CRS REPORT EXAMINES TAX IMPLICATIONS OF SULFUR DIOXIDE ALLOWANCE TRADING.

                IMPLEMENTING SULFUR DIOXIDE ALLOWANCE

Preliminary analysis by EPA indicates that the implementation cost of the new system could be between 15 and 25 percent of the total cost of the program. The primary implementation expense for participants in the program is for emission monitoring, along with anticipated transaction costs involved in trading allowances. In terms of the tax implications, IRS interpretation of the tax rules does not result in additional imposed cost on the allowance trading system, except for a fairly minor effect which may result from the treatment of potential capital losses on purchased allowances for future sale.

                              CONTENTS

A substantial regulatory structure is necessary for the new allowance trading program under title IV of the CAAA to function properly. Regulations are required to define the playing field and rules for participants and referees. Under title IV, EPA is required to issue regulations with respect to the following aspects of the allowance system:

o Rules with respect to the allocation, transfer, and use of allowances;

o Rules establishing a system to issue allowances and to record and track allowance transactions;

o Rules establishing an acid rain permit program;

o Rules specifying the requirements for monitoring systems, including recordkeeping and report requirements; and

o Rules specifying various special allowance funds and allocation schemes.

These rules involve costs both to the participants in the allowance system and to the government (including State and national entities). With the release of the Environmental Protection Agency's (EPA) regulatory impact statement (RIA) ¹ and the Internal Revenue Service (IRS) allowance guidance document, the magnitude of some of these costs is becoming more clear. This report reviews the estimated implementation costs of the trading program with specific attention on its two primary components: (1) monitoring costs, (2) potential transaction costs. In addition, the potential tax implications of trading allowances are also identified and discussed.

ESTIMATED COSTS: 1993-2010

The costs of the acid rain control annualized over the eighteen year period 1993-2010 are presented in Figure 1. Because the costs are annualized over eighteen years, the figures presented generally overestimate the costs during the early years of the program (Phase 1) and underestimate the costs in the out years. Because the focus of this section is on the relative burden of implementation costs over time, annualized costs are the appropriate measure, not specific costs in any one year. As indicated, the implementing cost of Title IV could run between 15 and 25 percent of the total cost of the program. Although the combined reduction implementation costs are substantially below the cost of the reductions without any market- based or flexible implementation scheme, they are significant nonetheless.

The major implementation costs for the control program are the monitoring (i.e., CEM) costs, with additional transaction and tracking costs possible (particularly if commission rates are higher than the RIA assumes). Each of these will be discussed in more detail.

            FIGURE 1: IMPLEMENTATION COSTS BY COST CATEGORY

  FIGURE 2: TOTAL ANNUALIZED ADMINISTRATIVE COSTS FOR PERMIT PROGRAM

Monitoring costs dominate potential implementation costs as identified by EPA. Although considerably smaller, additional costs are incurred with potential transaction expenses associated with allowance trading.

MONITORING (CEM) COSTS

Accurate monitoring of sulfur dioxide emissions by affected powerplant units is the linchpin of the allowance system. For a marketplace in allowances to develop, the participants must not be permitted to make "paper" trades or otherwise "cheat" on the need for allowances. ³ To encourage accurate data collection by utilities, the legislation requires that if a utility's monitoring equipment were not operating properly, the EPA is to calculate the facility's emission as if the facility were operating in an "uncontrolled" manner. The final rule on monitoring is a stringent regulation requiring Continuous Emission Monitors (CEM) on all large facilities affected by the program.

Under the CAAA of 1990, utilities are specifically required to install a sulfur dioxide CEM, a nitrogen oxide CEM, a continuous opacity monitor (COM) and a volumetric flow monitor. Figure 3 below presents an industry average cost estimate for a CEM that meets the requirements of EPA's rule. For an average utility, the costs of CEMS is relatively modest, particularly in comparison with the estimated costs of reducing Sulfur dioxide emissions. However, as the monitoring requirement covers over 2,000 units, the aggregate costs are significant (as presented in figure 1). ⁴

   FIGURE 3: CAPITAL AND O & M COST ESTIMATES FOR MONITORING SYSTEMS

The capital costs involved in CEM are incurred relatively early in the program with Phase 1 units required to have operational CEM by 1995 and Phase 2 units required to have operational CEM by 2000.

TRANSACTION COSTS

In terms of implementing the allowance system, transaction costs present the greatest uncertainty. Several variables are involved, including numbers of participants, volume of sales, numbers of transactions, and number and competitiveness of brokers and the services they provide (i.e., a discount or full-service broker). ICF's analysis assumes allowance transactions worth between $1 billion and $2 billion annually. ⁵ Thus, a commission of 1.5% results in aggregate annual costs of between $15 and $30 million while a commission of 6.0% results in aggregate annual costs of between $60 and $120 million. As noted by ICF, these commission rates would represent averages with small, service-intensive trades requiring fairly large commissions and larger, bulk sales requiring smaller commissions.

However, ICF notes, but does not analyze, the interactive effects of commission rates on trading volume, suggesting that transaction volumes would probably be closer to the lower end of the range if commissions were 3-10 percent instead of 1.5 percent. The actual degree to which commissions would affect transaction volumes depends on profitability of the trade to begin with. A larger commission would tend to eliminate marginal trades and to reduce trades made for inventory purposes. In this sense, commission charges may cause utilities to explore other compliance options or to wait to get a better idea of their allowance needs.

TAX IMPLICATIONS FOR ALLOWANCE TRADING

The tax treatment of emission allowances has few special implications for the operation of the allowance trading program. Special implications would develop only if the tax code treated allowances in a manner that was inconsistent with their economic character, which, for the most part, is not the case.

Under a net income tax, income is subject to taxation and the cost of earning the income is deductible. Hence, the cost of allowances used by a utility in connection with the generation of electricity sold during a year should be deductible in that year. If allowances are sold, the sales proceeds minus the cost of the allowances should be taxable.

Because emission allowances are rather unique, their treatment under some provisions of the tax code was uncertain until general guidance was provided by the Internal Revenue Service (IRS) in late 1992. ⁶ Under the IRS interpretation of the tax rules, receipt of allowances by a utility under the EPA allocation process will not be regarded as receipt of taxable income. Generally, emission allowances will be treated as capital assets of utilities under the tax rules. The costs of acquiring and holding the allowances, including any amount paid to purchase them or legal or accounting fees, must be capitalized. The costs cannot be depreciated or otherwise deducted prior to the time the allowances are used. The costs constitute the utility's tax "basis" in the allowances. Generally, a utility will be allowed to deduct the basis of allowances used to offset emissions during a year. If allowances are sold or exchanged, the proceeds minus the basis of the allowances will be treated as a capital gain or loss. ⁷ Under the current tax code, capital gains are taxed the same as other income (for corporations). Capital losses, however, may be deducted only against capital gains; capital losses which cannot be used in the current year may be carried back three years and forward five years to offset capital gains in those years. ⁸

In the typical case of a utility receiving an allowance from the EPA and using it to offset emissions during a year, there will be little or no tax consequence. The allowance will have no effect on the utility's tax status when it is received; it will have zero basis so when it is used it will not result in a deduction. ⁹ If a utility sells an allowance received from the EPA, the proceeds will be taxable, and, since the basis of the allowance will be zero, there will be no deduction to offset the income. For utilities which overcontrol to generate extra allowances for sale, the situation will be the same. The cost of the overcontrol investment will not become the basis of the allowances. The cost of the investment in pollution control equipment (or fuel switching equipment, etc.) will be capitalized and depreciated just as in the past. The extra allowances received from EPA will still have zero basis, so the proceeds of their sale will be fully taxable.

If a utility purchases allowances, the purchase price (plus any other costs such as brokerage fees associated with the purchase) will be the basis of the allowances. When the allowances are used, a tax deduction can be taken for their basis. If purchased allowances are later sold, the proceeds minus the basis will be a capital gain or capital loss.

The relevant issue for the purpose of this report is whether this tax treatment increases the cost of the allowance trading program. The answer is that, for the most part, it does not.

In thinking about the effects of taxation, it is helpful to realize that the cost effects that would result from taxation are different from the other kinds of costs identified in this report. The other cost -- for example, transactions costs or monitoring cost -- are costs IN ADDITION TO the costs of purchasing and accounting for emission allowances. If the tax system imposes costs, however, they would be reflected IN THE PRICE of emission allowances. If there is no effect on the price of allowances, then the only effect of the tax system would be to reduce the profit from the sale of allowances, profit that would not exist in the absence of the allowance trading system (hence, its taxation cannot be regarded as an extra cost).

The tax system should have no effect on the use of allowances received from EPA to offset emissions since this use has no tax consequence. Taxation also should have no effect on the sale of allowances received from EPA which do not result from overcontrol investments. In this case, taxation would reduce the profit received by the seller, but it should not affect the market price of the allowances since no investment decision is involved.

There would be an effect on the sales price of allowances resulting from overcontrol investments, since such investments will have to earn a pre-tax rate of return sufficient to provide a market rate of return after-tax. The same is true for allowances that would be held for sale in the future. But in an economy with an income tax, all investments must earn a higher pre-tax rate of return, so this effect should not be regarded as an extra cost associated with the tax treatment of any particular item.

There should be no tax effect on the purchase of allowances for use in offsetting emissions since the purchase cost is deductible at the time the allowance is used. The one transaction that would be affected by the tax code is purchase of allowances to hold for future sale. The limitation on deduction of capital losses increases the risk associated with this transaction. Gain from speculation in allowances would be taxable, but losses would be deductible only to the extent of gains that could be offset. This limitation could result in somewhat fewer allowances being held for sale in future years and, as a consequence, somewhat higher allowance prices in future years. If so, the higher future cost of purchased allowances would be legitimately regarded as an additional cost imposed on the allowance trading system by the tax treatment. This effect would be expected to be small, however, since it involves only allowances which are purchased for future sale, but not those received directly from the EPA and held for future sale (these would have zero basis, so they would not result in capital losses).

With this fairly minor exception regarding capital losses on purchased allowances held for future sale, the tax system does not impose additional costs on the allowance trading system.

² The EPA estimate is for the years 2000-2010, the most expensive years for EPA.

³ A paper trade would involve a situation where emissions reductions claimed to have occurred according to monitoring or accounting data (and then traded) did not actually occur because of manipulation of baseline or monitoring data. The less stringent the monitoring requirements are the more possible this situation becomes.

⁴ It should be noted that separate CEMs will not be necessary for every unit as the exhaust gases of some are fed into common stacks.

⁵ Based on model results for interstate trades, scaled up to account for intrastate trades.

⁶ Treatment of emission allowances under the Federal income tax is spelled out in Rev. Rul. 92-16, Internal Revenue bulletin, No. 1992-12, March 23, 1992, p. 5 and Rev. Proc. 92-91, Internal Revenue bulletin, No. 1992-46, November 16, 1992, pp. 32-33. See also, Announcement 92-50, Internal Revenue bulletin, No. 1992-13, March 30, 1992, p. 32.

⁷ If emission allowances are exchanged for other emission allowances, the transaction will qualify as a like-kind exchange under section 1031 of the Internal Revenue Code and gain will not be recognized (assuming all the requirements of section 1031 are met).

⁸ If a capital loss cannot be used in any of the carryover years, it vanishes.

⁹ An exception is that some legal or accounting fees may be ascribed to the allowance, included in its basis, and deducted when the allowance is used.