THREE FACTORS (em RESTRUCTURING, TECHNOLOGY AND environmental controls (em now create both reason and opportunity for electric utilities to lower their property taxes, which often make up a substantial cost of doing business.

Property tax valuation is fairly straightforward. Most states compute property taxes on fair market value, or what a hypothetical buyer and seller would agree the property is worth, with both parties having knowledge of the relevant facts and neither compelled to buy or sell. Three common approaches are used to estimate fair market value: (1) the income approach, (2) replacement cost less depreciation and obsolescence and (3) the sales comparison approach.

However, changes anticipated in the electric industry will disrupt the traditional connection between property valuation and the utility rate base, the benchmark by which utilities and local governments have calculated property taxes in the past. First, deregulation affects earnings, breaking the traditional ties between rate base and value. Second, advances in gas turbine technology (and greater reliance thereon) will force a re-evaluation of the cost, efficiency and capability of existing plants. Lastly, the prospect of new environmental legislation and regulation, coupled with deregulation, means the end of the captive market (ratepayers) through which to recover any required compliance or abatement costs.

And while these changes promise future adjustments in tax assessments, they also affect investor expectations, and hence value, today. Buyers and sellers look to the future; they discount the present value of assets to reflect expectations. If a utility should wait to act until the expected effects actually occur (i.e., the plant is actually shut down, redispatched or mothballed to reflect costs, markets or rules), then it is fair to say that the utility will have been paying excessive property taxes throughout many of the years preceding the impact.

Eyeing the Future:

Anticipating Changes in Property Value

How will property tax valuation evolve under deregulation, technology advances and new requirements for environmental compliance?

RESTRUCTURING. First, deregulation and rising competition force a re-evaluation of generating assets. In a deregulated market, %n1%n rate base and a permitted rate of return will no longer accurately predict the income a property will earn. Rather, without regulation, a competitive market for electricity will develop, as it developed in the natural gas industry.

In the short term, the marginal operating costs of plants will determine the market price of electricity. In the long term, the total costs of plants with the most efficient technology will determine the market price. Table 1 shows how the revenue and income would differ between a regulated market and a competitive market for a hypothetical nuclear plant and a hypothetical coal-fired plant.

Under regulation, the nuclear facility returns a higher income to investors than the coal-fired plant because of its higher rate base. It also provides higher total revenue to the investor because its higher operating costs and higher yearly depreciation charges are collected in rates.

In a competitive market, total revenue will equal market price multiplied by the total output of the plant. The revenue earned by the two plants will be equal, but their costs will not. Only the coal-fired plant can recover sufficient operating costs to stay in the market and produce electricity. The nuclear plant will shut down. Neither plant recovers its capital cost; even the coal plant may close when another substantial capital improvement must be made to keep the plant operational. Remember: Investors will value property according to the prospective income stream, so that if investors expect a shutdown in the future, today's fair market value will reflect that expectation.

TECHNOLOGY. Several factors, including (a) lower natural gas prices, from deregulation and pipeline open access, (b) the rise of small power producers, as encouraged by the Public Utility Regulatory Policies Act, and (c) legislative reform, such as repeal of provisions in the Power Plant and Industrial Fuel Use Act of 1978, which prohibited utilities from building gas-fired generators, have each encouraged power producers to turn to new technology (em in the form of gas combustion turbines.

Vendors have responded by increasing efficiencies of combined-cycle natural gas turbine power plants, with heat rates as low as 5950 for an "F" class turbine with triple pressure and reheat. The new G-series gas turbine, now under development, is expected to reach 5860 Btu/kWh under the same conditions.

Capital costs for combined-cycle gas turbine plants are lower than both coal or nuclear plants; $450-$500 per kilowatt-hour for a 120-megawatt facility and $340 per kWh for a 500-MW facility. A combined-cycle gas turbine usually requires a construction lead time of less than two years, compared with eight to 10 years for base-load coal plants leading to lower financing costs. And these plants can start quickly, change load rapidly and shut down immediately. %n2%n Finally, these units produce minimal nitrogen-oxide and carbon-monoxide emissions and no sulfur-dioxide. Pollution abatement costs are generally lower than for coal-fired steam plants.

ENVIRONMENTAL COMPLIANCE. In a competitive market, the cost of environmental compliance will decrease income, as it can no longer be included in rate base or regulated cost of service. Property values will fall. Prospective investors in a power plant will recognize environmental changes that may affect the profitability of their investment. A program with capped emissions and tradeable allowances has already been attached to the restructuring bill introduced by Sen. Dale Bumpers (D-Ark.) and likely will be added to others. Under the plan, the FERC would set caps for each pollutant. High-polluting generators would have a choice of installing new pollution control technologies or buying emissions allowance credits from cleaner generators. %n3%n

The EPA is working on regulations to reduce nitrogen-oxide emissions which appear to target utilities. There is a related risk that the Clean Air Act provisions that allow grandfathering of certain coal-fired power plants would be repealed, again inhibiting the ability of coal-fired plants to compete. %n4%n This repeal will prove more likely if Congress approves the CO2 limitations in the Kyoto Treaty. But the treaty likely will not be sent to the Senate for ratification before the November elections and many senators have already called it dead on arrival. %n5%n Moreover, by 2000 many additional plants will be subject to SO2 limitations under the Clean Air Act.

While some costs of these future environmental requirements may today be too uncertain to be recognized as significant value-diminishers, the effect on plant value can occur almost overnight. Once legislation or regulations are imminent, fair market value is affected because investors look to the future. By the time a compliance date arrives, it may be too late to obtain all of the possible tax savings.

Updating the Present:

Incorporating Future Changes in Plant Valuation

Depending upon state law, state assessors value property either at the "unit" level or locally on a location-by-location basis. In a unit assessment, all utility property (em generation, distribution and transmission (em is valued as a whole and then its value is allocated to the taxing jurisdiction. In a local assessment, each piece of property, which could be transmission wires, poles and substations, or a single generating plant, is valued by a local assessor in a town, city or county.

The actual valuation (em whether by income, cost or comparable sales (em can best be understood assuming a local assessment of each piece of property.

INCOME APPROACH. This method assumes that property is worth the present value of the income stream it can generate. Under traditional regulation, utilities project future income based upon rate of return on rate base, discounted by the market cost of capital. If market cost of capital approximates the allowed (and assumed achieved) rate of return, the income indicator will approximate the rate base.

Under deregulation, however, an appraiser must estimate prospective income a utility's generating plant is expected to earn based on a reasonable projection of electricity market prices and how they will affect the plant's dispatch. Operating costs, such as fuel prices, also are projected and discounted to present value. To make these projections, an appraiser can commission studies from energy and economic forecasting firms specifically for the plant at issue or use reports from the Energy Information Administration or the Gas Research Institute, which provide a more global perspective.

Moreover, the utility probably can use price projections it has used to conduct studies of stranded cost recovery. These studies typically provide the portion of net book cost the utility likely would not recover, and by extension, what an investor likely would not purchase. If the assessment is based on net book value, such studies will prove useful to benchmark property values. Depending upon the quality of the study, it may be combined with competent appraisal evidence and used to prove a value reduction in court.

A truncated projection is also possible with an income based on a rate base multiplied by permitted rate of return for several years, converting to a market-price income projection for those portions of the load that will be sold in competitive markets. If the plant is already producing primarily for a wholesale market, arguably competitive prices should be projected from today forward.

State law would have to be examined, however, to determine if using an income stream based on rate base or including stranded cost recovery allowances would improperly set the value of the property based on the owner's use rather than its fair market value or by valuing intangible assets. Fair market value is based on hypothetical buyers and sellers in the marketplace. If the only buyers would be independent power producers, their purchase price would be based only on the value of the tangible assets. Only the utility (em not an independent power producer (em would have the ability to collect both income from rate base or stranded costs. This situation may be analogous to the homeowner installing an expensive swimming pool; the home's value-in-use to the owner has risen but its market value may have fallen. There is a related issue for non-utility generators.

Under most state laws, prices from above-market power purchase agreements should not be used to project income, since doing so will value the non-taxable intangible contract rights rather than the tangible property comprising the power plant.

REPLACEMENT COST LESS DEPRECIATION. Generally speaking, an investor will not pay more for an old plant than what it would cost to build or purchase a substitute plant with equal operating characteristics. That idea underlies this approach, which will set the upper limit on the value of the plant: Even if the plant can make substantial profits at the market price of electricity, an investor will not pay a price based on its discounted income stream if the investor can purchase and operate a brand new plant for less.

Historically, under traditional regulation, net book cost or rate base has approximated the correct cost indicator for utility property, because it incorporates the physical deterioration and elements of functional obsolescence recognized by yearly depreciation rates allowed by the regulatory agency, and the external obsolescence caused by limiting the property's earning ability to a return on its net book cost. Deregulation requires different adjustments, however. (See Table 2, giving an example of using replacement cost less depreciation and obsolescence to calculate property tax value for a coal-fired steam generating plant.)

First, the appraiser calculates the capital cost per kilowatt-hour of producing the equivalent amount of electricity. This step can be done through industry publications, vendor proposals, or more appropriately, by an independent engineering firm. The capital cost should be increased by startup costs, necessary spare parts, and interest expense during the construction period, among other factors. From this cost for a new plant must be deducted an amount appropriate for the physical deterioration suffered by the appraised plant. This step can be performed by comparing the useful life of the new facility to the useful life of the appraised plant.

Next, fuel costs are compared. If the appraised plant is oil- or gas-fired, then the replacement gas plant's lower heat rate and lower overall fuel costs will be reflected by a reduction in value of the appraised plant. If the appraised plant is nuclear or coal-fired, an addition of value of the appraised plant (relative to the replacement plant) likely will be required, because coal costs less than natural gas per megawatt-hour of electricity produced. Nuclear fuel costs less as well, but that advantage likely disappears if one considers nuclear fuel disposal costs.

Similarly, compare all other fixed and variable operating costs per kilowatt of capacity, reducing (or increasing) the value of the appraised plant, depending upon whether the replacement facility shows a cost advantage or disadvantage. All future yearly cost estimates must be discounted to present value to reflect the total cost comparison as of the appraisal date.

Finally, an additional deduction in value may be appropriate for economic or external obsolescence. The appraiser must determine if the projections of the market price of electricity would allow the purchaser to recover all costs. If there is excess capacity in the market, so that competing plants in the market area of the appraised subject are likely to sell electricity priced at marginal cost (i.e., electricity priced so low it does not recover capital costs), it is likely the replacement facility also could not recover its capital costs. These unrecovered costs warrant a deduction. In the long run, however, the market price of electricity should be high enough to allow recovery of both capital and operating costs of the most efficient operating units as marginal plants exit the market.

COMPARABLE SALES. The third method, the sales comparison approach to value, considers actual market sales prices of comparable properties. Most often used for residential real estate, the comparable sales approach may have limits in the case of electric generating plants. In a fully regulated environment, those few power plant sales that would occur would likely send the plant to another utility; absent any strategic purposes peculiar to a particular buyer, there would be no reason to pay more than rate base.

Under deregulation, however, the appraiser should investigate market sales of power plants comparable to the appraised plant. In fact, with disaggregation and competition, such sales are occurring more frequently. But such sales are likely to include the prices for power purchase agreements, stranded cost recovery rights, other intangible contract rights, indemnification for various liabilities such as nuclear fuel disposal costs, other environmental liabilities, and other assets or costs not directly related to the tangible or taxable property. Rather, it is quite possible that the value of just the taxable tangible assets can be determined reliably only by the cost or income methods. %n6%n

UNIT-VALUE CONSIDERATIONS. For the utilities in the approximately 36 states that have their property valued by the unit method, the above techniques are also applicable.

The unit should be broken into those components that are likely to remain rate-base regulated such as transmission and distribution, with those assets being valued through traditional unit value techniques. Next, the assets that are likely not to be subject to rate base regulation will have to be identified, most likely the generating assets. A determination will have to be made about when they will be severed from the unit, or at least, no longer be allowed to earn an income based on rate base times a permitted rate of return. After that date, the above local valuation techniques will have to be applied.

The overall value for the unit will be a combination of the values of the assets that will remain regulated combined with the value of soon-to-be deregulated assets. The value of those deregulated assets will be a combination of their value in a regulated market for several years and their remaining value in a competitive market.

Steven P. Schneider is a tax and regulatory law litigator with the law firm of Honigman, Miller, Schwartz and Cohn in Detroit. The author thanks John C. Goodman, senior vice president in the Valuation Group of AUS Consultants for his contributions to this article.

1 See Lori M. Rodgers, "Kilowatts by Choice, Ready or Not," Public Utilities Fortnightly, Nov. 1, 1997, p. 42, for a list of Internet sites of groups providing state-by-state updates on retail open access plans.

2 Gas turbine cost and performance characteristics are improving rapidly. Some of the data in the current sources listed below could be obsolete: GRI, Gas IRP Review, June 1996; Michael Brower and Brian Parsons, "Can Renewable Energy Reduce Fuel Risk?" Public Utilities Fortnightly, May 1, 1997, p. 32; GRI, Successful Use of Natural Gas in Electric Generation, GRI-96/0272, October 1996; J. Alan Beamon and Steven H. Wade, "Energy Equipment Choices: Fuel Costs and Other Determinants," Energy Information Administration's Monthly Energy Review, April 1996; Paul Bautista, "Rise in Gas-Fired Power Generation Tracks Gains in Turbine Efficiency, Oil & Gas Journal, Aug. 12, 1996; GRI, Scenarios of Restructuring in The U. S. Power Industry: Implications for Natural Gas, gri-96/0003, November 1995; GRI and Electric Power Research Institute, Pipelines to Power Lines: Gas Transportation for Electricity Generation, GRI 5093-810-2575, January 1995; R. Utter, H. Termuehlen, H.-O. Rohwer, H. Brücker, Combined Cycle Power Plant Genelba in Argentina, paper presented at Power-Gen '96 International Conference, Orlando, Fla., Dec. 4-6, 1996.

3 See the summary of this legislation in Inside FERC, Nov. 10, 1997.

4 See "NOx Joke: EPA Proposal Has IOUs Fuming," Public Utilities Fortnightly, Nov. 15, 1997, p. 62.

5 "Kyoto Aftermath: Big Battles Still Ahead as U.S. Holds Treaty Key," Oil & Gas Journal, Dec. 22, 1997.

6 One of the states essentially recognizing an exception to the fair market value standard is New York. In a landmark case the state's highest court reasoned, in part, that because there was no "market" for the locally assessed portion of a gas system (i.e. the sales comparison or market approach was inapplicable), it would value property solely by looking at its reproduction cost with some very limited obsolescence deductions. It refused to apply an income approach or recognize earnings limitations from regulation in the cost approach. See Brooklyn Union Gas Co. v. State Bd. of Equalization, 492 N.Y.S.2d 598 (1985). The decision has been extended to electric utility property. However, as there is more evidence of power plants selling in competitive markets the rationale of this decision is weakened and it may be subject to challenge.

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