.

This chapter starts with our recommendations and then summarizes the report.

Stranded Cost Components

  • Stranded costs are payments for sunk costs and past obligations.
  • Utilities should not receive operating subsidies in stranded cost payments. These subsidies are unfair to both ratepayers and competitors.
  • An outside audit should be conducted to evaluate the book value of utility plants and regulatory assets before stranded costs are valued.
  • Recent capital additions should be carefully scrutinized for reasonableness, both specifically and in terms of the overall amount of costs spent.
  • Fuel contracts and inventories should generally not be part of stranded costs.
  • General and common plant located away from powerplant sites should generally be excluded from stranded costs because that equipment has alternate uses.
  • Regulatory assets must be analyzed to remove costs that are not actually stranded, to avoid double-counting costs, and to avoid operating subsidies.
  • Utilities should be required to credit ratepayers with the value of normalized deferred taxes when powerplants are assigned a market value to the extent feasible under tax law. All else being equal, methods of valuing utility plants that give ratepayers credit for deferred taxes should be preferred.

Method of Determining the Market Value of Utility Plants

  • Market valuation is preferable to administrative determination.
  • Divestiture of generation is desirable to reduce market power and to reduce manipulation of stranded cost determination and other regulatory decisions.
  • The most desirable method of divestiture is a stock spin-down, with the possible exception of nuclear and other specialized assets.
  • If an appraisal method is used, the instructions given to the appraiser must be reviewed by regulators to assure that costs are properly assigned and not double-counted, and that the appraiser is using reasonable assumptions. A mechanism to provide for additional appraisals must be adopted.

Sharing of Stranded Costs between Shareholders and Ratepayers

  • Shareholders receive a risk premium to compensate them for riskiness of utility stock. One of the risks is that utility generation may become uneconomic. In most cases, 100% recovery of stranded costs is not justified by the circumstances.
  • Shareholders should pay a portion of stranded costs to provide incentives for efficiency in reducing those costs.
  • The amount that shareholders receive in stranded costs should be tied to the method of determining stranded costs. Shareholders should recover more stranded costs with 100% divestiture, less with partial divestiture and partial appraisal or full appraisal of generating plant, and the least with administrative determination of the stranded costs.
  • The utility should be required to take a specific write-off to the bottom line of the percentage of stranded costs that are not recovered from ratepayers. This creates a structural incentive for the utility not to overstate stranded costs, because any overstatement increases the write-off.

Other Ratemaking Principles

  • Stranded costs should not be double-counted, either (a) with each other among categories of stranded costs; (b) with past costs recovered using other ratemaking mechanisms; or (c) with future costs that should be recovered from the market without subsidy.
  • Ratepayers should receive interest at the utility’s rate of return for any costs that are paid in advance (e.g., decommissioning costs) before the utility spends the money.
  • Determination that a cost is stranded should not override other past regulatory decisions, including disallowances, differences in allowed returns on certain costs, and decisions earmarking funds for specific purposes.
  • Issuing bonds to finance transition costs is not a substitute for comprehensive regulatory review of stranded costs. Rather it is a complement that may reduce financing costs for those stranded costs that the Commission determines that ratepayers should pay.

Stranded costs are the costs that the utility is obligated to pay for existing generation in excess of the market value of that generation.

 Transition costs are the portion of stranded costs that are paid by consumers.

For utility owned powerplants, stranded cost is the difference between the net book value of the plant plus all other regulatory assets and liabilities and other obligations associated with the plant’s past operation (deferred taxes, post-retirement benefits other than pensions, etc.) and the market value of the plant. The market value of a plant cannot be less than zero, because the plant’s owner could close it down and mitigate that cost.

 For contracts to purchase power, stranded costs equal the cost of purchased power (demand plus energy costs) minus the market value of that power.

Future costs for fuel, operation and maintenance and capital additions are not stranded costs. If a utility can recover future costs as part of stranded costs, it is receiving an operating subsidy, which has serious implications for market competitiveness and for ratepayers. Operating subsidies keep plants open that should be closed on the basis of simple economics, drive prices down artificially, and force ratepayers to pay artificially high stranded cost payments.

 Pennsylvania law allows stranded costs to be collected through a Competitive Transition Charge (CTC) which can be imposed for a period of up to nine years. The charge shall include all uncollected regulatory assets and all contract costs (as well as costs of buying out contracts that are prudently incurred).

 For utility owned assets, the Commission is given more flexibility in determining the costs that are just and reasonable. It is specifically required to set cost recovery in light of the utility’s proposals to "mitigate" stranded costs. Mitigation includes reducing capital spending, reallocating or accelerating depreciation, selling off powerplants, and issuing securitized debt to reduce costs.

Stranded costs can be calculated on a short-run basis, comparing the market value of power to the utility’s cost year-by-year, or on a long-run basis , comparing the market value of a utility plant to the net book value.

To analyze stranded costs, one can use either a market determination or an administrative determinationof market value by the regulatory agency.Market determination values a plant using observed market data. For long-run determination, the plant is divested, and a market value is developed. In the short-run, a plant’s costs are compared to the value of power.

 Administrative determination of market value involves a forecast of future plant operating costs and the future market value of power. The market value of the plant under a pure administrative determination is:

This calculation is highly data intensive, requires the use of many assumptions, and is likely to be first run by the utility with intervenors and the Commission often only providing critiques rather than independent calculations.

An intermediate step between market and administrative determination of stranded costs involves an appraisal. If the market value is set by appraisal, one or more professional appraisers set the value of the plant, and the Commission reviews the appraisal.

 The following eight categories of stranded costs have been requested by utilities.

 The stranded cost calculation compares the market value of a utility plant to its net book value (gross plant less depreciation). The California PUC correctly required an audit of utility sunk costs including gross plant, capital additions and depreciation over several recent years. However, an audit, while necessary, is no substitute for a detailed regulatory analysis and quantification of costs.

Recent capital additions need review. These additions must be scrutinized to avoid charging ratepayers for a pre-restructuring spending bulge or spending undertaken with knowledge of the low value of power.

General or common plant is plant not associated with a specific utility function (such as communications systems, computers, office buildings, and motor vehicles). The more tenuous the link between general plant and the generation site, the less likely that it is a stranded cost.

 Utilities routinely carry inventories of fuel and other materials and supplies. Stranded costs associated with these inventories, however, are minimal. Many inventories, particularly fuel supplies, can be easily sold, and the cost of restocking inventories should be recovered from future market prices. Stranded cost recovery for inventories gives utilities an advantage over other competitors.

 Some utilities are requesting recovery in stranded costs of the fixed components of fuel contracts. The recovery of costs related to fuel contracts is problematic. Most fuel contracts are not stranded costs. If utilities recover some fuel costs through stranded costs, they gain an unfair advantage over their competitors.

 A regulatory asset is a commitment by the regulator to recover certain utility costs in future rates. There are a wide variety of regulatory assets. Each of the California utilities claimed stranded cost treatment for at least 10 such assets.

 Analysts carefully review requests for stranded cost treatment for regulatory assets. Some of these assets may be legitimate stranded costs. Other regulatory assets are not stranded generation costs because they will disappear or be absorbed in the regulated utility business when generation is deregulated. Other assets may be stranded costs, but similar costs in current rates must be removed to prevent double-recovery of costs and avoid operating subsidies.

 Utilities decommission both fossil and nuclear plants. Nuclear decommissioning is funded in an external trust fund following rules set by the Nuclear Regulatory Commission. Nuclear decommissioning costs are stranded because the bulk of the cost arose when the plant first became radioactive.

 Fossil decommissioning is more complex. If a powerplant is sold, the new owner generally takes over the decommissioning obligation and factors it into the price. Therefore, fossil decommissioning is not a separate stranded cost, although it can be a contributing factor that reduces the market price of powerplants.

 If utilities treat fossil decommissioning as a separate stranded cost, regulators must carefully review decommissioning studies. They must also assure that, because ratepayers pay for decommissioning before it occurs, they must receive interest on their money (generally by using payments to reduce rate base).

 Power contracts can create stranded costs if the contract price exceeds the market value of power. The valuation of contracts typically uses a short-run valuation method where the contract is compared to the market value of power on a year-by-year basis. Utilities also have the ability to "buy out" contracts. These payments are also stranded costs if they are less than the original contracts.

 Future operating or capital expenses are definitively not stranded costs unless those costs are absolutely fixed by past contractual commitments.

 In the long run, the market value for a utility plant is compared to the book value to calculate stranded costs. This market value calculation can use either market methods or administrative methods. In between market and administrative valuation is valuation using an appraisal.

Divestiture involves the sale or spin-off of utility generation to a new owner. The market value of generation is determined by the value of that generation to the new owner or the price paid by the new owner to the utility. There are three primary methods for divesting utility generation:

  • spin-down of utility generation assets into a separate affiliate;
  • spin-off to a third party using an arm’s length transaction;
  • auction of utility generation assets;

A spin-down method is a stock transaction between the utility and its existing shareholders. The new generating companies have their own management and boards in place at the time of spin-down. The shares of the utility and the generating companies trade separately.

 The market valuation of generation is the value of the spun-down stock at a later date than the initial spin-down to avoid a "fire sale" valuation plus the value of debt assigned to the generation companies. A spin-down is generally not taxable to either individual shareholders or the corporation.

 A key feature of spin-down is that the utility has very little or no influence over the process by which the market price is set.

A spin-off is a transaction to sell the utility’s generation to a third party. The utility first separates generation into one or more separate companies from distribution. It then makes a transaction with a third party to sell the whole company and its entire generation asset base or, alternatively develops a public offering for the stock that sells off the generation asset base. The value of the generation system is the market value of the stock sale plus the value of debt assigned to the generation company.

The utility may also divest plants through the auction or sale of individual plants to third parties.

 A utility’s assets can be appraised. Appraisal is not divestiture. The utility still owns the generation. The appraisal determines the value of a plant transferred to the generation subsidiary. The difference between the book value and appraised value of the property is the stranded cost.

 The appraisal method requires regulatory intervention. The Commission must review the instructions given to the appraiser. It must review and approve data given to the appraiser on the market value of power and the cost of generating power. A process is needed to obtain additional appraisals if the commission or ratepayer representatives disagree with the results, rather than using one set of numbers created by one party with a vested interest in the outcome.

The administrative method calculates stranded costs based on a forecast of future market prices. Under this method, the value of generation would be:

The major theoretical issue with this method is that spot prices, which clear temporary surpluses, are currently below the cost of new generation. A method that relies on future spot market prices may undervalue generation, because it does not include any capital costs of building generation. Forecasts of future generation are highly uncertain. Finally, this method relies heavily on utility estimates of the future market value. The utility is the most well funded entity with the ability to run sophisticated computer models. This could create bias.

 A market determination of stranded costs is critical in the long run. This market determination is best made by divestiture. The value of a plant or company that is sold is clear in the marketplace. If an administrative method is used, the future market price of electricity will be projected forever, or everyone will be forced to live with one forecast that could be wildly inaccurate. Divestiture also gives a clearer market determination than appraisal. Even a good appraisal, is subject to question, and appraisal requires regulatory scrutiny.

 In a system with large utilities, there is potential to exercise market power in the deregulated bulk generation market. This market power can stifle competition and prevent customers from exercising meaningful choice. Divestiture into several smaller entities can defuse or eliminate market power in the bulk system.

Market power in retail service must also be considered. Without divestiture, a retail utility can favor affiliated generation at the expense of both ratepayers and competitors through cross-subsidies and control over the retail utility’s market resources. Even with direct access, many customers (particularly small customers) will be served at retail by the incumbent utility and the utility will thus be a "dominant carrier" similar to AT&T in long-distance telephone service.

The co-ownership of generation and any other utility function creates possible cross-subsidies between regulated and unregulated entities that must be policed through complex, intrusive regulation. Divestiture removes the need to do this.

Many complex issues must be decided in a restructuring process. Without divestiture, the debate over these issues is likely to be colored by utilities’ jockeying for advantage for their affiliates.

 One of the goals of utility restructuring is to increase use of market forces and limit regulation. Without divestiture, a heavy-handed new regulatory role will be necessary (to prevent cross-subsidies and unfair competition). It is better to set a simple rule in advance -- that a company that transmits or distributes electricity cannot own generation -- than to continually audit utility actions.

Of the three divestiture methods, the spin-down method is likely to yield the most accurate market value. The market valuation of generation can occur later than the initial transaction. The utility has little influence over how the market price is set, and the new owner of the plants receives its revenue from the market price and will close uneconomic generation to maximize shareholder value.

The spin-off and auction methods have significant drawbacks. Both methods can yield overly low values. To give the utility an incentive to negotiate for higher prices and lower stranded cost in a spin-off method, shareholders must pay a large portion of stranded cost.

 Positively, an auction method is likely to assure that ratepayers receive credit for their deferred taxes (see below).

There may be specific problems with spinning down nuclear generation. An auction may be a better way to obtain a financially qualified buyer for nuclear plants. Alternatively, nuclear plants may remain with the utility under tough regulation that encourages their closure if uneconomic.

If a commission gives a utility the choice between divestiture and appraisal for its individual assets (i.e., divesting 50% of assets but letting the utility choose which 50%), the utility can make strategic choices that maximize both stranded costs and shareholder value given its superior knowledge of its own plants. A utility should recover a lower percentage of stranded costs if given this option.

Utilities collect more money from ratepayers than they actually pay in taxes. They collect money based on straight-line depreciation but pay lower taxes using accelerated depreciation. The difference between what ratepayers pay the utility and what the utility pays the government constitutes a "deferred tax" offset, which reduces utility rate base. The total amount nationwide is $40 billion.

If a utility sells a powerplant it must pay income tax based on the difference between its tax basis and sale price. Deferred taxes collected from ratepayers offset some of the taxes, which pays ratepayers back for their deferred taxes.

 However, if a plant is removed from rate base but not kept by the utility, the Edison Electric Institute and some utilities claim that refunding the money that ratepayers previously paid in advance would violate federal tax law.

If the utility is attempting to keep normalized deferred taxes, regulators must be proactive. Incentives that strongly encourage or require the utility to divest, and possibly to sell off its units by auction, are needed to prevent the utility from gaining the benefit of deferred taxes while recovering stranded costs.

 Utilities claim a wide variety of regulatory assets and other costs as part of stranded cost. The key tasks in valuing these assets are:

  • assuring that costs are really stranded costs
  • excluding future "going forward" costs
  • assuring that costs are not double-counted
  • requiring utilities to pay interest on funds they get from ratepayers before they spend the money.

Short-run market determination is used for power contracts and as an interim measure to develop prices paid for utility power before divestiture. For short-run determination, on a year by year basis, the market price is the PJM pool price. The market price should be trued up to the actual price to prevent gaming and controversy about forecasts. If the pool rules contain an implicit or explicit price for capacity, the capacity value should be assigned to all generation up to the utility’s required reserve margin to determine the market value.

 Utility shareholders should not expect that they will receive 100% of stranded costs, based on several court cases. The most recent is Barasch v. Duquesne Light, a case argued by the Pennsylvania Consumer Advocate in the late 1980s.

 Utilities receive a return on equity above the cost of less risky investments like bonds. This premium compensates shareholders for taking risks. One of these risks is that utility generation may become uneconomic. Utilities have been earning high returns for over a decade. On the whole, utility stock has been selling above book value since the mid 1980s. It is time to face some of the risk arising from the poor economics of utility generation.

The utility has no incentive to efficiently mitigate stranded costs if it is guaranteed to collect all of them. There is no incentive to bargain down fuel or power contracts, to improve the plant efficiency, or to cut capital spending, and a strong incentive for the utility to request operating subsidies, if ratepayers pay all of its stranded costs.

 A utility that does not fully divest should recover a lower percentage of stranded cost from ratepayers, because a utility that does not divest is likely to claim higher stranded costs than one that divests. A non-divesting utility can set the agenda under administrative determination or the appraisal method by making initial filings quantifying its stranded costs.

 Typical transition cost recovery plans have accelerated depreciation of stranded costs that the utility is allowed to recover. By the end of the period, assets will reach market value (whether by divestiture, appraisal, or administratively), and the portion of costs above market value assigned to ratepayers will be recovered. In previous cases, acceleration has been combined with a rate freeze, so that rates are not actually raised. The California restructuring adopted a five-year rate freeze. If transition costs are not recovered within five years, they cannot be collected (except purchased power contracts and a few other items). Utilities have an opportunity, not a guarantee, to recover transition costs. Pennsylvania legislation allows a nine-year time horizon. In general, the shorter the period of transition cost recovery (with a rate freeze), the better off ratepayers will be.

Securitization of transition costs through bonds is proposed to obtain a lower cost of capital. Utilities are financed with about 50% debt and 50% equity. A utility’s rate of return is about 9.5% before tax and slightly over 13% after income tax on the equity return. By comparison, the cost of securitized bonds is about 7%. No equity return and no income taxes are paid.

 There are also potential savings from spreading the financing out over a longer time period. A relatively high cost with accelerated depreciation in five years may be cheaper when spread over 10 years using securitized financing. However, securitization can reduce the deferred tax offset to rate base.

 Savings are utility-specific, but, on a present value basis, are about 20% of the amount financed (i.e., $200 million per billion financed). Part of the savings comes from reducing income tax, part from the lower rate of return, and part from stretching out the term of financing.

 It is important to have flexibility in financing, including varying terms of debt (to retire bonds as principal is paid off), and call provisions (in case actual stranded costs end up below forecast costs so that bonds can be paid off early).

No one has used securitization for stranded cost financing yet. As a result, there are still significant unanswered questions regarding design and implementation.

 Securitization of stranded costs is not a substitute for the Commission’s judgment as to what stranded costs are valid and the percentage assigned to ratepayers.

 The evaluation of most utilities’ stranded costs is likely to be larger than any other rate case ever held for this utility, either past or future. Getting stranded costs right, conceptually and quantitatively is extremely important in determining whether ratepayers will benefit from a restructured future.

Stranded costs can be defined as the costs that the utility is obligated to pay for existing generation in excess of the market value of that generation.

 Transition costs are the portion of stranded costs that are to be paid by consumers.

For utility owned powerplants, stranded cost equals the difference between the net book value of the plant plus all other regulatory assets and liabilities and other obligations associated with the plant’s past operation (deferred taxes, post-retirement benefits other than pensions, etc.) and the market value of the plant. The market value of a plant cannot be less than zero, because the plant’s owner could close it down and mitigate that cost.

 Other items, such as inventories may either be sold with their associated powerplant or have an independent market value. The market value of inventories is relatively close to the book value, because fuel and many inventories are fungible and could be sold on the open market (or used up if the plant is going to be closed).

For contracts to purchase power, stranded costs equal the cost of purchased power (demand plus energy costs) minus the market value of that power.

These definitions are important for what is not included as well as what is included. They relate only to sunk costs – costs or obligations that the utility has already incurred.

 Utilities will attempt to define stranded costs very broadly, particularly if they believe that they can recover virtually all of these costs from ratepayers. If the utility can recover 100% of stranded costs from ratepayers, it is likely to ask for more. Higher stranded costs mean that utility investment is less risky and the competitive position of the utility powerplant is improved, because a large block of its costs is not collected in the marketplace.

Future costs for fuel, operation and maintenance and capital additions are not part of stranded costs. To the extent that a utility attempts to recover future costs as part of stranded costs, it is receiving an operating subsidy, with serious implications for market competitiveness discussed below. Existing generation must be required to earn the money to pay for these "going forward" costs from the market price, starting immediately at the beginning of the restructuring process with no stranded cost recovery.

In the stranded cost debate, some utilities want to include more than sunk capital costs as part of stranded costs, and attempt to create a new program of operating subsidies for uneconomic utility plants. This has been the case for nuclear power in California, which was granted stranded cost recovery for five to seven years of operating subsidies above 1 cent per kWh to "prepare them for competition."

While the operating subsidy issue arises in the definition and quantification of stranded costs, it has extremely critical implications in the analysis of future market structure and outcomes. Getting this point wrong in the definition of stranded costs is likely to make it impossible for structural reasons to achieve many of the other policy goals of restructuring.

 An operating subsidy arises by definition if a utility is allowed to receive payments for stranded costs in excess of today’s sunk costs of generation. In such an event, a portion of the utility’s cost of doing business is being subsidized through the stranded cost account. Allowing corporate welfare for uneconomic utility generators will have extremely serious consequences for market structure and market outcomes because it creates regulatory-imposed barriers to the ability of competitors to enter the market.

  • Operating subsidies keep plants open that should be closed on the basis of simple economics. The existence of an operating subsidy removes the discipline of the market from the plant operator. Plants with high O&M costs, high capital additions, or expensive new environmental requirements may be kept open because the operator does not have to recover all of its costs from the market. This is a particular problem for nuclear power plants, which have very low fuel costs but relatively high costs of O&M and capital additions.
  • Operating subsidies protect old, inefficient, and dirtier plants from their newer, cleaner, and more efficient competition and drive prices down artificially. Operating subsidies means that old generation can stay in service and be bid at lower prices than justified by their true costs. These subsidies make it harder to bring new generation into service, even if that new generation is cleaner, more efficient, and cheaper.
  • Ratepayers will have to pay artificially high stranded cost payments because of operating subsidies. To the extent that stranded cost payments include operating subsidies, they will be higher than if they do not. Moreover, the ability of subsidized plants to compete at artificially low prices can depress the market price and raise stranded cost payments even further.

In sum, one of the most important activities in the process of defining and quantifying stranded costs is to assure that operating subsidies are not included in stranded costs.

AquaCalc LLC. telephone +1.916.372.0534 e-mail: sales@aquacalc.com

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